2004 Annual Reports

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

Southwestern Electric Power Company

Audited Financial Statements and

Management’s Financial Discussion and Analysis

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO ANNUAL REPORTS

Glossary of Terms
Forward-Looking Information
AEP Common Stock and Dividend Information
American Electric Power Company, Inc. and Subsidiary Companies:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis of Results of Operations
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Report of Independent Registered Public Accounting Firm
	Management’s Assertion
	Consolidated Financial Statements
	Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
	Schedule of Consolidated Long-term Debt
	Index to Notes to Consolidated Financial Statements
AEP Generating Company:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Financial Statements
	Schedule of Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
AEP Texas Central Company and Subsidiary:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
AEP Texas North Company:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Financial Statements
	Schedule of Preferred Stock
	Schedule of Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Appalachian Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Columbus Southern Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Indiana Michigan Power Company and Subsidiaries:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Kentucky Power Company:
	Selected Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Financial Statements
	Schedule of Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Ohio Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Public Service Company of Oklahoma:
	Selected Consolidated Financial Data
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
Southwestern Electric Power Company Consolidated:
	Selected Consolidated Financial Data
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Consolidated Financial Statements
	Schedule of Preferred Stock
	Schedule of Consolidated Long-term Debt
	Index to Notes to Financial Statements of Registrant Subsidiaries
	Report of Independent Registered Public Accounting Firm
	Notes to Financial Statements of Registrant Subsidiaries
	Combined Management’s Discussion and Analysis of Registrant Subsidiaries

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 electric utility subsidiary of AEP.
AEP or Parent	American Electric Power Company, Inc.
AEP Consolidated	AEP and its majority-owned consolidated subsidiaries and consolidated affiliates.
AEP Credit	AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated domestic electric utility companies.
AEP East companies	APCo, CSPCo, I&M, KPCo and OPCo.
AEPES	AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR	AEP Resources, Inc.
AEP System or the System	The American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEPSC	American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
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.
AEP West companies	PSO, SWEPCo, TCC and TNC.
ALJ	Administrative Law Judge.
APCo	Appalachian Power Company, an AEP electric utility subsidiary.
ARO	Asset Retirement Obligations.
CAA	The Clean Air Act.
CenterPoint	CenterPoint Energy Houston Electric, LLC, Reliant Energy Retail Services, LLC, and Texas Genco LP, all of which are not affiliated with AEP.
Cook Plant	The 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.).
DETM	Duke Energy Trading and Marketing L.L.C., a nonaffiliated risk management counterparty.
DOE	United States Department of Energy.
EITF	The Financial Accounting Standards Board’s Emerging Issues Task Force.
EITF 02-3	Emerging Issues Task Force Issue No. 02-3: Issues Involved in Accounting for Derivative Contracts Held For Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.
ERCOT	The Electric Reliability Council of Texas.
FASB	Financial Accounting Standards Board.
Federal EPA	United States Environmental Protection Agency.
FERC	Federal Energy Regulatory Commission.
FIN 46	FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.”
GAAP	Accounting Principles Generally Accepted in the United States of America.
HPL	Houston Pipeline Company.
I&M	Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPP	Independent Power Producers.
ISO	Independent System Operator.
JMG	JMG Funding LP, a variable interest entity consolidated by OPCo.
KPCo	Kentucky Power Company, an AEP electric utility subsidiary.
KPSC	Kentucky Public Service Commission.
KWH	Kilowatthour.
LIG	Louisiana Intrastate Gas Co., a former AEP subsidiary.
MTM	Mark-to-Market.
MW	Megawatt.
MWH	Megawatthour.
NOx	Nitrogen oxide.
Nonutility Money Pool	AEP System’s Nonutility Money Pool.
NSR	New source review.
NRC	Nuclear Regulatory Commission.
OATT	Open Access Transmission Tariff.
OPCo	Ohio Power Company, an AEP electric utility subsidiary.
Parent	American Electric Power Company, Inc.
PJM	PJM Interconnection, LLC; a regional transmission organization.
PSO	Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB	Price-to-Beat.
PUCT	The Public Utility Commission of Texas.
PUHCA	Public Utility Holding Company Act of 1935, as amended.
PURPA	The Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries	AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
REP	Retail Electric Provider.
Risk Management Contracts	Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges, and nonderivative contracts held for trading purposes.
RTO	Regional Transmission Organization.
S&P	Standard & Poor’s.
SEC	Securities and Exchange Commission.
SFAS	Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.
SFAS 109	Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes.
SFAS 133	Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.
SFAS 143	Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.
SNF	Spent Nuclear Fuel.
SPP	Southwest Power Pool.
STP	South Texas Project Nuclear Generating Plant, owned 25.2% by TCC.
STPNOC	STP Nuclear Operating Company, a nonprofit Texas corporation which operates STP on behalf of its joint owners including TCC.
SWEPCo	Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC	AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor	Maturity of a contract.
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 to be made under the Texas Restructuring Legislation to review and finalize the amount of stranded costs, if applicable, and other true-up items and the recovery of such amounts.
TVA	Tennessee Valley Authority.
Utility Money Pool	AEP System’s Utility Money Pool.
VaR	Value at Risk, a method to quantify risk exposure.
WPCo	Wheeling Power Company, an AEP electric distribution subsidiary.

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.

· The ability to recover regulatory assets and stranded costs in connection with deregulation.

· The ability to recover increases in fuel and other energy costs through regulated or competitive electric 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).

· Oversight and/or investigation of the energy sector or its participants.

· Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp.).

· Our ability to constrain its operation and maintenance costs.

· Our ability to sell assets at acceptable prices and on other acceptable terms, including rights to share in earnings derived from the assets subsequent to their sale.

· The economic climate and growth in our service territory and changes in market demand and demographic patterns.

· Inflationary 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 and number of 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 membership 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 and other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:

Quarter Ended	High		Low		Quarter-End Closing Price		Dividend
December 31, 2004	$	35.53	$	31.25	$	34.34	$	0.35
September 30, 2004		33.21		30.27		31.96		0.35
June 30, 2004		33.58		28.50		32.00		0.35
March 31, 2004		35.10		30.29		32.92		0.35
December 31, 2003		30.59		26.69		30.51		0.35
September 30, 2003		30.00		26.58		30.00		0.35
June 30, 2003		31.51		22.56		29.83		0.35
March 31, 2003		30.63		19.01		22.85		0.60

AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2004, AEP had approximately 130,000 registered shareholders.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

SELECTED CONSOLIDATED FINANCIAL DATA

	2004			2003			2002			2001			2000
OPERATIONS STATEMENTS DATA	(in millions)
Total Revenues	$	14,057		$	14,667		$	13,427		$	12,840		$	10,854
Operating Income		1,991			1,754			1,923			2,310			1,869
Income Before Discontinued Operations,    Extraordinary Items and Cumulative Effect   of Accounting Changes	$	1,127		$	522		$	485		$	960		$	177
Discontinued Operations Income (Loss), Net of Tax		83			(605	)		(654	)		41			134
Extraordinary Losses, Net of Tax		(121	)		-			-			(48	)		(44	)
Cumulative Effect of Accounting Changes Gain (Loss),   Net of Tax		-			193			(350	)		18			-
Net Income (Loss)	$	1,089		$	110		$	(519	)	$	971		$	267
BALANCE SHEET DATA	(in millions)
Property, Plant and Equipment	$	37,286		$	36,021		$	34,127		$	32,993		$	31,472
Accumulated Depreciation and Amortization		14,485			14,004			13,539			12,655			12,398
Net Property, Plant and Equipment	$	22,801		$	22,017		$	20,588		$	20,338		$	19,074
Total Assets	$	34,663		$	36,781		$	35,945		$	40,432		$	47,703
Common Shareholders’ Equity	$	8,515		$	7,874		$	7,064		$	8,229		$	8,054
Cumulative Preferred Stocks of Subsidiaries (a) (d)	$	127		$	137		$	145		$	156		$	161
Trust Preferred Securities (b)	$	-		$	-		$	321		$	321		$	334
Long-term Debt (a) (b)	$	12,287		$	14,101		$	10,190		$	9,409		$	8,980
Obligations Under Capital Leases (a)	$	243		$	182		$	228		$	451		$	614
COMMON STOCK DATA
Earnings (Loss) per Common Share:
Income Before Discontinued Operations, Extraordinary Losses   and Cumulative Effect of Accounting Changes	$	2.85		$	1.35		$	1.46		$	2.98		$	0.55
Discontinued Operations, Net of Tax		0.21			(1.57	)		(1.97	)		0.13			0.42
Extraordinary Losses, Net of Tax		(0.31	)		-			-			(0.16	)		(0.14	)
Cumulative Effect of Accounting Changes, Net of Tax		-			0.51			(1.06	)		0.06			-
Earnings (Loss) Per Share	$	2.75		$	0.29		$	(1.57	)	$	3.01		$	0.83
Average Number of Shares Outstanding (in millions)		396			385			332			322			322
Market Price Range:
High	$	35.53		$	31.51		$	48.80		$	51.20		$	48.94
Low	$	28.50		$	19.01		$	15.10		$	39.25		$	25.94
Year-end Market Price	$	34.34		$	30.51		$	27.33		$	43.53		$	46.50
Cash Dividends Paid per Common Share	$	1.40		$	1.65		$	2.40		$	2.40		$	2.40
Dividend Payout Ratio (c)		50.9	%		569.0	%		(152.9	)%		79.7	%		289.2	%
Book Value per Share	$	21.51		$	19.93		$	20.85		$	25.54		$	25.01

(a)	Including portion due within one year.
(b)	See “Trust Preferred Securities” section of Note 17.
(c)	Based on AEP historical dividend rate.
(d)	Includes Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption which are classified in 2003 as Noncurrent Liabilities and in 2004 as Current Liabilities as the shares were redeemed in January 2005.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

American Electric Power Company, Inc. (AEP) is one of the largest investor-owned electric public utility holding companies in the U.S. Our electric utility operating companies provide generation, transmission and distribution service to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

We have an extensive portfolio of assets including:

· 36,000 megawatts of generating capacity as of December 31, 2004, the largest complement of generation in the U.S., the majority of which has a significant cost advantage in many of our market areas. In 2004, we sold utility generating capacity of 3,800 megawatts located in Texas and approximately 280 megawatts of independent power generation located in Colorado and Florida.

· Approximately 39,000 miles of transmission lines, including the backbone of the electric interconnected grid in the Eastern U.S.

· 177,000 miles of distribution lines that deliver electricity to customers.

· Substantial coal transportation assets (7,065 railcars, 2,230 barges, 53 towboats and one active coal handling terminal with 20 million tons of annual capacity).

· 4,400 miles of gas pipelines in Texas with 118 billion cubic feet of gas storage facilities, which we sold on January 26, 2005.

BUSINESS STRATEGY

Our strategy is to focus on domestic electric utility operations. Our objective is to be an economical, reliable and safe provider of electric energy to the markets that we serve. We will achieve economic advantage by designing, building, improving and operating low cost, environmentally-compliant, efficient sources of power and maximizing the volumes of power delivered from these facilities. We will maintain and enhance our position as a safe and reliable provider of electric energy by making significant investments in environmental and reliability upgrades. We will seek to recover the cost of our new utility investments in a manner that results in reasonable rates for our customers while providing a fair return for our shareholders through a stable stream of cash flows, enabling us to pay dependable, competitive dividends. We will operate our competitive generating assets to maximize our productivity and profitability after meeting our native load requirements.

In summary our business strategy calls for us to:

Operations

· Invest in technology that improves the environment of the communities in which we operate.

· Maximize the value of our transmission assets through membership in PJM, ERCOT, and SPP.

· Continue maintaining and improving the quality of distribution service.

· Optimize generation assets by increasing availability and consequently increasing sales.

Regulation

· Focus on the regulatory process to fully recover our costs and earn a fair return while providing fair and reasonable rates to our customers while fulfilling our commitment to invest in environmental projects at our generating plants.

· Complete the sale of our generation assets in Texas and recover the associated stranded costs in compliance with the law.

Financial

· Operate only those unregulated investments that are consistent with our energy expertise and risk tolerance and that provide reasonable prospects for a fair return and moderate growth.

· Continue to improve credit quality and maintain acceptable levels of liquidity.

· Achieve moderate but steady growth.

EXECUTIVE OVERVIEW

Utility Operations

Our Utility Operations, the core of our business, had a year of continued improvement despite some unfavorable operating conditions. Our results for the year reflect the increased demand from our industrial customers and sales growth in the residential and commercial classes. These are solid indicators that the economic recovery is reaching all sectors. We also realized a positive earnings impact due to a favorable court decision in Texas, which allows us to recover carrying costs for stranded costs in Texas. However, these favorable results were not sufficient to offset the absence of the wholesale capacity auction true-up revenues in 2004 and higher planned plant maintenance and distribution system reliability improvement work. Additionally, unfavorable weather due to a mild summer in 2004 lowered our revenues below expected norms and a significant late-December ice storm in parts of our eastern territory increased our storm damage repair operations and maintenance expenses.

In May 2004, we announced the reorganization of our distribution and customer service operations into seven regional utility divisions, placing operational authority into the hands of division presidents and their support staffs. With this new structure, we have created stronger utilities by moving the decision-making closer to the customer and other external stakeholders.

On October 1, 2004, we integrated our east region transmission and generation operations, commercial processes and data systems into those of PJM. While we continue to own our transmission assets, use our low-cost generation fleet to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in this new environment. We are confident in our ability to participate successfully in the PJM market.

During 2004, we further stabilized our financial strength by:

· Completing significant asset divestitures resulting in proceeds of approximately $1.4 billion.

· Using the cash flows from our asset divestitures to reduce outstanding debt, resulting in an improved debt to capital ratio of 59.1% at December 31, 2004.

· Stabilizing our credit ratings as indicated by Moody’s change in outlook from ‘stable’ to ‘positive’ in August 2004.

While we were extremely successful during 2004 in reducing our outstanding debt and the related debt to total capital ratio from 64.6% to 59.1%, we have significant capital expenditures projected for the near-term. Through a combination of cash generated from operations and proceeds from our asset dispositions we expect to maintain the strength of our balance sheet and fund our capital expenditure program.After the completion of our remaining planned divestitures and after the results of our Texas true-up proceedings are finalized, we hope to recommend to the board gradual, sustainable increases to our current 35 cent per share quarterly common stock dividend.

Regulatory Matters

Ohio Rate Stabilization Plan

CSPCo and OPCo filed their rate stabilization plans on February 9, 2004 at the request of the Public Utility Commission of Ohio (PUCO) and the plans were approved, subject to rehearing, on January 26, 2005, with certain modifications. The plans are intended to provide rate stability, facilitate a competitive retail market, and provide for recovery of future environmental expenditures.

The approved plans include fixed annual percentage increases in the generation component of all customers' bills of 3% for CSPCo and 7% for OPCo in 2006, 2007 and 2008, along with the opportunity for additional generation-related increases upon PUCO review and approval. Additional generation-related increases averaging up to 4% per year for each company above the fixed annual percentage increases under the plans are possible. Distribution rates will remain fixed at the December 31, 2005 level through 2008 but could be adjusted for specified reasons with PUCO approval. Transmission rates will be adjusted based on FERC-approved OATT tariffs. We believe that these plans will favorably affect customers, shareholders and other stakeholders.

Texas Stranded Cost and Related Carrying Cost Recovery

The stranded cost recovery process in Texas continues to be very intense and time-consuming. The ultimate recovery of these assets is somewhat clearer given the recent CenterPoint decision; however, we anticipate a contentious stranded cost True-up Proceeding for TCC. The principal component of the process is the determination of TCC’s net stranded generation costs regulatory asset. Other net true-up regulatory assets will also need to be recovered through customer transition charges. Although we believe that these assets are recoverable under the Texas restructuring legislation, we anticipate that other parties will contend that material amounts of stranded costs should not be recovered. TCC will seek to recover in its True-up Proceeding an amount in excess of the $1.6 billion recorded net true-up regulatory asset through December 31, 2004.

When the True-up Proceeding is completed, TCC intends to file to recover PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying charges, through a nonbypassable competition transition charge in the regulated T&D rates, and through an additional transition charge for amounts that can be recovered through securitization. We cannot predict whether our full net stranded cost and other true-up regulatory assets will be approved for recovery.

TCC Rate Case

TCC has a base rate filing for its Texas wires business pending before the PUCT in which it is requesting an adjusted $41 million rate increase. A reduction in existing rates of between $48 million and $75 million is possible depending on the final treatment of affiliated transactions. Based on preliminary decisions of the PUCT, it appears that the best result we can expect is a $6 million rate increase. The PUCT order, when issued, will affect revenues prospectively.

PSO Rate Review

In February 2003, the Corporation Commission of the State of Oklahoma (OCC) filed an application requiring PSO to file all documents necessary for a general rate review. Intervenors and OCC Staff filed testimony recommending a decrease in annual existing rates of between $15 million and $36 million. PSO’s current testimony supports a revenue deficiency of $28 million. As a consequence of this case, PSO also asserts that approximately $9 million of additional costs should be recovered through the fuel adjustment clause. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

Environmental Stewardship

In August 2004, a subcommittee of the Policy Committee of our Board of Directors prepared a report in response to a shareholder proposal entitled, “An Assessment of AEP’s Actions to Mitigate the Economic Impacts of Emissions Policies.” This report summarized assessed the actions that we are taking to mitigate the economic impact of increasing regulatory requirements, competitive pressures, and public expectations to significantly reduce carbon dioxide and other emissions. The comprehensive report made the following recommendations for managing the current challenge we face:

· Design of control regimes - engage in persuasive, proactive advocacy of positive policy positions that ensure the rules governing such programs will operate in a transparent, fair and cost-effective manner.

· Technology leadership - preserve our ability to utilize coal economically while meeting increasingly stringent emission control requirements.

· Excellence in plant operations - consistently operate emission-controlled plants at high capacity factors.

· Sophisticated decision-making tools - engage in complex decision-making processes to identify the mix of options that will minimize the cost to the consumer while at the same time factoring in the uncertainty inherent in the regulatory process.

· Transparency - make actions transparent and understandable to shareholders, customers and stakeholders.

· Partnerships - continue to seek out partners as we work out options to control greenhouse gas and other emissions.

The report concluded that the actions we have taken are a solid foundation for our future efforts to balance environmental policy and business opportunities. This conclusion is further evidenced by an award received in January 2005 from the Edison Electric Institute related to our advocacy efforts to support mercury cap-and-trade and the accompanying sulfur dioxide and nitrogen oxide regulations.

Asset Sales

While we made significant progress on our divestiture plans in 2004, we have four remaining assets to be sold. We sold the Pushan Power Plant, LIG Pipeline Company, Jefferson Island Storage & Hub, AEP Coal, four Independent Power Producers (IPPs), our U.K. operations, TCC and TNC generation assets, Numanco LLC and our 50% ownership in South Coast Power Limited during 2004, which generated proceeds of approximately $1.4 billion. In addition, on January 27, 2005, we announced the sale of 98% of our interest in Houston Pipeline Company, including gas and working capital, for $1 billion. This sale essentially completes our divestiture of natural gas assets in the U.S.

TCC Generation Assets

The largest remaining asset sale yet to close is the South Texas Project (STP) for approximately $333 million, followed by TCC’s ownership interest in the Oklaunion asset for approximately $43 million. Under the existing PUCT rule, both of these assets must be sold before we can proceed with our Texas True-Up Proceeding. We have entered into agreements to sell TCC’s interest in both facilities and we expect the sales to be completed in the first half of 2005, although the sale of Oklaunion could be delayed by litigation. TCC is considering seeking a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to closing of the sales of all generation assets.

Bajio

Our Bajio investment represents a 50% interest in a 600 MW natural gas-fired facility in Mexico. We have retained an advisor and the sale process is underway. Based on indicative bids received in the fourth quarter of 2004, we recorded an impairment of approximately $13 million. We expect a sale to close in 2006.

Pacific Hydro

Our Pacific Hydro investment represents a 20% interest in an Australian company that develops and operates renewable energy facilities including hydro, wind and geothermal facilities in the Pacific Rim. We have retained an advisor and have identified a preferred bidder. We expect the sale to close in the first half of 2005.

Fuel Costs

Market prices for coal, natural gas and oil have increased dramatically during 2004. These increasing fuel costs are the result of increasing worldwide demand, supply uncertainty, and transportation constraints, as well as other market factors. We manage price and performance risk, particularly for coal, through a portfolio of contracts of varying durations and other fuel procurement and management activities. We have fuel recovery mechanisms for about 50% of our fuel costs in our various jurisdictions.  Additionally, about 20% of our fuel is used for off-system sales where power prices we receive for our power sales should recover our cost of fuel. Accordingly, approximately 70% of fuel cost increases are recovered.  The remaining 30% of our fuel costs relate to Ohio and West Virginia customers, where we do not have a fuel cost recovery mechanism.  We currently have 100% and 85% of our projected coal needs for 2005 and 2006, respectively, under contract.

Capital Expenditures

Environmental

We previously announced plans to invest approximately $3.7 billion in capital from 2004 to 2010, and a total of $5 billion through 2020, to install pollution control equipment that preserves the low cost generation from our coal-fired power plants. Of the $3.7 billion environmental investment plan, $1.9 billion relates to compliance with current laws and the remaining $1.8 billion is intended to cover additional environmental controls that may be required in the future based on current legislative proposals to further reduce emissions and mercury. Forty-nine percent of our $3.7 billion capital plan relates to Ohio generation facilities, followed by Virginia and West Virginia for a combined 34 percent, and Kentucky with 12 percent. Our overall relationships with regulators are important to our growth strategy and our goal of producing low-cost electricity with minimal impact on the environment. We intend to support this investment program through the use of free cash flow and rate increases and therefore, at this time, do not anticipate material incremental leveraging. It is important that we manage the regulatory process to ensure that we receive fair recovery of our costs, including capital costs, as we fulfill our commitment to invest in environmental projects at our generating plants.

Advanced Technology

In conjunction with our environmental analysis issued in August 2004, we announced plans to construct synthetic-gas-fired power plant(s) with at least a combined 1,000 MW of capacity in the next five to six years utilizing new integrated gasification combined cycle (IGCC) technology. We estimate that the new plant(s) will cost up to $1.7 billion, based on Electric Power Research Institute cost studies.  Our detailed studies are under way to fully define the project. We have not determined a location for the plant, but it will likely be in one of our eastern states, because of ready access to coal and the need for capacity in the selected jurisdiction. We are currently performing site analysis and evaluation and at the same time working with state regulators and legislators to establish a framework for expedient recovery of this significant investment in new clean coal technology before final site selection. Our significant planned environmental investments and our commitment to IGCC technology reinforces our belief that coal will be a lower-emission domestic fuel source of the future and further signals our commitment to investing in clean, environmentally safe technology.

See further discussion of these matters in detail in the Notes to Financial Statements and later in Management’s Discussion and Analysis under the heading of Significant Factors. We expect to diligently resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our investors.

OUTLOOK FOR 2005

We remain focused on the fundamental earning power of our utilities, and we are committed to maintaining the strength of our balance sheet. Our strategy for achieving these goals is well planned. We expect to:

· Continue to identify opportunities to increase the efficiency of our operations and capital expenditure program.

· Seek rate changes that are fair and reasonable and that allow us to make the necessary operational, reliability and environmental improvements to our system.

· Efficiently manage generating facilities to benefit our customers and to maximize off-system sales.

· Successfully operate unregulated investments such as our wind farms and our barge and river transport groups, which complement our core utility operations.

· Pursue new environmentally friendly, state of the art coal-fired power plants.

There are, nevertheless, certain risks and challenges including:

· Rate activity such as the TCC wires rate case and the PSO rate case.

· Completion of our asset sales, including the remaining TCC generation assets.

· TCC stranded generation cost recovery, including the generation securitization, wholesale capacity auction true-up, fuel and clawback transition charge, and related carrying costs.

· Fuel cost volatility and fuel cost recovery.

· Financing and recovering the cost of capital expenditures, including environmental and new technology.

RESULTS OF OPERATIONS

Segments

In 2004, AEP’s principal operating business segments and their major activities were:

·	Utility Operations:
		Domestic generation of electricity for sale to retail and wholesale customers
		Domestic electricity transmission and distribution
·	Investments - Gas Operations: (a)
		Gas pipeline and storage services
·	Investments - UK Operations: (b)
		Generation of electricity in the U.K. for sale to wholesale customers
		Coal procurement and transportation to our plants
·	Investments - Other: (c)
		Bulk commodity barging operations, wind farms, independent power producers and other energy supply-related businesses

(a)	LIG Pipeline Company and its subsidiaries, including Jefferson Island Storage & Hub LLC, were classified as discontinued operations during 2003 and were sold during 2004. 98% of the remaining HPL-related gas assets were sold during the first quarter of 2005.
(b)	UK Operations were classified as discontinued during 2003 and substantially all operations were sold during 2004.
(c)	Four independent power producers were sold during 2004.

Our consolidated Net Income (Loss) for the years ended December 31, 2004, 2003 and 2002 were as follows (Earnings and Average Shares Outstanding in millions):

	2004						2003						2002
	Earnings			EPS			Earnings			EPS			Earnings			EPS
Utility Operations	$	1,171		$	2.96		$	1,219		$	3.17		$	1,154		$	3.47
Investments - Gas Operations		(51	)		(0.13	)		(290	)		(0.76	)		(99	)		(0.29	)
Investments - Other		78			0.20			(278	)		(0.72	)		(522	)		(1.58	)
All Other (a)		(71	)		(0.18	)		(129	)		(0.34	)		(48	)		(0.14	)
Income Before Discontinued Operations,   Extraordinary Item and Cumulative   Effect of Accounting Changes		1,127			2.85			522			1.35			485			1.46
Investments - Gas Operations		(12	)		(0.03	)		(91	)		(0.24	)		8			0.02
Investments - UK Operations		91			0.23			(508	)		(1.32	)		(472	)		(1.42	)
Investments - Other		4			0.01			(6	)		(0.01	)		(190	)		(0.57	)
Discontinued Operations, Net of Tax		83			0.21			(605	)		(1.57	)		(654	)		(1.97	)
Extraordinary Loss on Texas Stranded    Cost Recovery - Utility Operations,   Net of Tax		(121	)		(0.31	)		-			-			-			-
Utility Operations		-			-			236			0.61			-			-
Investments - Gas Operations		-			-			(22	)		(0.05	)		-			-
Investments - UK Operations		-			-			(21	)		(0.05	)		-			-
Investments - Other		-			-			-			-			(350	)		(1.06	)
Cumulative Effect of Accounting Changes,   Net of Tax		-			-			193			0.51			(350	)		(1.06	)
Net Income (Loss)	$	1,089		$	2.75		$	110		$	0.29		$	(519	)	$	(1.57	)
Weighted Average Shares Outstanding					396						385						332

(a) All Other includes the Parent’s interest income and expense, as well as other nonallocated costs.

2004 Compared to 2003

Income Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes in 2004 increased $605 million compared to 2003 due to increased retail margins and stranded generation carrying cost deferrals at TCC in our Utility Operations, improved margins and lower impairments in our Gas Operations and Investments - Other segments, gains realized on the sale of assets, and lower provisions for penalties and other expenses booked by the Parent. These increases were offset, in part, by decreased margins due to the divestiture of Texas generation assets, the loss of the capacity auction true-up revenues in Texas, and higher operations and maintenance expense, all occurring in our Utility Operations segment.

Our Net Income for 2004 of $1,089 million, or $2.75 per share, includes income, net of tax, on discontinued operations of $83 million, resulting primarily from a gain on the sale of our UK Operations, and an extraordinary loss of $121 million, net of tax, which represents a provision for probable disallowance to the stranded cost net regulatory assets of TCC based on PUCT orders in nonaffiliated true-up proceedings. Our Net Income for 2003 of $110 million, or $0.29 per share, includes a $605 million loss, net of tax, on discontinued operations and $193 million of income, net of tax, from the cumulative effect of changing our accounting for asset retirement obligations and for certain trading activities.

Average shares outstanding increased to 396 million in 2004 from 385 million in 2003 due to a common stock issuance in 2003 and common shares issued related to our incentive compensation plans. The additional average shares outstanding decreased our 2004 earnings per share by $0.08.

2003 Compared to 2002

Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect of Accounting Changes in 2003 increased compared to 2002 due to increased wholesale earnings, lower impairment and other charges, and reduced operations and maintenance expenses. This increase was offset, in part, by milder summer weather and continuing weakness in the economy. Our Net Income for 2003 of $110 million, or $0.29 per share, includes a $605 million loss, net of tax, on discontinued operations and $193 million of income, net of tax, from the cumulative effect of FASB-required changes to our accounting for asset retirement obligations and for certain trading activities. Our Net Loss for 2002 of $519 million, or ($1.57) per share, includes a $654 million loss, net of tax, from discontinued operations and a $350 million, net of tax, charge for implementing a newly issued accounting pronouncement related to the impairment of goodwill.

In the fourth quarter of 2003 we concluded that the UK Operations and LIG were not part of our core business and we began actively marketing each of these investments. The UK Operations consisted of generation and trading operations that sell to wholesale customers. LIG’s operations included 2,000 miles of intrastate gas pipelines in Louisiana and 9 Bcf of natural gas storage capacity. Poor market conditions also affected our merchant generation, other gas pipeline and storage assets, goodwill associated with these investments and various other assets. Based on market factors, as measured by a combination of indicative bids from unrelated interested buyers, independent appraisals, and estimates of cash flows, we recognized impairment losses of $960 million, net of tax.

Average shares outstanding increased to 385 million in 2003 from 332 million in 2002 due to a common stock issuance in March 2003. The additional average shares outstanding decreased our 2003 earnings per share by $0.04.

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

Utility Operations

	2004		2003		2002
	(in millions)
Revenues	$	10,633	$	11,015	$	10,491
Fuel and Purchased Power		3,615		3,746		3,132
Gross Margin		7,018		7,269		7,359
Depreciation and Amortization		1,256		1,250		1,276
Other Operating Expenses		3,772		3,554		3,811
Operating Income		1,990		2,465		2,272
Other Income (Expense), Net		353		27		170
Interest Charges and Preferred Stock Dividend Requirements		616		664		642
Income Tax Expense		556		609		646
Income Before Discontinued Operations, Extraordinary Item and   Cumulative Effect of Accounting Charges	$	1,171	$	1,219	$	1,154

Summary of Selected Sales Data

For Utility Operations

For the Years Ended December 31, 2004, 2003 and 2002

	2004		2003		2002
Energy Summary	(in millions of KWH)
Retail:
Residential		45,770		45,308		37,900
Commercial		37,204		36,798		30,380
Industrial		51,484		49,446		51,491
Miscellaneous		3,099		3,026		2,261
Subtotal		137,557		134,578		122,032
Texas Retail and Other		925		2,896		18,162
Total		138,482		137,474		140,194
Wholesale		82,870		72,977		70,661
		2004		2003		2002
Weather Summary	(in degree days)
Eastern Region
Actual - Heating		2,991		3,219		2,886
Normal - Heating (a)		3,086		3,075		3,071
Actual - Cooling		876		756		1,247
Normal - Cooling (a)		974		976		969
Western Region (b)
Actual - Heating		1,382		1,554		1,566
Normal - Heating (a)		1,624		1,622		1,622
Actual - Cooling		2,005		2,144		2,233
Normal - Cooling (a)		2,149		2,138		2,128

(a)	Normal Heating/Cooling represents the 30-year average of degree days.
(b)	Western Region statistics represent PSO/SWEPCo customer base only.

2004 Compared to 2003

Reconciliation of Year Ended December 31, 2003 to Year Ended December 31, 2004

Income from Utility Operations Before Discontinued Operations, Extraordinary Item and

Cumulative Effect of Accounting Changes

(in millions)

Year Ended December 31, 2003			$1,219
Changes in Gross Margin:
Retail Margins	65
Texas Supply Margins	(105	)
Wholesale Capacity Auction True-up Revenues	(215	)
Off-System Sales	10
Other Revenue	(6	)
				(251	)
Changes in Operating and Other Expenses:
Operations and Maintenance	(205	)
Asset Impairments and Other Related Charges	10
Depreciation and Amortization	(6	)
Taxes, Other	(23	)
Carrying Costs on Texas Stranded Costs	302
Other Income (Expense), Net	24
Interest Charges	48
				150
Income Tax Expense				53
Year Ended December 31, 2004			$	1,171

Income from Utility Operations Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes decreased $48 million to $1,171 million in 2004. Key drivers of the decrease include a $251 million decrease in gross margin; offset in part by a $150 million decrease in operating and other expenses and a $53 million decrease in income tax expense.

The major components of the net decrease in gross margin, defined as utility revenues net of related fuel and purchased power, were as follows:

· The increase in retail margins of our utility business over the prior year was due to increased demand in both the East and the West as a consequence of higher usage in most classes and customer growth in the residential and commercial classes. Commercial and industrial demand also increased, resulting from the economic recovery in our regions. Milder weather during the summer months of 2004 partially offset these favorable results.

· Our Texas Supply business experienced a $105 million decrease in gross margin principally due to the partial divestiture of a portion of TCC’s generation assets to support Texas stranded cost recovery. This resulted in higher purchased power costs to fulfill contractual commitments.

· Beginning in 2004, the wholesale capacity auction true-up ceased per the Texas Restructuring Legislation. Related revenues are no longer recognized, resulting in $215 million of lower regulatory asset deferrals in 2004. For the years 2003 and 2002, we recognized the revenues for the wholesale capacity auction true-up for TCC as a regulatory asset for the difference between the actual market prices based upon the state-mandated auction of 15% of generation capacity and the earlier estimate of market price used in the PUCT’s excess cost over market model.

· Margins from off-system sales for 2004 were $10 million higher than in 2003 due to favorable optimization activity, somewhat offset by lower volumes.

Utility Operating and Other Expenses changed between the years as follows:

· Operations and Maintenance expense increased $205 million due to a $110 million increase in generation expense primarily due to an increase in maintenance outage weeks in 2004 as compared to 2003 and increases in related removal and chemical costs, PJM expenses and operating expenses for the Dow Plaquemine Plant. Additionally, distribution maintenance expense increased $54 million from system improvement and reliability work and damage repair resulting primarily from major ice storms in our Ohio service territory during December 2004. Other increases of $81 million include ERCOT and transmission cost of service adjustments in 2004 and increased employee benefits, insurance, and other administrative and general expenses magnified by favorable adjustments in 2003. These increases were offset, in part, by $40 million due to the conclusion in 2003 of the amortization of our deferred Cook nuclear plant restart expenses.

· 2003 included a $10 million impairment at Blackhawk Coal Company, a nonoperating wholly-owned subsidiary of I&M, which holds western coal reserves.

· Depreciation and Amortization expense increased $6 million primarily due to a higher depreciable asset base, including the addition of capitalized software costs, increased amortization of regulatory assets, and the consolidation in July 2003 of JMG by OPCo (which had no impact on net income). These increases more than offset the decrease in expense at TCC, which is due primarily to the cessation of depreciation on plants classified as held for sale.

· Taxes Other Than Income Taxes increased $23 million due to increased property tax values and assessments, higher revenue taxes due to the increase in KWH sales, and favorable prior year franchise tax adjustments.

· Carrying Costs on Texas Stranded Costs of $302 million represent TCC’s debt component of the carrying costs accrued on its net stranded generation costs and its capacity auction true-up asset (see “Texas Restructuring” and “Texas True-Up Proceedings” under Customer Choice and Industry Restructuring).

· Interest Charges decreased $48 million from the prior period primarily due to refinancings of higher coupon debt at lower interest rates.

· Income Tax expense decreased $53 million due to the decrease in pretax income and tax return adjustments.

2003 Compared to 2002

Reconciliation of Year Ended December 31, 2002 to Year Ended December 31, 2003

Income from Utility Operations Before Discontinued Operations, Extraordinary Item and

Cumulative Effect of Accounting Changes

(in millions)

Year Ended December 31, 2002			$	1,154
Changes in Gross Margin:
Retail Margins	(145	)
Texas Supply	(85	)
Wholesale Capacity Auction Revenues	(44	)
Off-System Sales	162
Other Wholesale Transactions	(70	)
Other Revenue	92
				(90	)
Changes in Operating and Other Expenses:
Operations and Maintenance	183
Asset Impairments and Other Related Charges	43
Depreciation and Amortization	26
Taxes, Other	31
Other Income (Expense), Net	(143	)
Interest Charges	(22	)
				118
Income Tax Expense				37
Year Ended December 31, 2003			$	1,219

Income from Utility Operations Before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes increased $65 million to $1,219 million in 2003. Key drivers of the increase include a $118 million decrease in operating and other expenses and a $37 million decrease in income tax expense; offset in part by a $90 million decrease in gross margin.

The major components of our decrease in gross margin, defined as utility revenues net of related fuel and purchased power, were as follows:

· The decrease in retail margins from the prior year was due to lower retail demand from mild weather primarily in the East, and lower industrial demand in both the East and West service territories primarily due to the continued slow economic recovery in 2003.

· Our Texas Supply business experienced a decrease in gross margin principally due to provisions for probable final Texas fuel and off-system sales disallowances of $102 million and the loss of margin contributions from two Texas Retail Electric Providers (REPs) sold to Centrica in December 2002. The demand from the two REPs was replaced, in part, with a power supply contract with Centrica that extended through 2004.

· In 2003 and 2002, we recognized the revenues for the wholesale capacity auction true-up at TCC as a regulatory asset representing the difference between the actual market prices based upon state-mandated auctions of 15% of economically available generation capacity and the earlier estimate of market prices used in the PUCT’s excess cost over market model. The amount recognized in 2003 was $218 million, or $44 million less than in 2002.

· Margins from off-system sales for 2003 improved by $162 million over 2002 due to increased volumes, higher prices, and plant availability.

· Other wholesale transactions represent the transition electric trading book, associated with our decision to exit from markets where we do not own assets. During the fourth quarter of 2002, we exited trading activities that were not related to the sale of power from owned-generation. This reduced comparative 2003 utility earnings by approximately $70 million.

· Other revenue includes transmission revenues, third party revenues and miscellaneous service revenues. Transmission revenues were $45 million higher than the prior year primarily due to the effect of higher off-system sales volumes. Service revenues exceeded the prior year by $47 million primarily due to higher reconnect, temporary service fees, rental on pole attachments, transmission rentals, forfeited discounts, and other miscellaneous items.

Utility Operating and Other Expenses changed between the years as follows:

· Maintenance and Other Operation expenses decreased $183 million due to our continued efforts to reduce costs where practical, primarily administrative and general expenses, labor and employee related expenses, of approximately $120 million. The sale of the Texas REPs reduced expenses supporting the back office by $75 million in 2003, and unfavorable severance costs in 2002 contributed to the period-to-period favorable variance by $65 million. These decreases were offset, in part, by approximately $24 million in damage repair as a result of severe storms in the Midwest, and higher pension and postretirement benefit costs of approximately $60 million in 2003.

· Asset Impairments and Other Related Charges decreased $43 million from the prior year. 2002 included $38 million in impairments of certain moth-balled Texas gas plants, all related to TNC, a $12 million loss of investment value in some early-stage start up technologies, and a $3 million loss of investment value in water heater assets. Asset impairments in 2003 at Blackhawk Coal Company were $10 million.

· Depreciation and Amortization expense decreased $26 million primarily due to the change in our accounting for asset retirement obligations. The change caused similar offsetting increases in Maintenance and Other Operation expense.

· The decrease in Taxes, Other was primarily due to reduced gross receipts tax as a result of the sale of the Texas REPs and prior period franchise tax return true-ups.

· Other Income (Expense), Net decreased $143 million primarily due to a net gain on sale of the Texas REPs in 2002.

· Interest Charges increased $22 million from the prior period due to expensing debt reacquisition costs previously deferred under the regulatory accounting model and the consolidation in July 2003 of JMG by OPCo (which had no impact on net income), as well as the maturity of short-term debt.

· Income Tax expense decreased $37 million primarily due to state tax return adjustments partially offset by higher pretax income.

Investments - Gas Operations

	2004			2003			2002
	(in millions)
Revenues	$	3,114		$	3,126		$	2,283
Purchased Gas		2,955			2,995			2,171
Gross Margin		159			131			112
Operating Expenses		144			484			227
Operating Income (Loss)		15			(353	)		(115	)
Other Income (Expense), Net		(33	)		(8	)		(4	)
Interest Charges and Minority Interest in Finance Subsidiary		57			56			50
Income Tax Benefit		24			127			70
Net Loss Before Discontinued Operations and Cumulative
Effect of Accounting Changes	$	(51	)	$	(290	)	$	(99	)

2004 Compared to 2003

Reconciliation of Year Ended December 31, 2003 to Year Ended December 31,2004

Loss from Investments - Gas Operations Before Discontinued Operations and Cumulative Effect of Accounting Changes

(in millions)

Year Ended December 31, 2003			$	(290	)
Change in Gross Margin				28
Changes in Operating And Other Expenses:
Operations and Maintenance	21
Depreciation and Amortization	7
Taxes, Other	(3	)
Other Income (Expense), Net	(25	)
Interest Charges	(1	)
				(1	)
Asset Impairments and Other Related Charges				315
Income Tax Benefit				(103	)
Year Ended December 31, 2004			$	(51	)

Our loss from Gas Operations before discontinued operations and cumulative effect of accounting changes decreased $239 million to $51 million in 2004. The key driver of the decrease was $315 million of impairments recorded in 2003, partially offset by a $103 million decrease in income tax benefit principally related to the impairments.

The major components of the net increase in gross margin of $28 million, defined as gas revenues net of related purchased gas are as follows:

· 2003 included losses of $31 million related to the servicing of a single contract.

· Pipeline and pipeline optimization margins improved by $24 million.

· Storage margins decreased by $53 million, largely due to timing on recognition of storage margins.

· Prior year transitional gas trading activities yielded losses of $26 million.

Gas Operating and Other Expenses remained flat year-over-year. However, significant line-item changes are as follows:

· Operations and Maintenance expenses decreased $21 million as a result of gas trading activities that have since been ceased.

· Depreciation and Amortization expense decreased $7 million primarily due to the 2003 asset impairments.

· Other Income (Expense), Net decreased $25 million primarily due to the write-off of stranded intercompany debt between a discontinued operation and its parent.

2003 Compared to 2002

Reconciliation of Year Ended December 31, 2002 to Year Ended December 31, 2003

Loss from Investments - Gas Operations Before Discontinued Operations and Cumulative Effect of Accounting Changes

(in millions)

Year Ended December 31, 2002			$	(99	)
Change in Gross Margin				19
Change in Operating And Other Expenses:
Operations and Maintenance	60
Depreciation and Amortization	(5	)
Taxes, Other	3
Other Income (Expense), Net	(4	)
Interest Charges	(6	)
				48
Asset Impairments and Other Related Charges				(315	)
Income Tax Benefit				57
Year Ended December 31, 2003			$	(290	)

The loss from our Gas Operations before discontinued operations and cumulative effect of accounting changes of $290 million increased $191 million from 2002. This increase is primarily due to impairments recorded to reflect the reduction in the value of our gas assets. In the fourth quarter of 2003, we recognized impairments and other related charges of $315 million associated with HPL assets and goodwill based on market indicators supported by indicative bids received for LIG. These bids led us to conclude that purchasers were no longer willing to pay higher multiples for historic cash flows which included trading activities. Our previous operating strategy included higher risk tolerances associated with trading activities in order to achieve such operating results.

Partially offsetting the 2003 impairments, Gas Operations earnings increased $124 million year-over-year as a result of the following:

· Improvement in the transition gas segment margins of $62 million due to prior year losses in the options trading portfolio and lower operating expenses of $43 million.

· Decline in trading optimization of $43 million due to lower risk tolerances and limits in 2003 as compared to 2002.

· 2003 included losses of $31 million related to the servicing of a single contract.

· A $57 million increase in income tax benefit due to the increase in pretax losses.

Investments - UK Operations

2004 Compared to 2003

Income from our Investments - UK Operations segment (all classified as Discontinued Operations) increased to $91 million in income, which includes a gain on sale of $128 million in 2004, compared with a loss of $508 million in 2003, before the cumulative effect of accounting change. During late 2003, we concluded that the UK Operations were not part of our core business and we began actively marketing our investment. In July 2004, we completed the sale of substantially all operations and assets within our Investments - UK Operations segment.

2003 Compared to 2002

The loss before cumulative effect of accounting change from our UK Operations of $508 million for 2003 increased by $36 million from 2002 due primarily to a $375 million, net of tax, impairment and other related charges recorded during the fourth quarter of 2003 compared with a net of tax impairment of $414 million recorded in 2002. During 2003, we concluded that the UK Operations were not part of our core business and we began actively marketing our investment. As a result, we wrote down our UK investment based on bids received from interested, unrelated buyers. The 2003 loss also includes $157 million of pretax losses associated with commitments for below-market forward sales of power, which went beyond the date of the anticipated sale of these plants. We also experienced operating losses as a result of the deterioration of pretax trading margins of $83 million associated with U.K. power and $29 million associated with coal and freight.

Investments - Other

2004 Compared to 2003

Income before discontinued operations from our Investments - Other segment increased from a loss of $278 million in 2003 to income of $78 million in 2004.

The key components of the increase in income were as follows:

· We recorded an after tax gain of approximately $64 million resulting from the sale in July 2004 of our ownership interests in our two independent power producers in Florida (Mulberry and Orange).

· We recorded an after tax gain of approximately $31 million resulting from the sale of our 50% interest in South Coast Power Limited, owner of the Shoreham Power Station in the U.K.

· Our results in 2004 did not include $257 million of after tax impairments recorded in 2003, related to our investment in the Colorado IPPs, AEP Coal and the Dow power generation facility.

· Our AEP Texas Provider of Last Resort (POLR) entity recorded a $6 million after tax provision for uncollectible receivables in 2003.

· AEP Resources decreased its loss by $33 million in 2004 versus 2003, primarily due to lower interest expense of $19 million resulting from equity capital infusions in mid and late 2003 that were used to reduce debt and other corporate borrowings and $6 million related to increased earnings from Bajio.

· AEP Pro Serv reduced losses from $6 million to $1 million of income, primarily due to operations winding down in 2004.

Offsetting these increases was the absence during 2004 of a $31 million gain recorded in 2003 primarily related to the sale of Mutual Energy, AEP’s Texas REP, and a $7 million decrease in net income as a result of having sold four of our IPPs in 2004.

Discontinued operations includes the Eastex Cogeneration facility, which was sold in 2003 and Pushan Power Plant, which was sold in March 2004.

2003 Compared to 2002

The loss before discontinued operations and cumulative effect of accounting changes from our Investments - Other segment decreased by $244 million to $278 million in 2003. The decrease was primarily due to asset impairment charges of $257 million, net of tax, recorded in 2003 compared to impairments of $392 million, net of tax, recorded in 2002. Impairments in 2003 included losses of $46 million, net of tax, for two of our independent generation facilities due to market conditions in 2003; $168 million, net of tax, for the Dow facility due to the current market conditions and litigation; and coal mining asset impairments of $44 million, net of tax, based on bids from unrelated parties. We also had lower international development costs and reduced interest expenses during 2003.

All Other

2004 Compared to 2003

The Parent’s 2004 loss decreased $58 million from 2003 due to a $40 million provision for penalties booked in 2003, compared to $20 million in 2004, a $12 million decrease in expenses primarily resulting from lower insurance premiums and lower general advertisement expenses in 2004 and a $20 million decrease in income taxes related to federal tax accrual adjustments. Interest income was $9 million lower in the current period due to lower cash balances, along with higher interest rates on invested funds in 2003. Additionally, parent guarantee fee income from subsidiaries was $4 million lower due to the reduction of trading activities. There is no effect on consolidated net income for this item.

2003 Compared to 2002

The Parent’s 2003 loss increased $81 million over 2002 primarily from higher interest costs due to increased long-term debt at the parent level and reduced reliance on short-term borrowings as well as a $40 million provision for penalties booked in 2003.

Income Taxes

The effective tax rates for 2004, 2003 and 2002 were 33.5%, 40.3% and 38.8%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, energy production credits, amortization of investment tax credits, and other state income tax and federal income tax adjustments. The decrease in the effective tax rate in 2004 versus the comparative period is primarily due to more favorable federal income tax adjustments in 2004 versus 2003 and changes in permanent differences. The effective tax rates remained relatively flat between 2002 and 2003.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows. During 2004, we improved our financial condition as a consequence of the following actions and events:

· We reduced short-term debt by $303 million, terminated our Euro revolving credit facility, completed approximately $2.3 billion of long-term debt redemptions, including optional redemptions such as our Steelhead financing, and funded $770 million of debt maturities; and

· We maintained stable credit ratings across the AEP System. Moody’s Investor Services assigned a positive outlook on AEP Inc.’s ratings, while the rated subsidiaries continued to have ratings with stable outlooks.

Capitalization ($ in millions)

	2004				2003
Common Equity	$	8,515	40.6	%	$	7,874	35.1	%
Preferred Stock		61	0.3			61	0.3
Preferred Stock (Subject to Mandatory Redemption)		66	0.3			76	0.3
Long-term Debt, including amounts due within one year		12,287	58.7			14,101	62.8
Short-term Debt		23	0.1			326	1.5
Total Capitalization	$	20,952	100.0	%	$	22,438	100.0	%

Our $2.6 billion in cash flows from operations, combined with our reduction in cash expenditures for investments in discontinued operations, the proceeds from asset sales, a reduction in the dividend beginning in the second quarter of 2003 and the use of a portion of our cash on hand, allowed us to reduce long-term debt by $1.8 billion and short-term debt by $303 million.

Our common equity increased due to earnings exceeding the amount of dividends paid in 2004, a discretionary $200 million cash contribution to our pension fund, which allowed us to remove a portion of the charge to equity related to the underfunded plan, and the issuance of $17 million of new common equity (related to our incentive compensation plans). 

As a consequence of the capital changes during 2004, we improved our ratio of debt to total capital from 64.6% to 59.1% (preferred stock subject to mandatory redemption is included in the debt component of the ratio).

In February 2005, our Board of Directors authorized us to repurchase up to $500 million of our common stock from time to time through 2006.

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 December 31, 2004, our available liquidity was approximately $3.3 billion as illustrated in the table below:

			Amount			Maturity
			(in millions)
Commercial Paper Backup:
	Lines of Credit		$	1,000		May 2005
	Lines of Credit			750		May 2006
	Lines of Credit			1,000		May 2007
Letter of Credit Facility				200		September 2006
Total				2,950
Cash and Cash Equivalents				420
Total Liquidity Sources				3,370
Less: AEP Commercial Paper Outstanding				-	(a)
		Letters of Credit Outstanding		54
Net Available Liquidity			$	3,316

(a) Amount does not include JMG commercial paper outstanding in the amount of $23 million. This commercial paper is specifically associated with the Gavin scrubber and does not reduce AEP’s available liquidity. The JMG commercial paper is supported by a separate letter of credit facility not included above.

During the second quarter of 2005, we intend to replace our $1 billion credit facility expiring in May 2005 and our $750 million credit facility expiring in May 2006 with a $1.5 billion five-year credit facility.

Debt Covenants

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 outstanding debt and other capital under these covenants is contractually defined. At December 31, 2004, this percentage was 54.1%. Nonperformance of these covenants may result in an event of default under these credit agreements. At December 31, 2004, we complied with the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or those 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 amounts outstanding thereunder payable.

Our revolving credit facilities generally prohibit new borrowings if we experience a material adverse change in our business or operations. We may, however, make new borrowings under these facilities if we experience a material adverse change so long as the proceeds of such borrowings are used to repay outstanding commercial paper.

Under an SEC order, AEP and its 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 AEP and 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 December 31, 2004, we were in compliance with this order.

Nonutility Money Pool borrowings, Utility Money Pool borrowings and external borrowings may not exceed SEC or state commission authorized limits. At December 31, 2004, we had not exceeded the SEC or state commission authorized limits.

Dividend Policy and Restrictions

We have declared common stock dividends payable in cash in each quarter since July 1910, representing 379 consecutive quarters. The Board of Directors, at its January 2005 meeting, declared a quarterly dividend of $0.35 a share, payable March 10, 2005 to shareholders of record on February 10, 2005. Future dividends may vary depending upon our profit levels, operating cash flow levels and capital requirements as well as financial and other business conditions existing at the time. The timing of any dividend increase could depend upon the resolution of certain issues, including our planned divestitures and the results of our Texas rate and true-up proceedings. We hope to be able to recommend to the Board of Directors gradual, sustainable increases in our common stock dividend from its current level of 35 cents per share per quarter.

PUHCA prohibits our subsidiaries from making loans or advances to the parent company, AEP. In addition, under PUHCA, AEP and its public utility subsidiaries can pay dividends only out of retained or current earnings.

Credit Ratings

We continue to take steps to improve our credit quality, including executing plans during 2004 to further reduce our outstanding debt through the use of proceeds from our asset divestitures and other available cash.

AEP’s ratings have not been adjusted by any rating agency during 2004. On August 2, 2004, Moody’s Investors Service (Moody’s) changed their outlook on AEP to “positive” from “stable,” while keeping the remaining rated subsidiaries on “stable” outlook. The other major rating agencies have AEP and its rated subsidiaries on “stable” outlook.

Our current credit ratings are as follows:

	Moody’s	S&P	Fitch
AEP Short Term Debt	P-3	A-2	F-2
AEP Senior Unsecured Debt	Baa3	BBB	BBB

If AEP or any of its 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 nationally recognized 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.

	2004			2003			2002
	(in millions)
Cash and cash equivalents at beginning of period	$	976		$	1,084		$	163
Net Cash Flows From Operating Activities		2,597			2,308			2,067
Net Cash Flows Used For Investing Activities		(376	)		(1,979	)		(462	)
Net Cash Flows Used For Financing Activities		(2,777	)		(437	)		(681	)
Effect of Exchange Rate Changes on Cash		-			-			(3	)
Net Increase (Decrease) in Cash and Cash Equivalents		(556	)		(108	)		921
Cash and cash equivalents at end of period	$	420		$	976		$	1,084

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 December 31, 2004, we had credit facilities totaling $2.8 billion to support our commercial paper program. 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. Nonutility Money Pool borrowings, Utility Money Pool borrowings and external borrowings may not exceed SEC authorized limits.

Operating Activities

	2004			2003			2002
	(in millions)
Net Income (Loss)	$	1,089		$	110		$	(519	)
Plus: (Income) Loss From Discontinued Operations		(83	)		605			654
Income From Continuing Operations		1,006			715			135
Noncash Items Included in Earnings		1,471			1,939			2,676
Changes in Assets and Liabilities		120			(346	)		(744	)
Net Cash Flows From Operating Activities	$	2,597		$	2,308		$	2,067

2004 Operating Cash Flow

During 2004, our cash flows from operating activities were $2.6 billion consisting of our income from continuing operations of $1 billion and noncash charges of $1.6 billion for depreciation, amortization and deferred taxes. We recorded $302 million in noncash income for carrying costs on Texas stranded cost recovery and recognized an after tax, noncash extraordinary loss of $121 million to provide for probable disallowances to TCC’s stranded generation costs. We realized a $159 million gain on sale of assets primarily on the sales of the IPPs and South Coast. We made a $200 million discretionary contribution to our pension trust.

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.

Changes in working capital items resulted in cash from operations of $467 million predominantly due to increased accrued income taxes. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since our consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extension is filed.

2003 Operating Cash Flow

Our cash flows from operating activities were $2.3 billion for 2003. We produced income from continuing operations of $715 million during the period. Income from continuing operations for 2003 included noncash items of $1.5 billion for depreciation, amortization, and deferred taxes, $193 million for the cumulative effects of accounting changes, and $720 million for impairment losses and other related charges. In addition, there was a current period impact for a net $122 million balance sheet change for risk management contracts that are marked-to-market. These derivative contracts have an unrealized earnings impact as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The 2003 activity in changes in assets and liabilities relates to a number of items; the most significant of which are:

· Noncash wholesale capacity auction true-up revenues resulting in stranded cost regulatory assets of $218 million, which are not recoverable in cash until the conclusion of our TCC’s True-up Proceeding.

· Net changes in accounts receivable and accounts payable of $269 million related, in large part, to the settlement of risk management positions during 2002 and payments related to those settlements during 2003. These payments include $90 million in settlement of power and gas transactions to the Williams Companies. The earnings effects of substantially all payments were reflected on a MTM basis in earlier periods.

· Increases in fuel and inventory levels of $52 million resulting primarily from higher procurement prices.

· Reserves for disallowed deferred fuel costs, principally related to Texas, which will be a component of our Texas True-up Proceedings.

2002 Operating Cash Flow

During 2002, our cash flows from operating activities were $2.1 billion. Income from continuing operations was $135 million during the period. Income from continuing operations for 2002 included noncash items of $1.4 billion for depreciation, amortization, and deferred taxes, $350 million related to the cumulative effect of an accounting change, and $639 million for impairment losses. There was a current period impact for a net $275 million balance sheet change for risk management contracts that were marked-to-market. These contracts have unrealized earnings impacts as market prices move, and a cash impact upon settlement or upon disbursement or receipt of premiums. The activity in the asset and liability accounts related to the wholesale capacity auction true-up regulatory asset of $262 million, deposits associated with risk management activities of $136 million, and seasonal increases in our fuel inventories.

Investing Activities

	2004			2003			2002
	(in millions)
Construction Expenditures	$	(1,693	)	$	(1,358	)	$	(1,685	)
Change in Other Cash Deposits, Net		31			(91	)		(84	)
Proceeds from Sale of Assets		1,357			82			1,263
Other		(71	)		(612	)		44
Net Cash Flows Used for Investing Activities	$	(376	)	$	(1,979	)	$	(462	)

In 2004, our cash flows used for investing activities were $376 million. We funded our construction expenditures primarily with cash generated by operations. Our construction expenditures of $1.7 billion were distributed across our system, of which the most significant expenditures were investments for environmental improvements of $350 million and for a high voltage transmission line of $75 million. During 2004, we sold our U.K. generation, Jefferson Island Storage, LIG and certain IPP and TCC generation assets and used the proceeds from the sales of these assets to reduce debt.

Our cash flows used for investing activities were $2 billion in 2003 for increased investments in our U.K. operations and environmental and normal capital expenditures.

In 2002, our cash flows used for investing activities were $462 million as the proceeds received from the sales of SEEBOARD, CitiPower, and the Texas REPs offset a significant portion of our construction expenditures.

We forecast $2.7 billion of construction expenditures for 2005. 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.

Financing Activities

	2004			2003			2002
	(in millions)
Issuances of Equity Securities (common stock/equity units)	$	17		$	1,142		$	990
Issuances/Retirements of Debt, net		(2,229	)		(727	)		(868	)
Retirement of Preferred Stock		(10	)		(9	)		(10	)
Retirement of Minority Interest (a)		-			(225	)		-
Dividends Paid on Common Stock		(555	)		(618	)		(793	)
Net Cash Flows Used for Financing Activities	$	(2,777	)	$	(437	)	$	(681	)

(a) Minority Interest was reclassified to debt in July 2003 and the related $525 million of debt was repaid in 2004. See “Minority Interest in Finance Subsidiary” section of Note 17.

In 2004, we used $2.8 billion of cash to reduce debt and pay common stock dividends. We achieved our goal of reducing debt below 60% of total capitalization by December 31, 2004. The debt reductions were primarily funded by proceeds from our various divestitures in 2004.

Our cash flows used for financing activities were $437 million during 2003. The proceeds from the issuance of common stock were used to reduce outstanding debt and minority interest in a finance subsidiary.

In 2002, we used $681 million of cash from operations to pay common stock dividends and proceeds from the issuance of equity to repay debt.

The following financing activities occurred during 2004 and 2003:

Common Stock:

· During 2004 and 2003, we issued 841,732 and 23,001 shares of common stock, respectively, under our incentive compensation plans. For 2004, we received net proceeds of $14 million for 525,002 shares. The net proceeds for 2003 were insignificant.

· In March 2003, we issued 56 million shares of common stock at $20.95 per share through an equity offering and received net proceeds of $1.1 billion (net of issuance costs of $36 million). We used the proceeds to pay down both short-term and long-term debt with the balance being held in cash.

Debt:

· During 2004, we issued approximately $1.2 billion of long-term debt, including approximately $318 million of pollution control revenue bonds. The proceeds of these issuances were used to reduce short-term debt, fund long-term debt maturities and fund optional redemptions. In August 2004, Moody’s Investor Services upgraded AEP, Inc.’s short-term and long-term debt ratings to a “positive” outlook.

· During 2004, we entered into $530 million notional amount of fixed to floating swaps and unwound $400 million notional amount of swap transactions. The swap unwinds resulted in $9.1 million in cash proceeds. As of December 31, 2004, we had in place interest rate hedge transactions with a notional amount of $515 million in order to hedge a portion of anticipated 2005 issuances.

· During 2004, AEP Credit renewed its sale of receivables agreement for three years and it now expires on August 24, 2007. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2004, $435 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

· In May 2004, we closed on a $1 billion revolving credit facility for AEP, Inc., which replaced a maturing $750 million revolving credit facility. The facility will expire in May 2007. As of December 31, 2004, we had credit facilities totaling $2.8 billion to support our commercial paper program. As of December 31, 2004, we had no commercial paper outstanding related to the corporate borrowing program. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $661 million in June 2004 and the weighted average interest rate of commercial paper outstanding during the year was 1.81%.

· In June 2004, $494 million of five-year floating rate private placement debt was refinanced by Juniper Capital under the lease agreement for our Dow Plaquemine Cogeneration Project. See “Power Generation Facility” section within this “Financial Condition” section.

Our plans for 2005 include the following:

· In January, APCo issued Senior Unsecured Notes in the amount of $200 million at a rate of 4.95%.

· In January, OPCo refinanced $218 million of JMG’s Installment Purchase Contracts. The new bonds bear interest at a 35-day auction rate.

· In February, TCC reissued $162 million Matagorda County Navigation District Installment Purchase Contracts due May 1, 2030 that were put to TCC in November 2004. These bonds had not been retired as TCC intended to reissue the bonds at a later date. The original installment purchase contracts were mandatory one-year put bonds with fixed rates of 2.15% for Series A and 2.35% for Series B at the time of the put. The reissued contracts bear interest at 35-day auction rates.

· In June 2002, we issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note. In May 2005, the senior note portion of the equity will be remarketed and the coupon reset. In August 2005, under the terms of the equity units, holders will be required to purchase from us a certain number of shares per unit (1.2225 shares per unit at our current stock price). This would increase our average total shares outstanding from 396 million in 2004 to an estimated 399 million in 2005.

· Quarterly, make discretionary contributions of $100 million to our underfunded pension plans in order to fully fund the plans by the end of 2005.

Minority Interest and Off-balance Sheet Arrangements

We enter into minority interest and off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant minority interest and off-balance sheet arrangements:

Minority Interest in Finance Subsidiary

· We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis) in August 2001. As managing member, SubOne consolidated Caddis. Steelhead Investors LLC (Steelhead) was an unconsolidated special purpose entity with no relationship to us or any of our subsidiaries. The money invested in Caddis by Steelhead was loaned to SubOne.

· On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis. As a result, a note payable to Caddis was reported as a component of Long-term Debt, the balance of which was $525 million on December 31, 2003. Due to the prospective application of FIN 46, we did not change the presentation of Minority Interest in Finance Subsidiary in periods prior to July 1, 2003.

· The $525 million Caddis note payable was paid off in 2004 at which time SubOne no longer had any requirements or obligations under the structure described above.

AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. We have no ownership interest in the commercial paper conduits and are not required to consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet transaction was entered to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables, and accelerate its cash collections.

During 2004, AEP Credit renewed its sale of receivables agreement through August 24, 2007. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2004, $435 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivables less an allowance for anticipated uncollectible accounts.

Rockport Plant Unit 2

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each respective company are $1.3 billion.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the future payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.

Railcars

In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. At this time, we intend to renew the lease for the full twenty 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 with the future payment obligations included in the lease footnote. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over time from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2004, the maximum potential loss was approximately $32 million ($21 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year to a nonaffiliated company under an operating lease. The sublessee may renew the lease for up to three additional one-year terms. AEP has other railcar lease arrangements that do not utilize this type of financing structure.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payments Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	1,279	$	2,921	$	977	$	7,161	$	12,338
Short-term Debt (b)		23		-		-		-		23
Preferred Stock Subject to Mandatory Redemption (c)		66		-		-		-		66
Capital Lease Obligations (d)		64		97		51		92		304
Noncancelable Operating Leases (d)		291		505		452		2,181		3,429
Fuel Purchase Contracts (e)		1,954		2,599		1,111		1,367		7,031
Energy and Capacity Purchase Contracts (f)		188		342		219		507		1,256
Construction Contracts for Capital Assets (g)		626		90		-		-		716
Total	$	4,491	$	6,554	$	2,810	$	11,308	$	25,163

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	Represents principal only excluding interest.
(c)	See Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries.
(d)	See Note 16.
(e)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(f)	Represents contractual cash flows of energy and capacity purchase contracts.
(g)	Represents only capital assets that are contractual obligations.

As discussed in Note 11 to the Consolidated Financial Statements, our minimum pension funding requirements are not included above as such amounts are discretionary based upon the status of the trust.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. At December 31, 2004, our commitments outstanding under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	103	$	138	$	-	$	1	$	242
Guarantees of the Performance of Outside Parties (b)		10		-		22		109		141
Guarantees of our Performance (c)		439		749		681		8		1,877
Transmission Facilities for Third Parties (d)		45		64		20		24		153
Total Commercial Commitments	$	597	$	951	$	723	$	142	$	2,413

(a)	We have issued standby letters of credit to third parties. These letters of credit cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $242 million with maturities ranging from February 2005 to January 2011. As the parent of all of these subsidiaries, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn.
(b)	See Note 8.
(c)	We have issued performance guarantees and indemnifications for energy trading, Dow Chemical Company financing, Marine Transportation Pollution Control Bonds and sale agreements.
(d)	As construction agent for third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.

Other

Power Generation Facility

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 have subleased the Facility to the Dow Chemical Company (Dow) under a 5-year term with three 5-year renewal terms for a total term of up to 20 years. The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on June 17, 2009. We may extend the term of the Juniper Lease to a total lease term of 30 years. Our lease of the Facility is reported as an owned-asset under a lease financing transaction. Therefore, the asset and related liability for the debt and equity of the facility are recorded on our Consolidated Balance Sheets and the obligations under the lease agreement are excluded from the table of future minimum lease payment in Note 16.

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 with debt financing of up to $494 million and equity of up to $31 million from investors with no relationship to AEP or any of AEP’s subsidiaries.

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 of $520 million. 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.

We have the right to purchase the Facility for the acquisition cost during the last month of the Juniper Lease’s initial term or on any monthly rent payment date during any extended term of the lease. In addition, we may purchase the Facility from Juniper for the acquisition cost at any time during the initial term if we have arranged a sale of the Facility to a nonaffiliated third party. A purchase of the Facility from Juniper by AEP should not alter Dow’s rights to lease the Facility or our contract to purchase energy from Dow as described below. If the lease were renewed for up to a 30-year lease term, then at the end of that 30-year term we may further renew the lease at fair market value subject to Juniper’s approval, purchase the Facility at its acquisition cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper’s acquisition costs, we may be required to make a payment (not to exceed $415 million) to Juniper of the excess of Juniper’s acquisition cost over the proceeds from the sale. We have guaranteed the performance of our subsidiaries to Juniper during the lease term. Because we now report Juniper’s funded obligations related to the Facility on our Consolidated Balance Sheets, the fair value of the liability for our guarantee (the $415 million payment discussed above) is not separately reported.

At December 31, 2004, Juniper’s acquisition costs for the Facility totaled $520 million, and the total acquisition cost for the completed Facility is currently expected to be approximately $525 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR (plus a component for a fixed-rate return on Juniper’s equity investment and an administrative charge). Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Annual payments of approximately $23 million represent future minimum lease payments to Juniper during the initial term. The majority of the payment is calculated using the indexed LIBOR rate (2.55% at December 31, 2004). Annual sublease payments received from Dow are approximately $27 million (substantially based on an adjusted three-month LIBOR rate discussed above).

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has 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 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) 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.

On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP breaches. If the PPA is deemed terminated or found to be unenforceable by the court, 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 claimed termination value damages from TEM. The corporate parent of TEM (Tractebel SA) has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted AEP partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA. The litigation is in the discovery phase, with trial scheduled to begin on March 23, 2005.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the District Court that the PPA has been terminated and (iii) would be pursuing against TEM, and Tractebel SA under the guaranty, damages and the full termination payment value of the PPA.

The uncertainty of the litigation between TEM and ourselves, combined with a substantial oversupply of generation capacity in the markets where we would otherwise sell the power freed up by the TEM contract termination, triggered us to review the project for possible impairment of its reported values. We determined that the value of the Facility was impaired and recorded a $258 million ($168 million net of tax) impairment in December 2003. See “Power Generation Facility” section of Note 10 for further discussion.

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 in the event the Texas retail market developed increased earnings opportunities. No revenue was recorded in 2004 or 2003 related to these sharing agreements, pending resolution of various contractual matters. We expect to resolve the outstanding matters and record the related revenue in 2005. Management is unable to predict with certainty the amount of revenue that will be recorded.

SIGNIFICANT FACTORS

Progress Made on Announced Divestitures

We continued with our announced plan to divest noncore components of our nonregulated assets and certain Texas generation assets in order to recover stranded generation costs. During 2004, we generated $1.4 billion in proceeds from these dispositions. See Note 10 of our Notes to Consolidated Financial Statements within this Annual Report.

We made progress on our planned divestiture of certain Texas generation assets by (1) announcing in June 2004 and September 2004 that we had signed agreements to sell TCC’s 7.81% share of the Oklaunion Power Station to two nonaffiliated co-owners of the plant for approximately $43 million, subject to closing adjustments, (2) announcing in September 2004 that we had signed agreements to sell TCC’s 25.2% share of the STP nuclear plant to two nonaffiliated co-owners of the plant for approximately $333 million, subject to closing adjustments, and (3) closing in July 2004 on the sale of TCC’s remaining generation assets, including eight natural gas plants, one coal-fired plant and one hydro-electric plant for approximately $428 million, net of adjustments. We expect the sales of Oklaunion and STP to be completed in the first half of 2005. Nevertheless, there could be potential delays in receiving necessary regulatory approvals and clearances or in resolving litigation with a third party affecting Oklaunion which could delay the closings. We will file with the PUCT to recover net stranded costs associated with the sales pursuant to Texas Restructuring Legislation. Stranded costs will be calculated on the basis of all generation assets, not individual plants.

We continue to have discussions with various parties on business alternatives for certain of our other noncore investments, which may result in further dispositions in the future. We are involved in discussions to sell our 50% equity interest in Bajio, a 600 MW natural gas-fired facility in Mexico and our 20% equity interest in Pacific Hydro, an operator of renewable energy facilities in the Pacific Rim.

The ultimate timing for a disposition of one or more of these assets will depend upon market conditions and the value of any buyer’s proposal. We believe our remaining noncore assets are stated at fair value. However, we may realize losses from operations or losses or gains upon the eventual disposition of these assets that, in the aggregate, could have a material impact on our results of operations, cash flows and financial condition.

Texas Regulatory Activity

Texas Restructuring

Texas Restructuring Legislation enacted in 1999 provides the framework and timetable to allow retail electricity competition.

The Texas Restructuring Legislation, among other things:

● provides for the recovery of net stranded generation costs and other generation true-up amounts through securitization and nonbypassable wires charges,

● requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility,

● provides for an earnings test for each of the years 1999 through 2001 and,

● provides for a stranded cost True-up Proceeding after January 10, 2004.

The True-up Proceedings will determine the amount and recovery of:

● net stranded generation plant costs and net generation-related regulatory assets less any unrefunded excess earnings (net stranded generation costs),

● a true-up of actual market prices determined through legislatively-mandated capacity auctions to the projected power costs used in the PUCT’s excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up revenues),

● excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback),

● final approved deferred fuel balance, and

● net carrying costs on true-up amounts.

TCC’s recorded net true-up regulatory asset for amounts subject to approval in the True-up Proceeding is approximately $1.6 billionat December 31, 2004.

The Texas Restructuring Legislation required utilities with stranded generation plant costs to use market-based methods to value certain generation assets for determining stranded generation plant costs. TCC elected to use the sale of assets method to determine the market value of its generation assets for determining stranded generation plant costs. For purposes of the True-up Proceeding, the amount of stranded generation plant costs under this market valuation methodology will be the amount by which the book value of TCC’s generation assets exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets.

In December 2003, based on an expected loss from the sale of its generating assets, TCC recognized as a regulatory asset an estimated impairment of approximately $938 million from the sale of all its generation assets. The impairment was computed based on an estimate of TCC’s generation assets sales price compared to book basis at December 31, 2003. On July 1, 2004, TCC completed the sale of most of its coal, gas and hydro plants for approximately $428 million, net of adjustments. The closings of the sales of STP and Oklaunion plants are expected to occur in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals. In addition, there could be delays in resolving litigation with a third party affecting Oklaunion. On February 15, 2005, TCC filed with the PUCT requesting a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closings of the sales of all the generation assets. TCC asked the PUCT to rule on the request in April 2005.

On December 17, 2004, the PUCT also issued an Order on Rehearing in the CenterPoint True-Up Proceeding (CenterPoint Order). CenterPoint is a nonaffiliated electric utility in Texas. Among other things, the CenterPoint Order provided certain adjustments to stranded generation plant costs to avoid what the PUCT deemed to be duplicative recovery of stranded costs and the capacity auction true-up amount. The CenterPoint Order also confirmed that stranded costs are to be determined as of December 31, 2001, and identified how carrying costs from that date are to be computed.

In the fourth quarter of 2004, TCC made adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis (instead of December 31, 2003 book basis), including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on an applicable PUCT duplicate depreciation adjustment in the CenterPoint Order. These adjustments are reflected as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax in our Consolidated Statements of Operations.

In addition to the two items above (the $938 million impairment in 2003 and the $185 million adjustment in 2004), TCC had recorded $121 million of impairments in 2002 and 2003 on its gas-fired plants. Additionally, other miscellaneous items and the costs to complete the sales, which are still ongoing, of $23 million are included in the recoverable stranded generation plant costs of $897 million.

In the CenterPoint Order, the PUCT specified the manner in which carrying costs should be calculated. In December 2004, TCC computed, based on its interpretation of the methodology contained in the CenterPoint Order, carrying costs of $470 million for the period January 1, 2002 through December 31, 2004 on its stranded generation plant costs net of excess earnings and its wholesale capacity auction true-up regulatory assets at the 11.79% overall pretax cost of capital rate in its UCOS rate proceeding. The embedded 8.12% debt component of the carrying cost of $302 million ($225 million on stranded generation plant costs and $77 million on wholesale capacity auction true-up) was recognized in income in December 2004. This amount is included in Carrying Costs on Texas Stranded Cost Recovery in our Consolidated Statements of Operations. Of the $302 million recorded in 2004, approximately $109 million, $105 million and $88 million related to the years 2004, 2003 and 2002, respectively. The remaining equity component of $168 million will be recognized in income as collected. TCC will continue to accrue a carrying cost at the rate set forth above until it recovers its approved net true-up regulatory asset. If the PUCT further adjusts TCC’s net true-up regulatory asset in TCC’s True-up Proceeding, the carrying cost will also be adjusted.

When the True-up Proceeding is completed, TCC intends to file to recover PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through nonbypassable transition charges and competition transition charges in the regulated T&D rates. TCC will seek to securitize the approved net stranded generation costs plus related carrying costs. The securitizable portion of this net true-up regulatory asset, which consists of net stranded generation costs plus related carrying costs, was $1.4 billion at December 31, 2004. The other approved net true-up items will be recovered or refunded over time through a nonbypassable competition transition wires charge or credit inclusive of a carrying cost. We expect that TCC’s True-up Proceeding filing will seek to recover an amount in excess of the total of its recorded net true-up regulatory asset through December 31, 2004. The PUCT will review TCC’s filing and determine the amount for the recoverable net true-up regulatory assets.

Due to differences between CenterPoint’s and TCC’s facts and circumstances, the lack of direct applicability of certain portions of the CenterPoint Order to TCC and the unknown nature of future developments in TCC’s True-up Proceeding, we cannot, at this time, determine if TCC will incur additional disallowances in its True-up Proceeding. We believe that our recorded net true-up regulatory asset at December 31, 2004 is in compliance with the Texas Restructuring Legislation, and the applicable portions of the CenterPoint Order and other nonaffiliated true-up orders, and we intend to seek vigorously its recovery. If, however, we determine that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset of $1.6 billion at December 31, 2004 and we are able to estimate the amount of such nonrecovery, we will record a provision for such amount, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition. To the extent decisions in the TCC True-up Proceeding differ from management’s interpretation of the Texas Restructuring Legislation and its evaluation of the applicable portions of the CenterPoint and other true-up orders, additional material disallowances are possible.

See “TEXAS RESTRUCTURING” section of Note 6 for further discussion of Texas Regulatory Activity.

TCC Rate Case

On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC’s proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%.

In February 2004, eight intervening parties and the PUCT Staff filed testimony recommending reductions to TCC’s requested $67 million annual rate increase. Their recommendations ranged from a decrease in annual existing rates of approximately $100 million to an increase in TCC’s current rates of approximately $27 million. Hearings were held in March 2004. In May 2004, TCC agreed to a nonunanimous settlement on cost of capital including capital structure and return on equity with all but two parties in the proceeding. TCC agreed that the return on equity should be established at 10.125% based upon a capital structure with 40% equity resulting in a weighted cost of capital of 7.475%. The settlement and other agreed adjustments reduced TCC’s rate request from an increase of $67 million to an increase of $41 million.

On July 1, 2004, the ALJs who heard the case issued their recommendations, which included a recommendation to approve the cost of capital settlement. The ALJs recommended that an issue related to the allocation of consolidated tax savings to the transmission and distribution utility be remanded back to the ALJs for additional evidence. On July 15, 2004, the PUCT remanded this issue to the ALJs. On August 19, 2004, in a separate ruling, the PUCT remanded six other issues to the ALJs requesting revisions to clarify and support the recommendations in the Proposal for Decision (PFD).

The PUCT ordered TCC to calculate its revenue requirements based upon the recommendations of the ALJs. On July 21, 2004, TCC filed its revenue requirements based upon the recommendations of the ALJs. According to TCC’s calculations, the ALJs’ recommendations would reduce TCC’s annual existing rates between $33 million and $43 million depending on the final resolution of the amount of consolidated tax savings.

On November 16, 2004, the ALJs issued their PFD on remand, increasing their recommended annual rate reduction to a range of $51 million to $78 million, depending on the amount disallowed related to affiliated AEPSC billed expenses. At the January 13, 2005 and January 27, 2005 open meetings, the Commissioners considered a number of issues, but deferred resolution of the affiliated AEPSC billed expenses issue, among other less significant issues, until after additional hearings scheduled for early March 2005. Adjusted for the decisions announced by the Commissioners in January 2005, the ALJs' disallowance would yield an annual rate reduction of a range of $48 million to $75 million. If TCC were to prevail on the affiliated expenses issue and all remaining issues, the result would be an annual rate increase of $6 million. When issued, the PUCT order will affect revenues prospectively. An order reducing TCC’s rates could have a material adverse effect on future results of operations and cash flows.

Ohio Regulatory Activity

The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005.

The PUCO invited default service providers to propose an alternative to all customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo and OPCo filed rate stabilization plans with the PUCO addressing prices for the three-year period following the end of the MDP, January 1, 2006 through December 31, 2008. The plans are intended to provide price stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP’s generation resources that serve Ohio customers. On January 26, 2005, the PUCO approved the plans with some modifications.

The approved plans include annual, fixed increases in the generation component of all customers’ bills (3% a year for CSPCo and 7% a year for OPCo) in 2006, 2007 and 2008. The plan also includes the opportunity to annually request an additional increase in supply prices averaging up to 4% per year for each company to recover certain new governmentally mandated increased expenditures set out in the approved plan. The plans maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level in effect on December 31, 2005. Such rates could be adjusted with PUCO approval for specified reasons. Transmission charges could also be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion and ancillary services. The approved plans provide for the continued amortization and recovery of stranded transition generation-related regulatory assets. The plans, as modified by the PUCO, require CSPCo and OPCo to allot a combined total of $14 million of previously provided unspent shopping incentives for the benefit of their low-income customers and economic development over the three-year period ending December 31, 2008 which will not have an effect on net income. The plans also authorized each company to establish unavoidable riders applicable to all distribution customers in order to be compensated in 2006 through 2008 for certain new costs incurred in 2004 and 2005 of fulfilling the companies’ Provider of Last Resort (POLR) obligations. These costs include RTO administrative fees and congestion costs net of financial transmission revenues and carrying cost of environmental capital expenditures. As a result, in 2005, CSPCo and OPCo expect to record regulatory assets of $8 million and $21 million, respectively, for the subject costs related to 2004 and $14 million and $52 million, respectively, for expected subject costs related to 2005. These regulatory assets, totaling $22 million for CSPCo and $73 million for OPCo, will be amortized as the costs are recovered through POLR riders in 2006 through 2008. The riders, together with the fixed annual increases in generation rates are estimated to provide additional cumulative revenues to CSPCo and OPCo of $190 million and $500 million, respectively, in the three-year period ended December 31, 2008. Other revenue increases may occur related to other provisions of the plans discussed above.

On February 25, 2005, various intervenors filed Applications for Rehearing with the PUCO regarding their approval of the rate stabilization plans.  Management expects the PUCO to address the applications before the end of March 2005.  Management cannot predict the ultimate impact these proceedings will have on the results of operations and cash flows.

See “OHIO RESTRUCTURING” section of Note 6 for further discussion of Ohio Regulatory Activity.

Oklahoma Regulatory Activity

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery 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 submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. PSO filed testimony in February 2004.

An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested that $9 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated off-system sales margins between and among AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and, if corrected, could more than offset the $44 million 2002 reallocation under-recovery. The intervenor and the OCC Staff also argued that off-system sales margins were allocated incorrectly. The intervenors’ reallocation of such margins would reduce PSO’s recoverable fuel costs by $7 million for 2000 and $11 million for 2001, while under the OCC Staff method, the reduction for 2001 would be $9 million. The intervenor and the OCC Staff also recommended recalculation of PSO’s fuel costs for years subsequent to 2001 using the same revised methods. At a June 2004 prehearing conference, PSO questioned whether the issues in dispute were under the jurisdiction of the OCC because they relate to FERC-approved allocation agreements. As a result, the ALJ ordered that the parties brief the jurisdictional issue. After reviewing the briefs, the ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. In January 2005, the OCC conducted a hearing on the jurisdictional matter and a ruling is expected in the near future. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

PSO Rate Review

In February 2003, the OCC Staff filed an application requiring PSO to file all documents necessary for a general rate review. In October 2003 and June 2004, PSO filed financial information and supporting testimony in response to the OCC Staff’s request. PSO’s initial response indicated that its annual revenues were $36 million less than costs. The June 2004 filing updated PSO’s request and indicated a $41 million revenue deficiency. As a result, PSO sought OCC approval to increase its base rates by that amount, which is a 3.9% increase over PSO’s existing revenues.

In August 2004, PSO filed a motion to amend the timeline to consider new service quality and reliability requirements, which took effect on July 1, 2004. Also in August 2004, the OCC approved a revised schedule. In October 2004, PSO filed supplemental information requesting consideration of approximately $55 million of additional annual operations and maintenance expenses and annual capital costs to enhance system reliability. In November 2004, PSO filed a plan with the OCC seeking interim rate relief to fund a portion of the costs to meet the new state service quality and reliability requirements pending the outcome of the current case. In the filing, PSO sought interim approval to collect annual incremental distribution tree trimming costs of approximately $23 million from its customers. Intervenors and the OCC Staff filed testimony recommending that the interim rate relief requested by PSO be modified or denied. The OCC issued an order on PSO’s interim request in January 2005, which allows PSO to recover up to an additional $12 million annually for reliability activities beginning in December 2004. Expenses exceeding that amount and the amount currently included in base rates will be considered in the base rate case.

The OCC Staff and intervenors filed testimony regarding their recommendations on revenue requirement, fuel procurement, resource planning and vegetation management in January 2005. Their recommendations ranged from a decrease in annual existing rates between $15 million and $36 million. In addition, one party recommended that the OCC require PSO file additional information regarding its natural gas purchasing practices. In the absence of such a filing, this party suggested that $30 million of PSO’s natural gas costs not be recovered from customers because it failed to implement a procurement strategy that, according to this party, would have resulted in lower natural gas costs. OCC Staff and intervenors recommended a return on common equity ranging from 9.3% to 10.11%. PSO’s rebuttal testimony was filed in February 2005, and that testimony reflects a number of adjustments to PSO’s June 2004 updated filing. These adjustments result in a decrease of PSO’s revenue deficiency from $41 million to $28 million, although approximately $9 million of that decrease are items that would be recovered through the fuel adjustment clause rather than through base rates. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

FERC Order on Regional Through and Out Rates

In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (MISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and expanded PJM regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners including AEP East companies under the RTOs’ revenue distribution protocols.

In November 2003, the FERC issued an order finding that the T&O rates of the former Alliance RTO participants, including AEP, should also be eliminated for transactions within the Combined Footprint. The order directed the RTOs and former Alliance RTO participants to file compliance rates to eliminate T&O rates prospectively within the Combined Footprint and simultaneously implement a load-based transitional rate mechanism called the seams elimination cost allocation (SECA), to mitigate the lost T&O revenues for a two-year transition period beginning April 1, 2004. The FERC was expected to implement a new rate design after the two-year period. In April 2004, the FERC approved a settlement that delayed elimination of T&O rates and the implementation of SECA replacement rates until December 1, 2004 when the FERC would implement a new rate design.

On November 18, 2004, the FERC conditionally approved a license plate rate design to eliminate rate pancaking for transmission service within the Combined Footprint and adopted its previously approved SECA transition rate methodology to mitigate the effects of the elimination of T&O rates effective December 1, 2004. Under license plate rates, customers serving load within a RTO pay transmission service rates based on the embedded cost of the transmission facilities in the local pricing zone where the load being served is located. The use of license plate rates would shift costs that we previously recovered from our T&O service customers to mainly AEP’s native load customers within the AEP East pricing zone. The SECA transition rates will remain in effect through March 31, 2006. The SECA rates are designed to mitigate the loss of revenues due to the elimination of T&O rates.

The SECA rates became effective December 1, 2004. Billing statements from PJM for December 2004 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP accrued $11 million in December 2004 for SECA revenues. On January 7, 2005, AEP and Exelon filed joint comments and protest with the FERC including a request that FERC direct PJM and MISO to comply with the FERC decision and collect all SECA revenues due with interest charges for all late-billed amounts. On February 10, 2005, the FERC issued an order indicating that the SECA transition rates would be subject to refund or surcharge and set for hearing all remaining aspects of the compliance filings to the November 18 order, including our request that the FERC direct PJM and MISO begin billing and collecting the SECA transition rates.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA charges was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, or if any increase in the AEP East Companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Pension and Postretirement Benefit Plans

We maintain qualified, defined benefit pension plans (Qualified Plans or Pension Plans), which cover a substantial majority of nonunion and certain union employees, and unfunded, nonqualified supplemental plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans. Additionally, we have entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits. We also sponsor other postretirement benefit plans to provide medical and life insurance benefits for retired employees in the U.S. (Postretirement Plans). The Qualified Plans and Postretirement Plans are collectively “the Plans.”

The following table shows the net periodic cost (credit) for our Pension Plans and Postretirement Plans:

	2004			2003
	(in millions)
Net Periodic Cost (Credit):
Pension Plans	$	40		$	(3	)
Postretirement Plans		141			188
Assumed Rate of Return:
Pension Plans		8.75	%		9.00	%
Postretirement Plans		8.35	%		8.75	%

The net periodic cost is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Plans’ assets. In developing the expected long-term rate of return assumption, we evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. We also considered historical returns of the investment markets as well as our 10-year average return, for the period ended December 2004, of approximately 12%. We anticipate that the investment managers we employ for the Plans will continue to generate long-term returns averaging 8.75%.

The expected long-term rate of return on the Plans’ assets is based on our targeted asset allocation and our expected investment returns for each investment category. Our assumptions are summarized in the following table:

	2004 Actual Pension Plan Asset Allocation			2004 Actual Postretirement Plan Asset Allocation			2005 Target Asset Allocation			Assumed/Expected Long-term Rate of Return
Equity		68	%		70	%		70	%		10.50	%
Fixed Income		25	%		28	%		28	%		5.00	%
Cash and Cash Equivalents		7	%		2	%		2	%		2.00	%
Total		100	%		100	%		100	%
Overall Expected Return (weighted average)											8.75	%

We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation when considered appropriate. Because of a $200 million discretionary contribution to the Qualified Plans at the end of 2004, the actual asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced back to the target allocation in January 2005. We believe that 8.75% is a reasonable long-term rate of return on the Plans’ assets despite the recent market volatility. The Plans’ assets had an actual gain of 13.75% and 23.80% for the twelve months ended December 31, 2004 and 2003, respectively. We will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust them as necessary.

We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2004, we had cumulative losses of approximately $30 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses will result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.”

The method used to determine the discount rate that we utilize for determining future obligations was revised in 2004. Historically, we based it on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings from a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, we changed to a duration based method in which a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody's AA bond index was constructed but with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for the Pension Plans and 5.80% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Plans’ assets of 8.75%, a discount rate of 5.50% and various other assumptions, we estimate that the pension cost for all pension plans will approximate $55 million, $54 million and $61 million in 2005, 2006 and 2007, respectively. We estimate Postretirement Plan cost will approximate $164 million, $155 million and $146 million in 2005, 2006 and 2007, respectively. Future actual cost will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 0.5% basis point change to selective actuarial assumptions are in “Pension and Other Postretirement Benefits” within the “Critical Accounting Estimates” section of this Management’s Financial Discussion and Analysis of Results of Operations.

The value of our Pension Plans’ assets increased to $3.6 billion at December 31, 2004 from $3.2 billion at December 31, 2003. The Qualified Plans paid $265 million in benefits to plan participants during 2004 (nonqualified plans paid $8 million in benefits). The value of our Postretirement Plans’ assets increased to $1.1 billion at December 31, 2004 from $1.0 billion at December 31, 2003. The Postretirement Plans paid $109 million in benefits to plan participants during 2004.

For our underfunded pension plans, the accumulated benefit obligation in excess of plan assets was $474 million and $445 million at December 31, 2004 and 2003, respectively.

A minimum pension liability is recorded for pension plans with an accumulated benefit obligation in excess of the fair value of plan assets. The minimum pension liability for the underfunded pension plans declined during 2004 and 2003, resulting in the following favorable changes, which do not affect earnings or cash flow:

	Decrease in Minimum Pension Liability
	2004			2003
	(in millions)
Other Comprehensive Income	$	(92	)	$	(154	)
Deferred Income Taxes		(52	)		(75	)
Intangible Asset		(3	)		(5	)
Other		(10	)		13
Minimum Pension Liability	$	(157	)	$	(221	)

We made an additional discretionary contribution of $200 million in the fourth quarter of 2004 and intend to make additional discretionary contributions of $100 million per quarter in 2005 to meet our goal of fully funding all qualified pension plans by the end of 2005.

Certain pension plans we sponsor and maintain contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature. We believe that the defined benefit pension plans we sponsor and maintain are in compliance with the applicable requirements of such laws.

Litigation

Federal EPA Complaint and Notice of Violation

See discussion of the Federal EPA Complaint and Notice of Violation within “Significant Factors - Environmental Matters.”

Enron Bankruptcy

In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Bammel storage facility and HPL indemnification matters - In connection with the 2001 acquisition of HPL, we entered into a prepaid arrangement under which we acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipelines pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years.

In January 2004, we filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which we acquired title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million, which increased our investment in HPL. AEP and Enron agreed to release each other from all claims associated with the Bammel facility, including our indemnity claims. The settlement received Bankruptcy Court approval on September 30, 2004 and closed in November 2004. The parties’ respective trading claims and Bank of America’s (BOA) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement.

Enron Bankruptcy -Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (including the 10.5 BCF described in the preceding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, 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 also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate 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 state court in Texas 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. 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 has objected to the Magistrate Judge’s decision and the matter is now before the District Judge.

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 have objected to Enron’s attempted rejection of these agreements.

On January 26, 2005, we sold a 98% limited partner interest in HPL. We have indemnified the buyer of our 98% interest in HPL against any damages resulting from the BOA litigation. The determination of the amount of the gain on sale and the recognition of the gain is dependent on the ultimate resolution of the BOA dispute.

Enron Bankruptcy - Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas related trading transactions. AEP has asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several of our subsidiaries. The parties are currently in nonbinding court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding court-sponsored mediation.

Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ. We expect an initial decision from the ALJ later this year. The SEC will review the initial decision.

Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.

Bank of Montreal Claim

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals with us and claimed that we owed approximately $34 million. In April 2003, we filed a lawsuit against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts and that BOM had acknowledged just prior to the termination and liquidation that it owed us approximately $68 million. We are claiming that BOM owes us at least $45 million related to previously recorded receivables on which we hold approximately $20 million of credit collateral. We have reserved $4 million against these receivables to reflect the risks of loss, based on the low end of a range of valuations calculated for purposes of the litigation and related mediation. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition.

Coal Transportation Dispute

Certain of our subsidiaries, as joint owners of a generating station have disputed transportation costs billed for coal received between July 2000 and the present time. Our subsidiaries have remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, our subsidiaries recorded a provision for possible loss in December 2004. Of the total provision, a share for deregulated subsidiaries affected income in 2004, a share was recorded as a receivable due to partial ownership of the plant by third parties and the remainder was deferred under the operation of a deferred fuel mechanism. Management continues to work toward mitigating the disputed amounts to the extent possible.

Energy Market Investigations

AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission (CFTC), the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquiries and provided the requested information and continued to respond to supplemental data requests from some of these agencies in 2003 and 2004.

In September 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleged that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC sought civil penalties, restitution and disgorgement of benefits. We responded to the complaint in September 2004. In January 2005, we reached settlement agreements totaling $81 million with the CFTC, the U.S. Department of Justice and the FERC regarding investigations of past gas price reporting and gas storage activities, these being all agencies known still to be investigating these matters as to AEP. Our settlements do not admit nor should they be construed as an admission of violation of any applicable regulation or law. We made the settlement payments to the agencies in the first quarter of 2005 in accordance with the respective contractual terms. The agencies have ended their investigations and the CFTC litigation filed in September 2003 has also ended. During 2003 and 2004, we provided for the settlement payments in the amounts of $45 million and $36 million (nondeductible for federal income tax purposes), respectively. We do not expect any impact on 2005 results of operations as a result of these investigations and settlements.

Shareholders’ Litigation

In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty for failure to establish and maintain adequate internal controls and violations of the Employee Retirement Income Security Act (ERISA) were filed against us, certain executives, members of the Board of Directors and certain investment banking firms. All of these actions except the ERISA claims were dismissed during 2004. We intend to defend vigorously against the remaining ERISA actions. See Note 7 for further discussion.

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 has been dismissed from the case. The plaintiff had stated an intention to amend the complaint to add an AEP subsidiary as a defendant. The plaintiff amended the complaint but did not name any AEP company as a defendant. Since then, a number of 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. Management is unable to predict the outcome of these lawsuits but intends to defend vigorously against the claims made in 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 eighteen companies including AEP and AEPES making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. In December 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. We and the other defendants filed a motion to dismiss the complaint which the Court denied in September 2004. We intend to defend vigorously against these claims.

TEM Litigation

See discussion of TEM litigation within the “Financial Condition - Other” section of this Management’s Financial Discussion and Analysis.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and four of our subsidiaries, certain nonaffiliated energy companies and ERCOT alleging violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit. See Note 7 for further discussion.

Other Litigation

We are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on results of operations, cash flows or financial condition.

Potential Uninsured Losses

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

Environmental Matters

There are new environmental control requirements that we expect will result in substantial capital investments and operational costs. The sources of these future requirements include:

· Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO₂), nitrogen oxide (NO_x) and mercury emissions from coal-fired power plants,

· New Clean Water Act rules 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 emissions to address concerns about global climate change.

In addition to achieving full compliance with all applicable legal requirements, we strive to go beyond compliance in an effort to be good environmental stewards. For example, we invest in research, through groups like the Electric Power Research Institute, to develop, implement and demonstrate new emission control technologies. We plan to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. We have a proven record of efficiently producing and delivering electricity while minimizing the impact on the environment. We invested over $2 billion, from 1990 through 2004, to equip many of our facilities with pollution control technologies. We will continue to make investments to improve the air emissions from our fossil fuel generating stations as this is the most cost-effective generation source to meet our customers’ electricity needs.

In 2002, we joined the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program. We committed to reduce or offset approximately 18 million short tons of CO₂ emissions during 2003-2006 below our baseline emissions (i.e. average emission levels during 1998-2001) as adjusted to reflect any changes in our baseline during the commitment period. During 2003, we reduced or offset our emissions by approximately seven million tons below our voluntary emissions cap and, based on preliminary estimates, we anticipate being below our voluntary emissions cap in 2004.

In August 2004, we released “An Assessment of AEP’s Actions to Mitigate the Economic Impacts of Emissions Policies.” The assessment evaluated our operating emissions control technology, planned investment in additional control equipment and risks associated with an uncertain regulatory environment. It concluded that our actions over the past decade constitute a solid foundation for future efforts to address the intersection between environmental policy and business opportunities. It also concluded that irrespective of the uncertainties surrounding potential air emission regulations and possible future mandatory greenhouse gas regulations, the pollution control investments planned over the next six to eight years are sound. The report also details many of the voluntary actions we are undertaking to limit our greenhouse gas emissions and to develop and/or advance future clean energy technologies.

The Current Air Quality Regulatory Framework

The CAA establishes the federal regulatory authority and oversight for emissions from our fossil-fired generating plants. The states, with oversight and approval from the Federal EPA, administer and enforce these laws and related regulations.

Title I of the CAA

National Ambient Air Quality Standards: The Federal EPA periodically reviews the available scientific data for six pollutants and establishes a standard for concentration levels in ambient air for these substances to protect the public welfare and public health with an extra margin for safety. These requirements are known as “national ambient air quality standards” (NAAQS).

The states identify those areas within their state that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). States must develop their individual state implementation plans (SIPs) with the intention of bringing nonattainment areas into compliance with the NAAQS. In developing a SIP, each state must demonstrate that attainment areas will maintain compliance with the NAAQS. This is accomplished by controlling sources that emit one or more pollutants or precursors to those pollutants. The Federal EPA approves SIPs if they meet the minimum criteria in the CAA. Alternatively, the Federal EPA may prescribe a federal implementation plan if they conclude that a SIP is deficient. Additionally, the Federal EPA can impose sanctions, up to and including withholding of federal highway funds, in states that fail to submit an adequate SIP or a SIP that fails to bring nonattainment areas into NAAQS compliance within the time prescribed by the CAA.

The CAA also establishes visibility goals, which are known as the regional haze program, for certain federally designated areas, including national parks. States are required to develop and submit SIP provisions that will demonstrate reasonable progress toward preventing the impairment and remedying any existing impairment of visibility in these federally designated areas.

Each state’s SIP must include requirements to control sources that emit pollutants in that state as well as requirements to control sources that significantly contribute to nonattainment areas in another state. If a state believes that its air quality is impacted by upwind sources outside their borders, that state can submit a petition that asks the Federal EPA to impose control requirements on specific sources in other states if those states’ SIPs do not contain adequate requirements to control those sources. For example, the Federal EPA issued a NO_x Rule in 1997, which affected 22 eastern states (including states in which AEP operates) and the District of Columbia. The NO_x Rule asked these 23 jurisdictions to adopt requirements for utility and industrial boilers and certain other emission sources to employ cost-effective control technologies to reduce NO_x emissions. The purpose of the request was to reduce the contribution from these 23 jurisdictions to ozone nonattainment areas in certain eastern states.

The Federal EPA also granted four petitions filed by certain eastern states seeking essentially the same levels of control on emission sources outside of their states and issued a Section 126 Rule. All of the states in which we operate that were subject to the NO_x Rule have submitted the required SIP revisions. In response, the Federal EPA approved the SIPs. The compliance date for the SIPs implementing the NO_x Rule and the revised Section 126 Rule was May 31, 2004. These requirements apply to most of our coal-fired generating units.

In 2000, the Texas Commission on Environmental Quality (TCEQ) adopted rules requiring significant reductions in NO_x emissions from utility sources, including TCC and SWEPCo. The compliance requirements began in May 2003 for TCC and will begin in May 2005 for SWEPCo.

We installed a variety of emission control technologies to reduce NO_x emissions and to comply with applicable state and federal NO_x requirements. These include selective catalytic reduction (SCR) technology on certain units and other combustion control technologies on a larger number of units.

Our electric generating units are currently subject to other SIP requirements that control SO₂ and particulate matter emissions in all states, and that control NO_x emissions in certain states. Management believes that our generating plants comply with applicable SIP limits for SO₂, NO_x and particulate matter.

Hazardous Air Pollutants: In the 1990 Amendments to the CAA, Congress required the Federal EPA to identify the sources of 188 hazardous air pollutants (HAPs) and to develop regulations that prescribe a level of HAP emission reduction. These reductions must reflect the application of maximum achievable control technology (MACT). Congress also directed the Federal EPA to investigate HAP emissions from the electric utility sector and to submit a report to Congress. The Federal EPA’s 1998 report to Congress identified mercury emissions from coal-fired electric utility units and nickel emissions from oil-fired utility units as sources of HAP emissions that warranted further investigation and possible control.

New Source Performance Standards and New Source Review: The Federal EPA establishes New Source Performance Standards (NSPS) for 28 categories of major stationary emission sources that reflect the best demonstrated level of pollution control. Sources that are constructed or modified after the effective date of an NSPS standard are required to meet those limitations. For example, many electric generating units are regulated under the NSPS for SO₂, NO_x, and particulate matter. Similarly, each SIP must include regulations that require new sources, and major modifications at existing emission sources that result in a significant net increase in emissions, to submit a permit application and undergo a review of available technologies to control emissions of pollutants. These rules are called new source review (NSR) requirements.

Different NSR requirements apply in attainment and nonattainment areas.

In attainment areas:

· An air quality review must be performed, and

· The best available control technology must be employed to reduce new emissions.

In nonattainment areas,

· Requirements reflecting the lowest achievable emission rate are applied to new or modified sources, and

· All new emissions must be offset by reductions in emissions of the same pollutant from other sources within the same control area.

Neither the NSPS nor NSR requirements apply to certain activities, including routine maintenance, repair or replacement, changes in fuels or raw materials that a source is capable of accommodating, the installation of a pollution control project, and other specifically excluded activities.

Title IV of the CAA (Acid Rain)

The 1990 Amendments to the CAA included a market-based emission reduction program designed to reduce the amount of SO₂ emitted from electric generating units by approximately 50 percent from the 1980 levels. This program also established a nationwide cap on utility SO₂ emissions of 8.9 million tons per year. The Federal EPA administers the SO₂ program through an allowance allocation and trading system. Allowances are allocated to specific units based on statutory formulas. Annually each generating unit surrenders one allowance for each ton of SO₂ that it emits. Emission sources may bank their excess allowances for future use or trade them to other emission sources.

Title IV also contains requirements for utility sources to reduce NO_x emissions through the use of available combustion controls. Generating units must meet their specific NO_x emission standards or units under common control may participate in an annual averaging program for that group of units.

Future Reduction Requirements for SO₂, NO_x, and Mercury

In 1997, the Federal EPA adopted more stringent NAAQS for fine particulate matter and ground-level ozone. The Federal EPA finalized designations for fine particulate matter nonattainment areas on December 17, 2004. Approximately 200 counties are included in the nonattainment areas including many rural counties in the Eastern United States where our generating units are located. The Federal EPA has not yet issued a rule establishing planning and control requirements or attainment deadlines for these areas. The Federal EPA finalized designations for ozone nonattainment areas on April 15, 2004. On the same day, the Administrator of the Federal EPA signed a final rule establishing the elements that must be included in SIPs to achieve the new standards, and setting deadlines ranging from 2008 to 2015 for achieving compliance with the final standard, based on the severity of nonattainment. All or parts of 474 counties are affected by this new rule, including many urban areas in the Eastern United States.

The Federal EPA has identified SO₂ and NO_x emissions as precursors to the formation of fine particulate matter. NO_x emissions are also identified as a precursor to the formation of ground-level ozone. As a result, requirements for future reductions in emissions of NO_x and SO₂ from our generating units are highly probable. In addition, the Federal EPA proposed a set of options for future mercury controls at coal-fired power plants.

Multi-emission control legislation is supported by the Bush Administration. This legislation would regulate NO_x, SO₂, and mercury emissions from electric generating plants. We support enactment of a comprehensive, multi-emission legislation so that compliance planning can be coordinated and collateral emission reductions maximized. We believe this legislation would establish stringent emission reduction targets and achievable compliance timetables utilizing a cost-effective nationwide cap and trade program. We believe regulation or legislation will require us to substantially reduce SO₂, NO_x and mercury emissions over the next ten years.

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% in emissions of SO₂, NO_x and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

· The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO₂ and NO_x emissions across the eastern half of the United States (29 states and the District of Columbia) and make progress toward attainment of the fine particulate matter and ground-level ozone NAAQS. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.

· The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.

The CAIR would require affected states to include, in their SIPs, a program to reduce NO_x and SO₂ emissions from coal-fired electric utility units. SO₂ and NO_x emissions would be reduced in two phases, which would be implemented through a cap-and-trade program. Regional SO₂ emissions would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional NO_x emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to implement the SO₂ and NO_x trading programs were proposed in June 2004.

On April 15, 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include “Best Available Retrofit” requirements for individual facilities in their SIPs to address regional haze. The guidance applies to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. The Federal EPA included an alternative “Best Available Retrofit” program based on emissions budgeting and trading programs. For generating units that are affected by the CAIR, described above, the Federal EPA proposed that participation in the trading program under the CAIR would satisfy any applicable “Best Available Retrofit” requirements. However, the guidance preserves the ability of a state to require site-specific installation of pollution control equipment through the SIP for purposes of abating regional haze.

To control and reduce mercury emissions, the Federal EPA published two alternative proposals. The first option requires the installation of MACT on a site-specific basis. Mercury emissions would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and the industry concurs, that there are no commercially available mercury control technologies in the marketplace today that can achieve the MACT standards for bituminous coals, but certain generating units have achieved comparable levels of mercury reduction by installing conventional SO₂ (scrubbers) and NO_x (SCR) emission reduction technologies. The proposed rule imposes significantly less stringent standards on generating plants that burn sub-bituminous coal or lignite. The proposed standards for sub-bituminous coals potentially could be met without installation of mercury control technologies.

The Federal EPA recommends, and we support, a second mercury emission reduction option. The second option would permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. This approach would coordinate the reduction requirements for mercury with the SO₂ and NO_x reduction requirements imposed on the same sources under the CAIR. Coordination is significantly more cost-effective because technologies like scrubbers and SCRs, which can be used to comply with the more stringent SO₂ and NO_x requirements, have also proven effective in reducing mercury emissions on certain coal-fired units that burn bituminous coal. The second option contemplates reducing mercury emissions from 48 million tons to 34 million tons by 2010 and to 15 million tons by 2018. A supplemental proposal including unit-specific allocations and a framework for the emissions budgeting and trading program preferred by the Federal EPA was published in the Federal Register in March 2004. We filed comments on both the initial proposal and the supplemental proposal in June 2004.

The Federal EPA’s proposals are the beginning of a lengthy rulemaking process, which will involve supplemental proposals on many details of the new regulatory programs, written comments and public hearings, issuance of final rules, and potential litigation. In addition, states have substantial discretion in developing their rules to implement cap-and-trade programs, and will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here.

While uncertainty remains as to whether future emission reduction requirements will result from new legislation or regulation, it is certain under either outcome that we will invest in additional conventional pollution control technology on a major portion of our fleet of coal-fired power plants. Finalization of new requirements for further SO₂, NO_x and/or mercury emission reductions will result in the installation of additional scrubbers, SCR systems and/or the installation of emerging technologies for mercury control. The cost of such facilities could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

Estimated Air Quality Environmental Investments

Each of the current and possible future environmental compliance requirements discussed above will require us to make significant additional investments, some of which are estimable. The proposed rules discussed above have not been adopted, will be subject to further revision, and may be the subject of a court challenge and further modifications.

All of our estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including:

· Timing of implementation

· Required levels of reductions

· Allocation requirements of the new rules, and

· Our selected compliance alternatives.

As a result, we cannot estimate our compliance costs with certainty, and the actual costs to comply could differ significantly from the estimates discussed below.

All of the costs discussed below are incremental to our current investment base and operating cost structure. We intend to seek recovery of these expenditures for pollution control technologies, replacement 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.

Estimated Investments for NO_x Compliance

We estimate that we will make future investments of approximately $450 million to comply with the Federal EPA’s NO_x Rule, the TCEQ Rule and other final NO_x-related requirements. Approximately $380 million of these investments are expected to be expended during 2005-2007. As of December 31, 2004, we have invested approximately $1.3 billion to comply with various NO_x requirements.

Estimated Investments for SO₂ Compliance

We are complying with Title IV SO₂ requirements by installing scrubbers, other controls and fuel switching at certain generating units. We also use SO₂ allowances that we:

· Received in the Federal EPA’s annual allowance allocation,

· Obtained through participation in the annual Federal allowance auction,

· Purchased in the market, and

· Obtained as bonus allowances for installing controls early.

Decreasing SO₂ allowance allocations, our diminishing SO₂ allowance bank, and increasing allowance prices in the market will require us to install additional controls on certain of our generating units. We plan to install 3,500 MW of additional scrubbers to comply with our Title IV SO₂ obligations. We invested approximately $97 million during 2004. In total, we estimate these additional capital costs to be approximately $1.2 billion, the remainder of which will be expended during 2005-2007.

Estimated Investments to Comply with Future Reduction Requirements

Our planning assumptions for the levels and timing of emissions reductions parallel the reduction levels and implementation time periods stated in the proposed rules issued by the Federal EPA in January 2004. We have also assumed that the Federal EPA will implement a mercury trading option and will design its proposed cap and trade mechanism for SO₂, NO_x and mercury emissions in a manner similar to existing cap and trade programs. Based on these assumptions, compliance would require additional capital investment of approximately $1.7 billion by 2010, the end of the first phase for each proposed rule. We estimate that we will invest $1 billion of the capital amount through 2007. We also estimate that we would incur accumulated increases in variable operation and maintenance expenses of $150 million for the periods through 2010, due to the costs associated with the maintenance of additional control systems, disposal of scrubber by-products and the purchase of reagents.

If the Federal EPA’s preferred mercury trading option is not implemented, then any alternative mercury control program requiring adherence to MACT standards would have higher implementation costs that could be significant. We cannot currently estimate the nature or amount of these costs. Furthermore, scrubber and SCR technologies could not be deployed at every bituminous-fired plant that we operate within the three-year compliance schedule provided under the proposed MACT rule. These MACT compliance costs, which we are not able to estimate, would be incremental to other cost estimates that we have discussed above.

Between 2010 and 2020, we expect to incur additional costs for pollution control technology retrofits and investment of $1.6 billion. However, the post-2010 capital investment estimates are quite uncertain, reflecting the uncertain nature of future air emission regulatory requirements, technology performance and costs, new pollution control and generating technology developments, among other factors. Associated operation and maintenance expenses for the equipment will also increase during those years. We cannot estimate these additional costs because of the uncertainties associated with the final control requirements and our associated compliance strategy, but these additional costs are expected to be significant.

New Source Review Litigation

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 Federal EPA and a number of states have alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the NSRs 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.

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, eight Northeastern States filed a separate complaint containing the same allegations against the Conesville and Amos plants that the judge disallowed in the pending case. We filed an answer to the complaint in January 2005.

We are unable to estimate the loss or range of loss related to the contingent liability 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, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered from customers.

In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio SIP occurred at the Stuart Station, and seeking injunctive relief and civil penalties. Stuart Station is jointly-owned by CSPCo (26%) and two nonaffiliated utilities. The owners have filed a motion to dismiss portions of the complaint. We believe the allegations in the complaint are without merit, and intend to defend vigorously against this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 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 SWEPCo's Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations made by a terminated AEP employee. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions.

On July 19, 2004, the 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. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of volatile organic compound emissions at the Pirkey Plant, but after investigation determined that further enforcement was not warranted and withdrew the notice on January 5, 2005.

SWEPCo has previously reported to the TCEQ, deviations related to the receipt of off-specification fuel at Knox Lee, the volatile organic compound emissions at Pirkey, and the referenced recordkeeping and reporting requirements and heat input value at Welsh. We have submitted additional responses to the Notice of Enforcement and the notice from the special interest groups. 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.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and nonhazardous materials. We are currently incurring costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances at disposal sites and authorized the Federal EPA to administer the clean-up programs. At year-end 2004, our subsidiaries are named by the Federal EPA as a Potentially Responsible Party (PRP) for four sites. There are six additional sites for which our subsidiaries have received information requests which could lead to PRP designation. Our subsidiaries have also been named potentially liable at seven sites under state law. Liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where we have been named a PRP or defendant, our disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.

While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding our potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, our present estimates do not anticipate material cleanup costs for identified sites for which we have been declared PRPs. If significant cleanup costs were attributed to our subsidiaries in the future under Superfund, results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be included in our electricity prices.

Emergency Release Reporting

Superfund also requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances which cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. The Federal EPA's Complaint seeks an immaterial amount of civil penalties. I&M has requested a hearing and raised several defenses to the claim, including federally permitted release exemption from reporting. Negotiations on the penalty amount are continuing.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated their intent to seek civil penalties.  In February 2005, OPCo provided relevant information that the Federal EPA should consider in advance of any filing.

Global Climate Change

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 carbon dioxide (CO₂), which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol on November 12, 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. Ratification of the treaty by a majority of the countries’ legislative bodies is required for it to be enforceable. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries and is now in effect as of February 2005.

In August 2003, the Federal EPA issued a decision in response to a petition for rulemaking seeking reductions of CO₂ and other greenhouse gas emissions from mobile sources. The Federal EPA denied the petition and issued a memorandum stating that it does not have the authority under the CAA to regulate CO₂ or other greenhouse gas emissions that may affect global warming trends. The Circuit Court of Appeals for the District of Columbia is reviewing these actions.

We have been working with the Bush Administration on a voluntary program aimed at meeting the President’s goal of reducing the greenhouse gas intensity of the economy by 18% by 2012. For many years, we have been a leader in pursuing voluntary actions to control greenhouse gas emissions. We expanded our commitment in this area in 2002 by joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program. We made a voluntary commitment to reduce or offset a total of 18 million tons of CO₂ emissions during 2003-2006 as adjusted to reflect any changes in our baseline during the commitment period.

Carbon Dioxide Public Nuisance Claims

On July 21, 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 and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions allege that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and seek 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. Management believes the actions are without merit and intends to defend vigorously against the claims.

Costs for Spent Nuclear Fuel and Decommissioning

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law I&M and TCC participate in the DOE’s SNF disposal program which is described in the “SNF Disposal” section of Note 7. Since 1983, I&M has collected $333 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. We deposited $118 million of these funds in external trust funds to provide for the future disposal of SNF and remitted $215 million to the DOE. TCC has collected and remitted to the DOE, $61 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date, DOE has failed to comply with the requirements of the Nuclear Waste Policy Act.

As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of TCC and the other STP owners, along with a number of nonaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other nonaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE’s complete failure to perform its contract obligations, and that the utilities’ suits against DOE may continue in court. In January 2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of liability. The case continued on the issue of damages owed to I&M by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against I&M and denied damages. In July 2004, I&M appealed this ruling to the U.S. Court of Appeals for the Federal Circuit. As long as the delay in the availability of a government-approved storage repository for SNF continues, the cost of both temporary and permanent storage of SNF and the cost of decommissioning will continue to increase.

The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2003 estimate the cost to decommission the Cook Plant ranges from $889 million to $1.1 billion in 2003 nondiscounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2004, the total decommissioning trust fund balance for Cook Plant was $791 million, which includes earnings on the trust investments. In May 2004, an updated decommissioning study was completed for STP. The study estimates TCC’s share of the decommissioning costs of STP to be $344 million in nondiscounted 2004 dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2004, the total decommissioning trust fund for TCC’s share of STP was $143 million, which includes earnings on the trust investments. TCC is in the process of selling its ownership interest in STP to two nonaffiliated companies, and upon completion of the sale it is anticipated that TCC will no longer be obligated for nuclear decommissioning liabilities associated with STP. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. I&M and TCC will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, our future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

Clean Water Act Regulation

On July 9, 2004, the Federal EPA published in the Federal Register a rule pursuant to the Clean Water Act that will require all large existing, once-through cooled power plants to meet certain performance standards to reduce the mortality of juvenile and adult fish or other larger organisms pinned against a plant’s cooling water intake screen. All plants must reduce fish mortality by 80% to 95%. A subset of these plants that are located on sensitive water bodies will be required to meet additional performance standards for reducing the number of smaller organisms passing through the water screens and the cooling system. These plants must reduce the rate of smaller organisms passing through the plant by 60% to 90%. Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and small rivers with large generating plants. These rules will result in additional capital and operation and maintenance expenses to ensure compliance. The estimated capital cost of compliance for our facilities, based on the Federal EPA’s analysis in the rule, is $193 million. Any capital costs associated with compliance activities to meet the new performance standards would likely be incurred during the years 2008 through 2010. We have not independently confirmed the accuracy of the Federal EPA’s estimate. The rule has provisions to limit compliance costs. We may propose less costly site-specific performance criteria if our compliance cost estimates are significantly greater than the Federal EPA’s estimates or greater than the environmental benefits. The rule also allows us to propose mitigation (also called restoration measures) that is less costly and has equivalent or superior environmental benefits than meeting the criteria in whole or in part. Several states, electric utilities (including our APCo subsidiary) and environmental groups appealed certain aspects of the rule. We cannot predict the outcome of the appeals.

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 which 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 results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

· it requires assumptions to be made that were uncertain at the time the estimate was made; and

· changes in the estimate or different estimates that could have been selected could have a material effect on our consolidated results of operations or financial condition.

Management has discussed the development and selection of its critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee has reviewed the disclosure relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.

The sections that follow present information about AEP’s most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required - Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

We recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, we match the timing of our expense recognition with the recovery of such expense in regulated revenues. Likewise, we match income with the passage to our customers through regulated revenues in the same accounting period.

We also record regulatory liabilities for refunds, or probable refunds, to customers that have not yet been made.

Assumptions and Approach Used - When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example, changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate of return earned on invested capital and the timing and amount of assets to be recovered through regulated rates. If it is determined that recovery of a regulatory asset is no longer probable, we write-off that regulatory asset as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used - A change in the above assumptions may result in a material impact on our results of operations. Refer to Note 5 of the Notes to Consolidated Financial Statements for further detail related to regulatory assets and liabilities.

Revenue Recognition - Unbilled Revenues

Nature of Estimates Required - We recognize and record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is also estimated. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.

Unbilled revenues included in Revenue were $22 million, $13 million and $7 million, respectively for the years ended December 31, 2004, 2003 and 2002.

Assumptions and Approach Used - The monthly estimate for unbilled revenues is calculated by operating company as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to the occurrence of problems in meter readings, meter drift and other anomalies, a separate monthly calculation determines factors that limit the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are then statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

In addition, an annual comparison to a load research estimate is performed for the East Companies. The annual load research study is an independent unbilled KWH estimate based on a sample of accounts. The unbilled estimate is also adjusted annually for significant differences from the load research estimate.

Effect if Different Assumptions Used - Significant fluctuations in energy demand for the unbilled period, weather impact, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1%.

Revenue Recognition - Accounting for Derivative Instruments

Nature of Estimates Required - Management considers fair value techniques, valuation adjustments related to credit and liquidity, and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used - We measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based on exchange prices and broker quotes. If a quoted market price is not available, we estimate the fair value based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data, and other assumptions. Fair value estimates based upon the best market information available is somewhat subjective in nature and involves uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

We reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing future bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments are based on estimated defaults by counterparties that are calculated using historical default probabilities for companies with similar credit ratings.

We evaluate the probability of the occurrence of the forecasted transaction within the specified time period as provided for in the original documentation related to hedge accounting.

Effect if Different Assumptions Used - There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

The probability that hedged forecasted transactions will occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified in operating income.

For additional information regarding accounting for derivative instruments, see sections labeled Credit Risk and VaR Associated with Risk Management Contracts within “Quantitative and Qualitative Disclosures About Risk Management Activities.”

Long-Lived Assets

Nature of Estimates Required - In accordance with the requirements of SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets are evaluated periodically for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable or the assets meet the held for sale criteria under SFAS 144. These events or circumstances may include the expected ability to recover additional investment in environmental compliance expenditures, the relative pricing of wholesale electricity by region, the anticipated demand and the cost of fuel. If the carrying amount is not recoverable, an impairment is recorded to the extent that the fair value of the asset is less than its book value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For nonregulated assets, an impairment charge would be recorded as a charge against earnings.

Assumptions and Approach Use - The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales, or independent appraisals. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used - In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS 144, the fair value of the asset can vary if different estimates and assumptions would have been used in our applied valuation techniques. In cases of impairment as described in Note 10, we made our best estimate of fair value using valuation methods based on the most current information at that time. We have been in the process of divesting certain noncore assets and their sales values can vary from the recorded fair value as described in Note 10. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

Nature of Estimates Required - We sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. We account for these benefits under SFAS 87, “Employers’ Accounting For Pensions” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”, respectively. See Note 11 of the Notes to Consolidated Financial Statements for more information regarding costs and assumptions for employee retirement and postretirement benefits. The measurement of our pension and postretirement obligations, costs and liabilities is dependent on a variety of assumptions used by our actuaries and us. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.

Assumptions and Approach Used - The critical assumptions used in developing the required estimates include the following key factors:

· discount rate

· expected return on plan assets

· health care cost trend rates

· rate of compensation increases

Other assumptions, such as retirement, mortality, and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used - The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

	Pension Plans						Other Postretirement Benefits Plans
	+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2004 Benefit Obligations:
Discount Rate	$	(175	)	$	182		$	(133	)	$	142
Salary Scale		11			(11	)		4			(4	)
Cash Balance Crediting Rate		(20	)		20			N/A			N/A
Health Care Trend Rate		N/A			N/A			129			(121	)
Expected Return on Assets		N/A			N/A			N/A			N/A
Effect on 2004 Periodic Cost:
Discount Rate		-			1			(11	)		11
Salary Scale		2			(2	)		1			(1	)
Cash Balance Crediting Rate		3			(3	)		N/A			N/A
Health Care Trend Rate		N/A			N/A			19			(18	)
Expected Return on Assets		(17	)		17			(5	)		5

New Accounting Pronouncements

We implemented FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” effective April 1, 2004, retroactive to January 1, 2004. Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost, while the retroactive portion is an actuarial gain to be amortized over the average remaining service period of active employees, to the extent that the gain exceeds FAS 106’s 10 percent corridor.

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. We will implement SFAS 123R in the third quarter of 2005 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to 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 will be based on the grant-date fair value of the equity award. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

We implemented FIN 46R, “Consolidated of Variable Interest Entities,” effective March 31, 2004 with no material impact to our financial statements. FIN 46R is a revision to FIN 46 which interprets the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.

Other Matters

Seasonality

The sale of electric power in our service territories is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of our facilities and the terms when we enter into power contracts. In addition, we have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish our results of operations and may impact cash flows and financial condition.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, natural gas, coal and emission allowances, we have certain market risks inherent in our business activities. These risks include commodity price risk, interest rate risk, foreign exchange risk and credit risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

We have established policies and procedures which allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies have been 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 daily, weekly, and monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, Credit Risk Management, Market Risk Oversight, and 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. The following tables provide information on our risk management activities:

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

This table provides detail on changes in our mark-to-market (MTM) net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets (Liabilities)

Year Ended December 31, 2004

(in millions)

	Utility Operations			Investments-Gas Operations			Investments-UK Operations (h)			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2003	$	286		$	5		$	(246	)	$	45
(Gain) Loss from Contracts   Realized/Settled During the Period (a)		(116	)		(24	)		246			106
Fair Value of New Contracts When   Entered During the Period (b)		11			-			-			11
Net Option Premiums Paid/(Received) (c)		(3	)		(1	)		-			(4	)
Change in Fair Value Due to Valuation   Methodology Changes (d)		3			-			-			3
Changes in Fair Value of Risk   Management Contracts (e)		74			20			(12	)		82
Changes in Fair Value of Risk   Management Contracts Allocated to   Regulated Jurisdictions (f)		22			-			-			22
Total MTM Risk Management Contract   Net Assets (Liabilities) at December 31, 2004	$	277		$	-		$	(12	)		265
Net Cash Flow and Fair Value Hedge Contracts (g)											5
Ending Net Risk Management Assets at   December 31, 2004										$	270

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized gains from risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	The “Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of  Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed in detail within the following pages.
(h)	During 2004, we began to unwind our risk management contracts within the U.K. as part of our planned divestiture of our UK Operations. We completed the sale of substantially all of our operations and assets in the Investments-UK Operations segment in July 2004 and we expect the remaining MTM Risk Management Current Net Liabilities to be finalized in the first quarter of 2005.

Detail on MTM Risk Management Contract Net Assets (Liabilities)

As of December 31, 2004

(in millions)

	Utility Operations			Investments-Gas Operations			Investments-UK Operations			Total
Current Assets	$	392		$	255		$	1		$	648
Noncurrent Assets		354			115			-			469
Total Assets		746			370			1			1,117
Current Liabilities		(282	)		(236	)		(11	)		(529	)
Noncurrent Liabilities		(187	)		(134	)		(2	)		(323	)
Total Liabilities		(469	)		(370	)		(13	)		(852	)
Total Net Assets (Liabilities),excluding Hedges	$	277		$	-		$	(12	)	$	265

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in millions)

	MTM Risk Management Contracts (a)			PLUS: Hedges			Total (b)
Current Assets	$	648		$	89		$	737
Noncurrent Assets		469			1			470
Total MTM Derivative Contract Assets		1,117			90			1,207
Current Liabilities		(529	)		(79	)		(608	)
Noncurrent Liabilities		(323	)		(6	)		(329	)
Total MTM Derivative Contract Liabilities		(852	)		(85	)		(937	)
Total MTM Derivative Contract Net Assets	$	265		$	5		$	270

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets (liabilities) provides two fundamental pieces of information.

· The source of 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 December 31, 2004

(in millions)

	2005			2006			2007			2008			2009			After 2009			Total (c)
Utility Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	(47	)	$	1		$	9		$	-		$	-		$	-		$	(37	)
Prices Provided by Other External Sources -   OTC Broker Quotes  (a)		163			44			34			13			-			-			254
Prices Based on Models and Other Valuation Methods (b)		(6	)		(8	)		2			19			25			28			60
Total	$	110		$	37		$	45		$	32		$	25		$	28		$	277
Investments - Gas Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	21		$	(4	)	$	2		$	-		$	-		$	-		$	19
Prices Provided by Other External Sources -   OTC Broker Quotes (a)		(4	)		(6	)		-			-			-			-			(10	)
Prices Based on Models and Other Valuation Methods (b)		2			(1	)		(1	)		(3	)		(4	)		(2	)		(9	)
Total	$	19		$	(11	)	$	1		$	(3	)	$	(4	)	$	(2	)	$	-
Investments - UK Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	-		$	-		$	-		$	-		$	-		$	-		$	-
Prices Provided by Other External Sources -   OTC Broker Quotes (a)		(10	)		(2	)		-			-			-			-			(12	)
Prices Based on Models and Other Valuation Methods (b)		-			-			-			-			-			-			-
Total	$	(10	)	$	(2	)	$	-		$	-		$	-		$	-		$	(12	)
Total:
Prices Actively Quoted - Exchange Traded Contracts	$	(26	)	$	(3	)	$	11		$	-		$	-		$	-		$	(18	)
Prices Provided by Other External Sources -   OTC Broker Quotes (a)		149			36			34			13			-			-			232
Prices Based on Models and Other Valuation Methods (b)		(4	)		(9	)		1			16			21			26			51
Total	$	119		$	24		$	46		$	29		$	21		$	26		$	265

(a)	Prices provided by other external sources - Reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	Modeled - 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.
(c)	Amounts exclude Cash Flow and Fair Value Hedges.

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 December 31, 2004

Commodity	Transaction Class	Market/Region	Tenor
			(in months)
Natural Gas	Futures	NYMEX/Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	24
	Swaps	Gas East - Northeast, Mid-continent,
		Gulf Coast, Texas	24
	Swaps	Gas West - Rocky Mountains, West Coast	22
	Exchange Option Volatility	NYMEX/Henry Hub	12
Power	Futures	Power East - PJM	36
	Physical Forwards	Power East - Cinergy	24
	Physical Forwards	Power East - PJM West	36
	Physical Forwards	Power East - AEP Dayton (PJM)	24
	Physical Forwards	Power East - NEPOOL	12
	Physical Forwards	Power East - NYPP	24
	Physical Forwards	Power East - ERCOT	48
	Physical Forwards	Power East - Com Ed	24
	Physical Forwards	Power East - Entergy	12
	Physical Forwards	Power West - Palo Verde, North Path 15,    South Path 15, MidColumbia, Mead	36
	Peak Power Volatility (Options)	Cinergy	12
	Peak Power Volatility (Options)	PJM	12
Crude Oil	Swaps	West Texas Intermediate	36
Emissions	Credits	SO2, NOx	48
Coal	Physical Forwards	PRB, NYMEX, CSX	24

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

We are exposed to market fluctuations in energy commodity prices impacting our power and 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 cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The tables below provide detail on effective cash flow hedges under SFAS 133 included in our Balance Sheets. The data in the first table will indicate the magnitude of SFAS 133 hedges that we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. This table further indicates what portions of these hedges are expected to be reclassified into net income in the next 12 months. The second table provides the nature of changes from December 31, 2003 to December 31, 2004.

Information on energy activities is presented separately from interest rate and foreign currency risk management activities. In accordance with GAAP, all amounts are presented net of related income taxes.

Cash Flow Hedges included in Accumulated Other Comprehensive Loss

On the Balance Sheet as of December 31, 2004

(in millions)

	Accumulated Other Comprehensive Income (Loss) After Tax (a)			Portion Expected to be Reclassified to Earnings During the Next 12 Months (b)
Power and Gas	$	23		$	26
Foreign Currency		-			-
Interest Rate		(23	)		(4	)
Total	$	-		$	22

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in millions)

	Power, Gas and Coal			Foreign Currency			Interest Rate			Total
Beginning Balance, December 31, 2003	$	(65	)	$	(20	)	$	(9	)	$	(94	)
Changes in Fair Value (c)		29			-			(21	)		8
Reclassifications from AOCI to Net Income (d)		59			20			7			86
Ending Balance, December 31, 2004	$	23		$	-		$	(23	)	$	-

(a)	“Accumulated Other Comprehensive Income (Loss) After Tax” - Gains/losses are net of related income taxes that have not yet been included in the determination of net income; reported as a separate component of shareholders’ equity on the balance sheet.
(b)	“Portion Expected to be Reclassified to Earnings During the Next 12 Months” - Amount of gains or losses (realized or unrealized) from derivatives used as hedging instruments that have been deferred and are expected to be reclassified into net income during the next 12 months at the time the hedged transaction affects net income.
(c)	“Changes in Fair Value” - Changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(d)	“Reclassifications from AOCI to Net Income” - Gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

Credit Risk

We limit credit risk 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 Investor Service, Standard and Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. Our analysis, in conjunction with the rating agencies’ information, is used 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. At December 31, 2004, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 14.5%, expressed in terms of net MTM assets and net receivables. The concentration in noninvestment grade credit exposure is proportionately higher due to coal exposures related to domestic MTM coal transactions. These exposures were driven by the continued high levels of prices for coal. As of December 31, 2004, 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	$	789	$	147	$	642		-	$	-
Split Rating		87		21		66		3		48
Noninvestment Grade		230		134		96		3		68
No External Ratings:
Internal Investment Grade		161		1		160		3		80
Internal Noninvestment Grade		61		11		50		1		10
Total	$	1,328	$	314	$	1,014		10	$	206

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, 2007. 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 for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information

Estimated Next Three Years

As of December 31, 2004

	2005	2006	2007
Estimated Plant Output Hedged	93%	94%	93%

VaR Associated with Risk Management Contracts

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 December 31, 2004, 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 years:

VaR Model

December 31, 2004				December 31, 2003
(in millions)				(in millions)
End	High	Average	Low	End	High	Average	Low
$3	$19	$5	$1	$11	$19	$7	$4

The 2004 High VaR occurred in January 2004 during a period when international coal and freight prices experienced record high levels and extreme volatility. Within the following month, the VaR returned to levels approaching the average VaR for the year.

Our VaR model results are adjusted using standard statistical treatments to calculate the CCRO VaR reporting metrics listed below.

CCRO VaR Metrics

(in millions)

	December 31, 2004		Average for Year-to-Date 2004		High for Year-to-Date 2004		Low for Year-to-Date 2004
95% Confidence Level, Ten-Day Holding Period	$	10	$	20	$	73	$	5
99% Confidence Level, One-Day Holding Period	$	4	$	8	$	30	$	2

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 $601 million at December 31, 2004 and $1 billion at December 31, 2003. 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 consolidated financial position.

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 and to a lesser degree other commodities, principally coal and emissions. 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 his staff. When risk management activities exceed certain pre-determined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

American Electric Power Company, Inc.:

We have audited the accompanying consolidated balance sheets of American Electric Power Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows, and common shareholders’ equity and comprehensive income (loss), for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and subsidiary companies as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2005 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 142, “Goodwill and Other Intangible Assets,” effective January 1, 2002; SFAS 143, “Accounting for Asset Retirement Obligations,” and EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003; FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003; and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of American Electric Power Company, Inc.:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that American Electric Power Company, Inc. and subsidiary companies (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and the financial statement schedules as of and for the year ended December 31, 2004 of the Company and our reports dated February 28, 2005 expressed an unqualified opinion on those financial statements and the financial statement schedules and included an explanatory paragraph regarding the Company’s adoption of a new accounting pronouncements in 2002, 2003 and 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of American Electric Power Company, Inc. and subsidiary companies (AEP) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. AEP’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

AEP management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2004. In making this assessment we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on our assessment, the company’s internal control over financial reporting was effective as of December 31, 2004.

AEP’s independent registered public accounting firm has issued an attestation report on our assessment of the Company’s internal control over financial reporting. The Report of Independent Registered Public Accounting Firm appears above.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2004, 2003 and 2002

(in millions, except per-share amounts)

	2004			2003			2002
REVENUES
Utility Operations	$	10,513		$	10,869		$	10,446
Gas Operations		3,064			3,099			2,071
Other		480			699			910
TOTAL		14,057			14,667			13,427
EXPENSES
Fuel for Electric Generation		2,949			3,058			2,580
Purchased Energy for Resale		689			707			532
Purchased Gas for Resale		2,807			2,850			1,946
Maintenance and Other Operation		3,611			3,660			4,054
Asset Impairments and Other Related Charges		-			650			318
Depreciation and Amortization		1,300			1,307			1,356
Taxes Other Than Income Taxes		710			681			718
TOTAL		12,066			12,913			11,504
OPERATING INCOME		1,991			1,754			1,923
Interest Income		33			25			21
Carrying Costs on Texas Stranded Cost Recovery		302			-			-
Investment Value Losses		(15	)		(70	)		(321	)
Gain on Disposition of Equity Investments, Net		153			-			-
Other Income		205			240			321
Other Expense		(183	)		(229	)		(323	)
INTEREST AND OTHER CHARGES
Interest Expense		781			814			775
Preferred Stock Dividend Requirements of Subsidiaries		6			9			11
Minority Interest in Finance Subsidiary		-			17			35
TOTAL		787			840			821
INCOME BEFORE INCOME TAXES		1,699			880			800
Income Taxes		572			358			315
INCOME BEFORE DISCONTINUED OPERATIONS,    EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF      ACCOUNTING CHANGES		1,127			522			485
DISCONTINUED OPERATIONS, Net of Tax		83			(605	)		(654	)
EXTRAORDINARY LOSS ON TEXAS STRANDED COST RECOVERY,   Net of Tax		(121	)		-			-
CUMULATIVE EFFECT OF ACCOUNTING CHANGES, Net of Tax
Goodwill and Other Intangible Assets		-			-			(350	)
Accounting for Risk Management Contracts		-			(49	)		-
Asset Retirement Obligations		-			242			-
NET INCOME (LOSS)	$	1,089		$	110		$	(519	)
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING		396			385			332
EARNINGS (LOSS) PER SHARE
Income Before Discontinued Operations, Extraordinary Item and Cumulative Effect   of Accounting Changes	$	2.85		$	1.35		$	1.46
Discontinued Operations		0.21			(1.57	)		(1.97	)
Extraordinary Loss		(0.31	)		-			-
Cumulative Effect of Accounting Changes		-			0.51			(1.06	)
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE)	$	2.75		$	0.29		$	(1.57	)
CASH DIVIDENDS PAID PER SHARE	$	1.40		$	1.65		$	2.40

See Notes to Consolidated Financial Statements

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in millions)

	2004			2003
CURRENT ASSETS
Cash and Cash Equivalents	$	420		$	976
Other Cash Deposits		175			206
Accounts Receivable:
Customers		930			1,155
Accrued Unbilled Revenues		592			596
Miscellaneous		79			83
Allowance for Uncollectible Accounts		(77	)		(124	)
Total Receivables		1,524			1,710
Fuel, Materials and Supplies		852			889
Risk Management Assets		737			766
Margin Deposits		113			119
Other		200			161
TOTAL		4,021			4,827
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		15,969			15,112
Transmission		6,293			6,130
Distribution		10,280			9,902
Other (including gas, coal mining and nuclear fuel)		3,585			3,590
Construction Work in Progress		1,159			1,287
Total		37,286			36,021
Accumulated Depreciation and Amortization		14,485			14,004
TOTAL - NET		22,801			22,017
OTHER NONCURRENT ASSETS
Regulatory Assets		3,601			3,582
Securitized Transition Assets		642			689
Spent Nuclear Fuel and Decommissioning Trusts		1,053			982
Investments in Power and Distribution Projects		154			212
Goodwill		76			78
Long-term Risk Management Assets		470			494
Prepaid Pension Obligations		386			-
Other		831			806
TOTAL		7,213			6,843
Assets of Discontinued Operations and Held for Sale		628			3,094
TOTAL ASSETS	$	34,663		$	36,781

See Notes to Consolidated Financial Statements

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

December 31, 2004 and 2003

				2004			2003
CURRENT LIABILITIES				(in millions)
Accounts Payable				$	1,051		$	1,337
Short-term Debt					23			326
Long-term Debt Due Within One Year (a)					1,279			1,779
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption (a)					66			-
Risk Management Liabilities					608			631
Accrued Taxes					611			620
Accrued Interest					180			207
Customer Deposits					414			379
Other					775			703
TOTAL					5,007			5,982
NONCURRENT LIABILITIES
Long-term Debt (a)					11,008			12,322
Long-term Risk Management Liabilities					329			335
Deferred Income Taxes					4,819			3,957
Regulatory Liabilities and Deferred Investment Tax Credits					2,540			2,395
Asset Retirement Obligations					827			651
Employee Benefits and Pension Obligations					730			667
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2					166			176
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption (a)					-			76
Deferred Credits and Other					411			409
TOTAL					20,830			20,988
Liabilities of Discontinued Operations and Held for Sale					250			1,876
TOTAL LIABILITIES					26,087			28,846
Cumulative Preferred Stock Not Subject to Mandatory Redemption (a)					61			61
Commitments and Contingencies (Note 7)
COMMON SHAREHOLDERS’ EQUITY
Common Stock Par Value $6.50:
		2004	2003
Shares Authorized	600,000,000		600,000,000
Shares Issued	404,858,145		404,016,413
(8,999,992 shares were held in treasury at December 31, 2004 and 2003)					2,632			2,626
Paid-in Capital					4,203			4,184
Retained Earnings					2,024			1,490
Accumulated Other Comprehensive Income (Loss)					(344	)		(426	)
TOTAL					8,515			7,874
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY				$	34,663		$	36,781

(a) See Accompanying Schedules.

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in millions)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income (Loss)	$	1,089		$	110		$	(519	)
Plus: (Income) Loss from Discontinued Operations		(83	)		605			654
Income from Continuing Operations		1,006			715			135
Adjustments for Noncash Items:
Depreciation and Amortization		1,300			1,307			1,356
Accretion of Asset Retirement Obligations		64			59			-
Deferred Income Taxes		291			163			63
Deferred Investment Tax Credits		(29	)		(33	)		(31	)
Cumulative Effect of Accounting Changes		-			(193	)		350
Asset Impairments, Investment Value Losses and Other Related Charges		15			720			639
Carrying Costs on Stranded Cost Recovery		(302	)		-			-
Extraordinary Loss		121			-			-
Amortization of Deferred Property Taxes		(3	)		(2	)		(16	)
Amortization of Cook Plant Restart Costs		-			40			40
Mark-to-Market of Risk Management Contracts		14			(122	)		275
Pension Contributions		(231	)		(58	)		-
Over/Under Fuel Recovery		96			239			13
Gain on Sales of Assets		(159	)		(48	)		(117	)
Change in Other Noncurrent Assets		(187	)		(137	)		(91	)
Change in Other Noncurrent Liabilities		134			(171	)		(124	)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		298			363			(238	)
Fuel, Materials and Supplies		33			(52	)		(73	)
Accounts Payable		(325	)		(632	)		(21	)
Taxes Accrued		427			87			(222	)
Customer Deposits		35			194			23
Interest Accrued		-			(5	)		72
Other Current Assets		(35	)		(5	)		65
Other Current Liabilities		34			(121	)		(31	)
Net Cash Flows From Operating Activities		2,597			2,308			2,067
INVESTING ACTIVITIES
Construction Expenditures		(1,693	)		(1,358	)		(1,685	)
Change in Other Cash Deposits, Net		31			(91	)		(84	)
Investment in Discontinued Operations, Net		(59	)		(615	)		-
Proceeds from Sale of Assets		1,357			82			1,263
Other		(12	)		3			44
Net Cash Flows Used For Investing Activities		(376	)		(1,979	)		(462	)
FINANCING ACTIVITIES
Issuance of Common Stock		17			1,142			656
Issuance of Long-term Debt		682			4,761			2,893
Issuance of Equity Unit Senior Notes		-			-			334
Change in Short-term Debt, Net		(400	)		(2,781	)		(1,248	)
Retirement of Long-term Debt		(2,511	)		(2,707	)		(2,513	)
Retirement of Preferred Stock		(10	)		(9	)		(10	)
Retirement of Minority Interest		-			(225	)		-
Dividends Paid on Common Stock		(555	)		(618	)		(793	)
Net Cash Flows Used For Financing Activities		(2,777	)		(437	)		(681	)
Effect of Exchange Rate Change on Cash		-			-			(3	)
Net Increase (Decrease) in Cash and Cash Equivalents		(556	)		(108	)		921
Cash and Cash Equivalents at Beginning of Period		976			1,084			163
Cash and Cash Equivalents at End of Period	$	420		$	976		$	1,084
Net Increase (Decrease) in Cash and Cash Equivalents from   Discontinued Operations	$	(13	)	$	(10	)	$	(116	)
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period		13			23			139
Cash and Cash Equivalents from Discontinued Operations - End of Period	$	-		$	13		$	23

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY AND

COMPREHENSIVE INCOME (LOSS)

(in millions)

			Common Stock										Accumulated Other Comprehensive Income (Loss)
			Shares		Amount		Paid-in Capital			Retained Earnings						Total
DECEMBER 31, 2001				331	$	2,153	$	2,906		$	3,296		$	(126	)	$	8,229
Issuance of Common Stock				17		108		568									676
Common Stock Dividends											(793	)					(793	)
Common Stock Expense								(30	)								(30	)
Other								(31	)		15						(16	)
TOTAL																	8,066
COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Net of Tax:
		Foreign Currency Translation Adjustments, Net of Tax of $0												117			117
		Cash Flow Hedges, Net of Tax of $2												(13	)		(13	)
		Securities Available for Sale, Net of Tax of $1												(2	)		(2	)
		Minimum Pension Liability, Net of Tax of $315												(585	)		(585	)
NET LOSS											(519	)					(519	)
TOTAL COMPREHENSIVE LOSS																	(1,002	)
DECEMBER 31, 2002				348		2,261		3,413			1,999			(609	)		7,064
Issuance of Common Stock				56		365		812									1,177
Common Stock Dividends											(618	)					(618	)
Common Stock Expense								(35	)								(35	)
Other								(6	)		(1	)					(7	)
TOTAL																	7,581
COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Net of Tax:
		Foreign Currency Translation Adjustments, Net of Tax of $0												106			106
		Cash Flow Hedges, Net of Tax of $42												(78	)		(78	)
		Securities Available for Sale, Net of Tax of $0												1			1
		Minimum Pension Liability, Net of Tax of $75												154			154
NET INCOME											110						110
TOTAL COMPREHENSIVE INCOME																	293
DECEMBER 31, 2003				404		2,626		4,184			1,490			(426	)		7,874
Issuance of Common Stock				1		6		11									17
Common Stock Dividends											(555	)					(555	)
Other								8									8
TOTAL																	7,344
COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Net of Tax:
	Foreign Currency Translation Adjustments, Net of Tax of $0													(104	)		(104	)
	Cash Flow Hedges, Net of Tax of $51													94			94
	Minimum Pension Liability, Net of Tax of $52													92			92
NET INCOME											1,089						1,089
TOTAL COMPREHENSIVE INCOME																	1,171
DECEMBER 31, 2004				405	$	2,632	$	4,203		$	2,024		$	(344	)	$	8,515

See Notes to Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES

December 31, 2004 and 2003

	December 31, 2004
	Call	Shares	Shares	Amount
	Price Per Share (a)	Authorized (b)	Outstanding (d)	(in millions)
Not Subject to Mandatory Redemption:
4.00% - 5.00%	$102-$110	1,525,903	607,662	$	61
Subject to Mandatory Redemption:
5.90% (c)	$100	850,000	182,000 (f)		18
6.25% - 6.875% (c)	$100	950,000	482,450 (f)		48
Total Subject to Mandatory Redemption (c)					66
Total Preferred Stock				$	127	(e)

	December 31, 2003
	Call	Shares	Shares	Amount
	Price Per Share (a)	Authorized (b)	Outstanding (d)	(in millions)
Not Subject to Mandatory Redemption:
4.00% - 5.00%	$102-$110	1,525,903	607,940	$	61
Subject to Mandatory Redemption:
5.90% - 5.92% (c)	$100	1,950,000	278,100		28
6.25% - 6.875% (c)	$100	950,000	482,450		48
Total Subject to Mandatory Redemption (c)					76
Total Preferred Stock				$	137	(e)

(a)	At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares.
(b)	As of December 31, 2004, the subsidiaries had 13,823,127 shares of $100 par value preferred stock, 22,200,000 shares of $25 par value preferred stock and 7,822,164 shares of no par value preferred stock that were authorized but unissued. As of December 31, 2003, the subsidiaries had 13,780,352 shares of $100 par value preferred stock, 22,200,000 shares of $25 par value preferred stock and 7,768,561 shares of no par value preferred stock that were authorized but unissued.
(c)	Shares outstanding and related amounts are stated net of applicable retirements through sinking funds (generally at par) and reacquisitions of shares in anticipation of future requirements. The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.
(d)	The number of shares of preferred stock redeemed is 96,378 shares in 2004, 86,210 shares in 2003 and 106,458 shares in 2002.
(e)	Due to the implementation of SFAS 150 in July 2003, Cumulative Preferred Stocks of Subsidiaries is no longer presented as one line item on the balance sheet. SFAS 150 has required us to present Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a liability. Cumulative Preferred Stocks of Subsidiaries Not Subject to Mandatory Redemption will continue to be reported separately on the balance sheet.
(f)	All outstanding shares were redeemed on January 3, 2005.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

			Weighted Average	Interest Rates at December 31,		December 31,
Maturity			Interest Rate December 31, 2004	2004	2003	2004			2003
						(in millions)
FIRST MORTGAGE BONDS (a)
	2004-2008 (b)		6.91%	6.20%-8.00%	6.125%-8.00%	$	456		$	694
	2024-2025		8.00%	8.00%	6.875%-8.00%		45			246
INSTALLMENT PURCHASE   CONTRACTS (c)
	2004-2009		3.58%	1.75%-4.55%	2.15%-6.90%		163			350
	2011-2022		3.98%	1.70%-6.10%	1.10%-8.20%		785			943
	2023-2038		4.39%	1.125%-6.55%	1.20%-6.55%		825			733
NOTES PAYABLE (d)
	2004-2017		4.98%	2.325%-15.25%	1.537%-15.45%		939			1,518
SENIOR UNSECURED NOTES
	2004-2009		5.22%	2.879%-6.91%	2.43%-7.45%		3,459			3,707
	2010-2015		5.30%	4.40%-6.375%	4.40%-6.375%		2,633			2,525
	2032-2038		6.32%	5.625%-6.65%	5.625%-7.375%		1,625			1,765
SECURITIZATION BONDS
	2007-2017		5.67%	3.54%-6.25%	3.54%-6.25%		698			746
NOTES PAYABLE TO TRUST
	2037-2043		5.25%	5.25%	5.25%-8.00%		113			331
EQUITY UNIT SENIOR NOTES (e)
	2007		5.75%	5.75%	5.75%		345			345
OTHER LONG-TERM DEBT (f)							243			247
Equity Unit Contract Adjustment Payments		(g)					9			19
Unamortized Discount (net)							(51	)		(68	)
Total Long-term Debt Outstanding							12,287			14,101
Less Portion Due Within One Year							1,279			1,779
Long-term Portion						$	11,008		$	12,322

(a)	First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment. There are certain limitations on establishing additional liens against our assets under our indentures.
(b)	In May 2004, we deposited cash and treasury securities with a trustee to defease all of TCC’s outstanding First Mortgage Bonds. The defeased TCC First Mortgage Bonds had balances of $84 million and $118 million in 2004 and 2003, respectively. Trust fund assets related to this obligation of $72 million are included in Other Cash Deposits and $22 million are included in Other Noncurrent Assets in the Consolidated Balance Sheets at December 31, 2004. Trust fund assets are restricted for exclusive use in funding the interest and principal due on the First Mortgage Bonds.
(c)	For certain series of installment purchase contracts, interest rates are subject to periodic adjustment. Certain series will be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and standby bond purchase agreements support certain series.
(d)	Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
(e)	In May 2005, the interest rate on these Equity Unit Senior Notes can be reset through a remarketing.
(f)	Other long-term debt consists of fair market value of adjustments of fixed rate debt that is hedged, a liability along with accrued interest for disposal of spent nuclear fuel (see “Nuclear” section of Note 7) and a financing obligation under a sale and leaseback agreement.
(g)	The Equity Unit Contract Adjustment Payments settle in August 2005 and as a result the amount is classified as due within one year.

LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2004 IS PAYABLE AS FOLLOWS:

	2005		2006		2007		2008		2009		After 2009		Total
	(in millions)
Principal Amount	$	1,279	$	1,659	$	1,262	$	575	$	402	$	7,161	$	12,338
Unamortized Discount														(51	)
													$	12,287

AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES

INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Summary of Significant Accounting Policies
2.	New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting  Changes
3.	Goodwill and Other Intangible Assets
4.	Rate Matters
5.	Effects of Regulation
6.	Customer Choice and Industry Restructuring
7.	Commitments and Contingencies
8.	Guarantees
9.	Sustained Earnings Improvement Initiative
10.	Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Held for Sale and Assets Held and Used
11.	Benefit Plans
12.	Stock-Based Compensation
13.	Business Segments
14.	Derivatives, Hedging and Financial Instruments
15.	Income Taxes
16.	Leases
17.	Financing Activities
18.	Unaudited Quarterly Financial Information
19.	Subsequent Event

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by our eleven domestic electric utility operating companies is the generation, transmission and distribution of electric power. These companies are subject to regulation by the FERC under the Federal Power Act and maintain accounts in accordance with FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. During 2003, we announced plans to significantly restructure and dispose of our nonregulated operations. See Note 10 for a discussion of the impacts of these plans on our organization.

We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States. In addition, our domestic operations include nonregulated independent power and cogeneration facilities, coal mining and intra-state natural gas operations in Texas. In January 2005, we sold a 98% interest in our natural gas operations in Texas. We sold our natural gas operations in Louisiana in 2004.

We are in the process of completing our divestitures of our noncore assets, including most of our international operations. Our current international portfolio includes only limited investments in the generation and supply of power in Mexico and the Pacific Rim. We sold our generation assets in the U.K. and China in 2004. In 2002, we sold our investments in international distribution companies in Australia and the U.K.

We also conduct domestic barging operations and provide various energy-related services.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rate Regulation

We are subject to regulation by the SEC under the PUHCA. The rates charged by the utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations. Wholesale power markets are generally market-based and are not cost-based regulated unless a generator/seller of wholesale power is determined by the FERC to have “market power.” The FERC also regulates transmission service and rates particularly in states that have restructured and unbundled their rates. The state commissions regulate all or portions of our retail operations and retail rates dependent on the status of customer choice in each state jurisdiction (see Note 6).

Principles of Consolidation

Our consolidated financial statements include AEP and its wholly-owned and majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or substantially controlled variable interest entities (VIE). Intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method of accounting; equity earnings are included in Other Income. We also consolidate variable interest entities in accordance with FASB Interpretation Number (FIN) 46 (revised December 2003) “Consolidation of Variable Interest Entities” (FIN 46R) (seeNote 2). We also have generating units that are jointly owned with nonaffiliated companies. Our proportionate share of the operating costs associated with such facilities is included in our Consolidated Statements of Operations and the investments are reflected in our Consolidated Balance Sheets.

Accounting for the Effects of Cost-Based Regulation

As the owner of cost-based rate-regulated electric public utility companies, our consolidated financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71, “Accounting for the Effects of Certain Types of Regulation”, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. We discontinued the application of SFAS 71 for the generation portion of our business as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by TCC, TNC, and SWEPCo in September 1999, in Arkansas by SWEPCo in September 1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo reapplied SFAS 71 for its West Virginia generation operations and SWEPCo reapplied SFAS 71 for its Arkansas generation operations. SFAS 101, “Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71” requires the recognition of an impairment of a regulatory asset arising from the discontinuance of SFAS 71 be classified as an extraordinary item.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include but are not limited to inventory valuation, allowance for doubtful accounts, goodwill and intangible asset impairment, unbilled electricity revenue, values of long-term energy contracts, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could differ from those estimates.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of the nonregulated operations and other investments are stated at their fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are charged to accumulated depreciation. For nonregulated operations, retirements from the plant accounts, net of salvage, are charged to accumulated depreciation and removal costs are charged to expense. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses.

We implemented SFAS 143 effective January 1, 2003 (see “Accounting for Asset Retirement Obligations (ARO)” section of this note).

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets is no longer recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Equity investments are required to be tested for impairment when it is determined that an other than temporary loss in value has occurred.

The fair value of an asset and investment is the amount at which that asset and investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Depreciation, Depletion and Amortization

We provide for depreciation of property, plant and equipment on a straight-line basis over the estimated useful lives of property, excluding coal-mining properties, generally using composite rates by functional class as follows:

Functional Class of Property		Annual Composite Depreciation Rate Ranges
		2004	2003	2002
Production:
	Steam-Nuclear	3.1%	2.5% to 3.4%	2.5% to 3.4%
	Steam-Fossil-Fired	2.6% to 4.5%	2.3% to 4.6%	2.6% to 4.5%
	Hydroelectric-Conventional and Pumped Storage	2.6% to 3.3%	1.9% to 3.4%	1.9% to 3.4%
Transmission		1.7% to 3.0%	1.7% to 3.1%	1.7% to 3.0%
Distribution		3.2% to 4.1%	3.3% to 4.2%	3.3% to 4.2%
Other		4.9% to 16.4%	5.2% to 16.7%	4.7% to 9.9%

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. Average amortization rates for coal rights and mine development costs were $0.65 per ton in 2004, $0.25 per ton in 2003 and $0.32 per ton in 2002. In 2004, average amortizations rates increased from 2003 due to a lower tonnage nomination from the power plant yielding a higher cost per ton. In addition, coal mining assets amortized at a lower rate were sold in 2004. In 2002, certain coal-mining assets were impaired by $60 million leading to the decline in amortization rates in 2003.

For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for nonasset retirement obligation (non-ARO) removal costs, which is credited to accumulated depreciation. Actual removal costs incurred are debited to accumulated depreciation. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from accumulated depreciation and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred (see “Accounting for Asset Retirement Obligations (ARO)” section of this note).

Accounting for Asset Retirement Obligations (ARO)

We implemented SFAS 143 effective January 1, 2003. SFAS 143 requires entities to record a liability at fair value for any legal obligations for future asset retirements when the related assets are acquired or constructed. Upon establishment of a legal liability, SFAS 143 requires a corresponding ARO asset to be established, which will be depreciated over its useful life. ARO accounting is being followed for regulated and nonregulated property that has a legal removal obligation. Upon removal of ARO property, any difference between the ARO accrual and actual removal costs is recognized as income or expense. The following is a reconciliation of 2003 and 2004 aggregate carrying amount of asset retirement obligations:

	Nuclear Decommissioning			Ash Ponds			U.K. Plants, Wind Mills and Mining Operations			Total
	(in millions)
ARO Liability at January 1, 2003 Including Held for Sale	$	718.3		$	69.8		$	37.2		$	825.3
Accretion Expense		52.6			5.6			2.3			60.5
Liabilities Incurred		-			-			8.3			8.3
Foreign Currency Translation		-			-			5.3			5.3
ARO Liability at December 31, 2003 Including Held for Sale		770.9			75.4			53.1			899.4
Less ARO Liability Held for Sale:
South Texas Project (b)		(218.8	)		-			-			(218.8	)
U.K. Plants					-			(28.8	)		(28.8	)
ARO Liability at December 31, 2003	$	552.1		$	75.4		$	24.3		$	651.8
ARO Liability at January 1, 2004 Including Held for Sale	$	770.9		$	75.4		$	53.1		$	899.4
Accretion Expense		56.5			6.0			2.8			65.3
Foreign Currency Translation		-			-			0.6			0.6
Liabilities Incurred		-			-			17.7			17.7
Liabilities Settled (a)		-			(0.4	)		(56.9	)		(57.3	)
Revisions in Cash Flow Estimates		132.1			3.2			15.0			150.3
ARO Liability at December 31, 2004 Including Held for Sale		959.5			84.2			32.3			1,076.0
Less ARO Liability Held for Sale:   South Texas Project (b)		(248.9	)		-			-			(248.9	)
ARO Liability at December 31, 2004	$	710.6		$	84.2		$	32.3		$	827.1

(a)	Liabilities settled include approximately $45.5 million in noncash reductions of ARO associated with the sale of the U.K. generation assets in July 2004.
(b)	We have signed an agreement to sell TCC’s share of South Texas Project (see Note 10).

Accretion expense is included in Maintenance and Other Operation expense in our accompanying Consolidated Statements of Operations.

As of December 31, 2004 and 2003, the fair values of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $934 million and $845 million, respectively, of which $791 million and $720 million relating to the Cook Plant are recorded in Spent Nuclear Fuel and Decommissioning Trusts in our Consolidated Balance Sheets. The fair values of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities for the South Texas Project totaling $143 million and $125 million as of December 31, 2004 and 2003, respectively, are classified as Assets of Discontinued Operations and Held for Sale in our Consolidated Balance Sheets.

Pro forma net income and earnings per share are not presented for the year ended December 31, 2002 because the pro forma application of SFAS 143 would result in pro forma net income and earnings per share not materially different from the actual amounts reported during that period.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For nonregulated operations, interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.” Capitalized interest is also recorded for domestic generating assets in Ohio, Texas and Virginia, effective with the discontinuance of SFAS 71 regulatory accounting. The amounts of AFUDC and interest capitalized were $37 million, $37 million and $34 million in 2004, 2003 and 2002, respectively.

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Cash Deposits

Other Cash Deposits include funds held by trustees primarily for the payment of debt.

Inventory

Except for PSO and TNC, the domestic utility companies value fossil fuel inventories at the lower of a weighted average cost or market. PSO and TNC record fossil fuel inventories at the lower of cost or market, utilizing the LIFO cost method. Materials and supplies inventories are carried at average cost. Gas inventory is carried at the lower of weighted average cost or market. During 2003, a fair value hedging strategy was implemented for certain gas inventory. Changes in the fair value of hedged inventory were recorded to the extent offsetting hedges are designated against that inventory. In the third quarter of 2004, the fair value hedges were de-designated. As a result, the existing hedged inventory was held at the market price on the fair value hedge de-designation date with subsequent additions to inventory carried at cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.

We recognize revenue from electric power and gas sales when we deliver power or gas to our customers. To the extent that deliveries have occurred but a bill has not been issued, we accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the last billing.

AEP Credit, Inc. factors accounts receivable for certain subsidiaries, including CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be removed from the company’s balance sheets (see “Sale of Receivables” section of Note 17).

Foreign Currency Translation

The financial statements of subsidiaries outside the U.S. that are included in our consolidated financial statements and investments outside the U.S. that are accounted for under the equity method are measured using the local currency as the functional currency and translated into U.S. dollars in accordance with SFAS 52, “Foreign Currency Translation.” Although the effects of foreign currency fluctuations are mitigated by the fact that expenses of foreign subsidiaries are generally incurred in the same currencies in which sales are generated, the reported results of operations of our foreign subsidiaries are affected by changes in foreign currency exchange rates and, as compared to prior periods, will be higher or lower depending upon a weakening or strengthening of the U.S. dollar. Revenues and expenses are translated at monthly average foreign currency exchange rates throughout the year. Assets and liabilities are translated into U.S. dollars at year-end foreign currency exchange rates. Accordingly, our consolidated common shareholders’ equity will fluctuate depending on the relative strengthening or weakening of the U.S. dollar versus relevant foreign currencies. Currency translation gain and loss adjustments are recorded in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The balance of Accumulated Other Comprehensive Income as of December 31, 2004 has been reduced significantly primarily due to the disposition of our U.K. assets in 2004, which is reflected in Discontinued Operations on our Consolidated Statements of Operations. The impact of the changes in exchange rates on cash, resulting from the translation of items at different exchange rates, is shown on our Consolidated Statements of Cash Flows in Effect of Exchange Rate Change on Cash. Actual currency transaction gains and losses are recorded in income when they occur.

Deferred Fuel Costs

The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to ratepayers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to ratepayers) are deferred as regulatory assets. These deferrals are amortized when refunded or when billed to customers in later months with the regulator’s review and approval. The amounts of an over-recovery or under-recovery can also be affected by actions of regulators. When a fuel cost disallowance becomes probable, we adjust our deferrals and record provisions for estimated refunds to recognize these probable outcomes (see Note 4).

In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All or a portion of profits from off-system sales are shared with ratepayers through fuel clauses in Texas (SPP area only), Oklahoma, Louisiana, Arkansas, Kentucky and in some areas of Michigan. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings unless recovered in the sales price for electricity. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes have impacted earnings. The Michigan fuel clause suspension ended December 31, 2003, and the Indiana freeze ended on March 1, 2004. Through subsequent orders, the Indiana Utility Regulatory Commission (IURC) has authorized the billing of capped fuel rates on an interim basis until April 1, 2005. In Indiana, there is an issue as to whether the freeze should be extended through 2007 under an existing corporate separation stipulation agreement. Management disagrees with this interpretation of the stipulation and the matter is pending resolution. In West Virginia, the fuel clause is suspended indefinitely. Changes in fuel costs also impact earnings for certain of our IPP generating units that do not have long-term contracts for their fuel supply or have not hedged fuel costs (see Notes 4 and 6).

Revenue Recognition

Regulatory Accounting

Our consolidated financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers in cost-based regulated rates. Regulatory liabilities or regulatory assets are also recorded for unrealized MTM gains or losses that occur due to changes in the fair value of physical and financial contracts that are derivatives and that are subject to the regulated ratemaking process when realized.

When regulatory assets are probable of recovery through regulated rates, we record them as assets on the balance sheet. We test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against earnings. A write-off of regulatory assets also reduces future cash flows since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our statement of operations when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase and sale contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio, Virginia and Texas. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Beginning in July 2004, as a result of the sale of generation assets in AEP's west zone, we are short capacity and must purchase physical power to supply retail and wholesale customers.  For power purchased under derivative contracts in AEP’s west zone, prior to settlement the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period are recognized as Revenues. If the contract results in the physical delivery of power, the previously recorded unrealized gains and losses from MTM valuations are reversed and the settled amounts are recorded gross as Purchased Energy for Resale. If the contract does not physically deliver, the previously recorded unrealized gains and losses from MTM valuations are reversed and the settled amounts are recorded as Revenues in the Consolidated Statement of Operations on a net basis (see Note 14).

Domestic Gas Pipeline and Storage Activities

Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and accounted for using MTM accounting (resale gas contracts). The unrealized and realized gains and losses on resale gas contracts for the sale of natural gas are presented as Revenues in the Consolidated Statement of Operations. The unrealized and realized gains and losses on physically settled resale gas contracts for the purchase of natural gas are presented as Purchased Gas for Resale in the Consolidated Statement of Operations (see Note 14).

Energy Marketing and Risk Management Activities

We engage in wholesale electricity, natural gas, coal and emission allowances marketing and risk management activities. Effective October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts, which include exchange traded futures and options, and over-the-counter options and swaps. Prior to October 2002, we recorded wholesale marketing and risk management activities using the MTM method of accounting.

In October 2002, EITF 02-3 precluded MTM accounting for risk management contracts that were not derivatives pursuant to SFAS 133. We implemented this standard for all nonderivative wholesale and risk management transactions occurring on or after October 25, 2002. For nonderivative risk management transactions entered prior to October 25, 2002, we implemented this standard on January 1, 2003 and reported the effects of implementation as a cumulative effect of an accounting change (see “Accounting for Risk Management Contracts” section of Note 2).

After January 1, 2003, revenues and expenses are recognized from wholesale marketing and risk management transactions that are not derivatives when the commodity is delivered. We use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated for hedge accounting or the normal purchase and sale exemption. The unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in Revenues in the Consolidated Statement of Operations on a net basis. In jurisdictions subject to cost-based regulation, the unrelated MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Where they are included in cost-based regulated rates on a realized basis, the MTM gains and losses are deferred as regulatory assets or liabilities.

Certain wholesale marketing and risk management transactions are designated as a hedge of a forecasted transaction, a future cash flow (cash flow hedge) or as a hedge of a recognized asset, liability or firm commitment (fair value hedge). The gains or losses on derivatives designated as fair value hedges are recognized in Revenues in the Consolidated Statement of Operations in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged. For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the Consolidated Statement of Operations when the forecasted transaction is realized and affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the Consolidated Statement of Operations immediately (see Note 14).

Construction Projects for Outside Parties

We engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue, including the related margin, as project costs are incurred and billed to the outside party.

Maintenance

Maintenance costs are expensed as incurred. If it becomes probable that we will recover specifically incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. Maintenance costs during refueling outages at the Cook Nuclear Plant are deferred and amortized over the period between outages in accordance with rate orders in Indiana and Michigan.

Other Income and Other Expense

Nonoperational revenue including the nonregulated business activities of our utilities, equity earnings of nonconsolidated subsidiaries, gains on dispositions of property, AFUDC-equity and miscellaneous income, are reported in Other Income. Nonoperational expenses including nonregulated business activities of our utilities, losses on dispositions of property, miscellaneous amortization, donations and various other nonrecoverable/nonoperating and miscellaneous expenses, are reported in Other Expense.

AEP Consolidated Other Income and Other Expense:

	December 31,
	2004		2003		2002
	(in millions)
Other Income:
Equity Earnings (Loss)	$	18	$	10	$	(15	)
Nonutility Revenue		127		129		201
Gain on Sale of REPs (Mutual Energy Companies)		-		39		129
Other		60		62		6
Total Other Income	$	205	$	240	$	321
Other Expense:
Nonutility Expense	$	103	$	112	$	179
Property and Miscellaneous Taxes		20		20		20
Other		60		97		124
Total Other Expense	$	183	$	229	$	323

Income Taxes and Investment Tax Credits

We use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment.

Excise Taxes

We act as an agent for some state and local governments and collect from customers certain excise taxes levied by those state or local governments on our customer. We do not recognize these taxes as revenue or expense.

Debt and Preferred Stock

Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Some jurisdictions require that these costs be expensed upon reacquisition. We report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Expense.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The amortization expense is included in interest charges.

We classify instruments that have an unconditional obligation requiring us to redeem the instruments by transferring an asset at a specified date as liabilities on our Consolidated Balance Sheets. Those instruments consist of Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as of December 31, 2004 and 2003. Beginning July 1, 2003, we classify dividends on these mandatorily redeemable preferred shares as Interest Expense. In accordance with SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” dividends from prior periods remain classified as preferred stock dividends, a component of Preferred Stock Dividend Requirements of Subsidiaries, on our Consolidated Statements of Operations.

Where reflected in rates, redemption premiums paid to reacquire preferred stock of certain domestic utility subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series. The excess of par value over the costs of reacquired preferred stock for nonregulated subsidiaries is credited to retained earnings upon reacquisition.

Goodwill and Intangible Assets

When we acquire businesses, we record the fair value of any assets including intangible assets. To the extent that consideration exceeds the fair value of identified assets, we record goodwill. Purchased goodwill and intangible assets with indefinite lives are not amortized. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Goodwill is tested at the reporting unit level and other intangibles are tested at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods. Intangible assets with finite lives are amortized over their respective estimated lives, currently ranging from 5 to 10 years, to their estimated residual values.

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC have established investment limitations and general risk management guidelines. In general, limitations include:

· acceptable investments (rated investment grade or above);

· maximum percentage invested in a specific type of investment;

· prohibition of investment in obligations of the applicable company or its affiliates; and

· withdrawals only for payment of decommissioning costs and trust expenses.

Trust funds are maintained for each regulatory jurisdiction and managed by external investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after tax earnings of the trust giving consideration to liquidity, risk, diversification, and other prudent investment objectives.

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Spent Nuclear Fuel and Decommissioning Trusts for amounts relating to the Cook Plant and are included in Assets of Discontinued Operations and Held for Sale for amounts relating to STP (see “Assets Held for Sale” section of Note 10). These securities are recorded at market value. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Unrealized gains and losses from securities in these trust funds are reported as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.

Comprehensive Income(Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the 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):

	December 31,
	2004			2003
Components	(in millions)
Foreign Currency Translation Adjustments, net of tax	$	6		$	110
Securities Available for Sale, net of tax		(1	)		(1	)
Cash Flow Hedges, net of tax		-			(94	)
Minimum Pension Liability, net of tax		(349	)		(441	)
Total	$	(344	)	$	(426	)

Stock-Based Compensation Plans

At December 31, 2004, we have two stock-based employee compensation plans with outstanding stock options (see Note 12). No stock option expense is reflected in our earnings, as all options granted under these plans had exercise prices equal to or above the market value of the underlying common stock on the date of grant.

We also grant performance share units, phantom stock units, restricted shares and restricted stock units to employees, as well as stock units to nonemployee members of our Board of Directors. The Deferred Compensation and Stock Plan for Non-Employee Directors permits directors to choose to defer up to 100 percent of their annual Board retainer in stock units, and the Stock Unit Accumulation Plan for Non-Employee Directors awards stock units to directors. Compensation cost is included in Net Income (Loss) for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director’s stock units.

The following table shows the effect on our Net Income (Loss) and Earnings (Loss) per Share as if we had applied fair value measurement and recognition provisions of SFAS 123, “Accounting for Stock-Based Compensation,”to stock-based employee compensation awards:

	Year Ended December 31,
	2004			2003			2002
	(in millions, except per share data)
Net Income (Loss), as reported	$	1,089		$	110		$	(519	)
Add: Stock-based compensation expense included in reported net income   (loss), net of related tax effects		15			2			(5	)
Deduct: Stock-based employee compensation expense   determined under fair value based method for all awards,   net of related tax effects		(18	)		(7	)		(4	)
Pro Forma Net Income (Loss)	$	1,086		$	105		$	(528	)
Earnings (Loss) per Share:
Basic - As Reported	$	2.75		$	0.29		$	(1.57	)
Basic - Pro Forma (a)	$	2.74		$	0.27		$	(1.59	)
Diluted - As Reported	$	2.75		$	0.29		$	(1.57	)
Diluted - Pro Forma (a)	$	2.74		$	0.27		$	(1.59	)

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

Earnings Per Share (EPS)

Basic earnings (loss) per common share is calculated by dividing net earnings (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The effects of stock options have not been included in the fiscal 2002 diluted loss per common share calculation as their effect would have been antidilutive.

The calculation of our basic and diluted earnings (loss) per common share (EPS) is based on weighted average common shares shown in the table below:

	2004		2003		2002
	(in millions)
Weighted Average Shares:
Average Common Shares Outstanding		396		385		332
Assumed Conversion of Dilutive Stock Options (see Note 12)		-		-		-
Diluted Average Common Shares Outstanding		396		385		332

The assumed conversion of stock options does not affect net earnings (loss) for purposes of calculating diluted earnings per share. Our basic and diluted EPS are the same in 2004, 2003 and 2002 since the effect on weighted average common shares outstanding is minimal.

Had we reported net income in fiscal 2002, incremental shares attributable to the assumed exercise of outstanding stock options would have increased diluted common shares outstanding by 398,000 shares.

Options to purchase 5.2 million, 5.6 million and 8.8 million shares of common stock were outstanding at December 31, 2004, 2003 and 2002, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the year-end market price of the common shares and, therefore, the effect would be antidilutive.

In addition, there is no effect on diluted earnings per share related to our equity units (issued in 2002) unless the market value of our common stock exceeds $49.08 per share. There were no dilutive effects from equity units at December 31, 2004, 2003 and 2002. If our common stock value exceeds $49.08 we would apply the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contracts are used to repurchase outstanding shares (see “Equity Units” section of Note 17).

Supplementary Information

	Year Ended December 31,
	2004			2003		2002
Related Party Transactions	(in millions)
AEP Consolidated Purchased Power - Ohio Valley Electric Corporation   (44.2% owned by AEP)	$	161		$	147	$	142
AEP Consolidated Other Revenues - barging and other transportation services -   Ohio Valley Electric Corporation (44.2% owned by AEP)		14			9		-
Cash Flow Information
Cash was paid (received) for:
Interest (net of capitalized amounts)		755			741		792
Income Taxes		(107	)		163		336
Noncash Investing and Financing Activities:
Acquisitions Under Capital Leases		120			25		6
Assumption (Disposition) of Liabilities Related to Acquisitions/Divestitures		(67	)		-		1
Increase in assets and liabilities resulting from:
Consolidation of VIEs due to the adoption of FIN 46		-			547		-
Consolidation of merchant power generation facility		-			496		-

Power Projects

We own a 50% interest in a domestic unregulated power plant with a capacity of 450 MW located in Texas and an international power plant totaling 600 MW located in Mexico (see Note 10).

We account for investments in power projects that are 50% or less owned using the equity method and report them as Investments in Power and Distribution Projects on our Consolidated Balance Sheets (see “Eastex” section in Note 10). At December 31, 2004, the 50% owned domestic power project and international power investment are accounted for under the equity method and have unrelated third-party partners. The domestic project is a combined cycle gas turbine that provides steam to a host commercial customer and is considered a Qualifying Facility (QF) under PURPA. The international power investment is classified as a Foreign Utility Company (FUCO) under the Energy Policies Act of 1992.

Both the international and domestic power projects have project-level financing, which is nonrecourse to AEP. In addition, for the international project, AEP has guaranteed $57 million of letters of credit associated with the financing and a $10 million letter of credit for the benefit of the power purchaser under the power supply contract.

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).

2.NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES

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 during 2004 that we have determined relate to our operations.

FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003

We implemented FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” effective April 1, 2004, retroactive to January 1, 2004. The new disclosure standard provides authoritative guidance on the accounting for any effects of the Medicare prescription drug subsidy under the Act. It replaces the earlier FSP FAS 106-1, under which we previously elected to defer accounting for any effects of the Act until the FASB issued authoritative guidance on the accounting for the Medicare subsidy.

Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost, while the retroactive portion is an actuarial gain to be amortized over the average remaining service period of active employees, to the extent that the gain exceeds FAS 106’s 10 percent corridor. See Note 11 for additional information related to the effects of implementation of FAS 106-2 on our postretirement benefit plans.

SFAS 123 (revised 2004) "Share-Based Payment" (SFAS 123R)

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” 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 Accounting Principles Board (APB) Opinion No. 25. The statement is effective as of the first interim or annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement.

We will implement SFAS 123R in the third quarter of 2005 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to 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 will be based on the grant-date fair value of the equity award. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

SFAS 153 “Exchange of Nonmonetary Assets: an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153, “Exchange of Nonmonetary Assets: an amendment of APB Opinion No. 29” to eliminate the Opinion 29 exception to fair value for nonmonetary exchanges of similar productive assets and to replace it with a general exception for exchange transactions that do not have commercial substance. We expect to implement SFAS 153 prospectively, beginning July 1, 2005. We do not expect the effect to be material to our results of operations, cash flows or financial condition.

FIN 46 (revised December 2003)“Consolidation of Variable Interest Entities” and FIN 46 “Consolidation of Variable Interest Entities”

We implemented FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003. FIN 46 interprets the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,”to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Due to the prospective application of FIN 46, we did not reclassify prior period amounts.

On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis) and we also deconsolidated the trusts which hold mandatorily redeemable trust preferred securities (see “Minority Interest in Finance Subsidiary” and “Trust Preferred Securities” sections of Note 17).

Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company (Sabine), a contract mining operation providing mining services to SWEPCo. Also, after consolidation, SWEPCo records all expenses (depreciation, interest and other operation expense) of Sabine and eliminates Sabine’s revenues against SWEPCo’s fuel expenses. There is no cumulative effect of accounting change recorded as a result of the requirement to consolidate, and there was no change in net income due to the consolidation of Sabine.

Effective July 1, 2003, OPCo consolidated JMG, an entity formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. OPCo now records the depreciation, interest and other operating expenses of JMG and eliminates JMG’s revenues against OPCo’s operating lease expenses. There is no cumulative effect of accounting change recorded as a result of our requirement to consolidate JMG, and there was no change in net income due to the consolidation of JMG (see “Gavin Scrubber Financing Agreement” section of Note 16).

In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R) which replaces FIN 46. We implemented FIN 46R effective March 31, 2004 with no material impact to our financial statements.

EITF Issue 03-13 “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”

This issue developed a model for evaluating which cash flows are to be considered in determining whether cash flows have been or will be eliminated and what types of continuing involvement constitute significant continuing involvement when determining whether to report Discontinued Operations. We will apply this issue to components that are disposed of or classified as held for sale in periods beginning after December 15, 2004.

FASB Staff Position 109-1 “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Activities Provided by the American Jobs Creation Act of 2004”

On October 22, 2004, the American Jobs Creation Act of 2004 (Act) was signed into law. The Act included tax relief for domestic manufacturers (including the production, but not the delivery of electricity) by providing a tax deduction up to 9 percent (when fully phased-in in 2010) on a percentage of “qualified production activities income.” Beginning in 2005 and for 2006, the deduction is 3 percent of qualified production activities income. The deduction increases to 6 percent for 2007, 2008 and 2009. The FASB staff has indicated that this tax relief should be treated as a special deduction and not as a tax rate reduction. While the U.S. Treasury has issued general guidance on the calculation of the deduction, this guidance lacks clarity as to determination of qualified production activities income as it relates to utility operations. We believe that the special deduction for 2005 and 2006 will not materially affect our results of operations, cash flows, or financial condition.

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, asset retirement obligations, fair value measurements, business combinations, revenue recognition, pension plans, liabilities and equity, earnings per share calculations, accounting changes and related tax impacts as applicable. We also expect to see more FASB projects as a result of their 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.

EXTRAORDINARY ITEM

In the fourth quarter of 2004, as part of its True-up Proceeding, TCC made net adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset related to its transition to retail competition. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis, including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on a PUCT adjustment in the CenterPoint Order (see “Wholesale Capacity Auction True-up” section of Note 6). These net adjustments were recorded as an extraordinary item in accordance with SFAS 101 and are reflected in our Consolidated Statements of Operations as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES

Accounting for Risk Management Contracts

EITF 02-3 rescinds EITF 98-10, “Accounting for Contracts Included in Energy Trading and Risk Management Activities,” and related interpretive guidance. We recorded a $49 million after tax charge against net income as Accounting for Risk Management Contracts in our Consolidated Statements of Operations in the first quarter of 2003 ($13 million in Utility Operations, $22 million in Investments - Gas Operations and $14 million in Investments - UK Operations segments). These amounts are recognized as the positions settle.

Asset Retirement Obligations

In the first quarter of 2003, we recorded $242 million of after tax income as a cumulative effect of accounting change for Asset Retirement Obligations in accordance with SFAS 143 ($249 million after tax income in Utility Operations and $7 million after tax loss in Investments-UK Operations segment).

Goodwill and Other Intangible Assets

SFAS 142, “Goodwill and Other Intangible Assets,” requires that goodwill and intangible assets with indefinite useful lives no longer be amortized and be tested annually for impairment. The implementation of SFAS 142 in 2002 resulted in a $350 million net transitional loss for our U.K. and Australian operations (included in the Investments - Other segment) and is reported in our Consolidated Statements of Operations as a cumulative effect of accounting change (see Note 3).

See table below for details of the Cumulative Effect of Accounting Changes:

	Year Ended December 31,
	2004		2003			2002
	(in millions)
Accounting for Risk Management Contracts (EITF 02-3)	$	-	$	(49	)(a)	$	-
Asset Retirement Obligations (SFAS 143)		-		242	(b)		-
Goodwill and Other Intangible Assets (SFAS 142)		-		-			(350	)(c)
Total	$	-	$	193		$	(350	)

(a)	net of tax of $19 million
(b)	net of tax of $157 million
(c)	net of tax of $0

3.GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

The changes in our carrying amount of goodwill for the years ended December 31, 2004 and 2003 by operating segment are:

			Investments
	Utility Operations		Gas Operations			UK Operations			Other			AEP Consolidated
	(in millions)
Balance at January 1, 2003	$	37.1	$	306.3		$	11.2		$	41.4		$	396.0
Impairment losses (a)		-		(291.4	)		(12.2	)		-			(303.6	)
Assets Held for Sale, Net (b)		-		(14.9	)		-			-			(14.9	)
Foreign currency exchange rate changes		-		-			1.0			-			1.0
Balance at December 31, 2003	$	37.1	$	-		$	-		$	41.4		$	78.5
Balance at January 1, 2004	$	37.1	$	-		$	-		$	41.4		$	78.5
Goodwill written off related to sale of  Numanco		-		-			-			(2.6	)		(2.6	)
Balance at December 31, 2004	$	37.1	$	-		$	-		$	38.8		$	75.9

(a) Impairment Losses: (see Note 10)

2003

Gas Operations

In the fourth quarter of 2003, we prepared our annual impairment tests. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. As a result of the tests, we recognized a $162.5 million goodwill impairment loss related to HPL ($150.4 million) and AEPES ($12.1 million).

Also during 2003, we recognized a goodwill impairment loss of $128.9 million related to Jefferson Island.

UK Operations

In 2003, we recognized a goodwill impairment loss of $12.2 million related to UK Coal Trading.

2004

In the fourth quarter of 2004, we prepared our annual impairment tests. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses.

(b) On our Consolidated Balance Sheets, amounts related to entities classified as held for sale are excluded from Goodwill and are reported within Assets of Discontinued Operations and Held for Sale until they are sold (see Note 10). The following entities were classified as held for sale and had goodwill impairments for the year ended December 31, 2003:

· Jefferson Island (Investments - Gas Operations segment) - $14.4 million balance in goodwill at December 31, 2003.

· LIG Chemical (Investments - Gas Operations segment) - $0.5 million balance in goodwill at December 31, 2003.

OTHER INTANGIBLE ASSETS

Acquired intangible assets subject to amortization are $29.7 million at December 31, 2004 and $34.1 million at December 31, 2003, net of accumulated amortization and are included in Other Noncurrent Assets on the Consolidated Balance Sheets. The gross carrying amount, accumulated amortization and amortization life by major asset class are:

			December 31, 2004				December 31, 2003
	Amortization Life		Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(in years)		(in millions)				(in millions)
Software acquired (a)		3	$	-	$	-	$	0.5	$	0.3
Patent		5		0.1		0.1		0.1		-
Easements		10		2.2		0.5		2.2		0.3
Trade name and administration  of contracts		7		2.4		0.9		2.4		0.9
Purchased technology		10		10.9		3.2		10.9		2.2
Advanced royalties		10		29.4		10.6		29.4		7.7
Total			$	45.0	$	15.3	$	45.5	$	11.4

(a) This asset related to U.K. Generation Plants and was sold during the third quarter of 2004.

Amortization of intangible assets was $4 million, $5 million and $4 million for 2004, 2003 and 2002, respectively. Our estimated total amortization is $5 million for each year 2005 through 2007, $4 million for 2008 through 2010 and $3 million in 2011.

4.RATE MATTERS

In certain jurisdictions, we have agreed to base rate or fuel recovery limitations usually under terms of settlement agreements. See Note 5 for a discussion of those terms related to the Nuclear Plant Restart and the Merger with CSW.

TNC Fuel Reconciliations

In 2002, TNC filed with the PUCT to reconcile fuel costs and defer the unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in its True-up Proceeding. As a result of the introduction of customer choice on January 1, 2002, this fuel reconciliation for the period from July 2000 through December 2001 is the final fuel reconciliation for TNC’s ERCOT service territory.

Through 2004, TNC provided $30 million for various disallowances recommended by the ALJ and accepted by the PUCT in open session of which $20 million was recorded in 2003 and $10 million in 2004. On October 18, 2004, the PUCT issued a final order which concluded that the over-recovery balance was $4 million. TNC has fully provided for the PUCT’s final order in this proceeding. TNC has sought declaratory and injunctive relief in Federal District Court for $8 million of its provision resulting from the PUCT’s rejection of TNC’s application of a FERC-approved tariff on the basis that the interpretation of the tariff is within the exclusive jurisdiction of the FERC and not the PUCT. TNC has also appealed various other issues to state District Court in Travis County for which it has provided $22 million. Another party has also filed a state court appeal. TNC will pursue vigorously these proceedings but at present cannot predict their outcome.

In February 2002, TNC received a final PUCT order in a previous fuel reconciliation covering the period July 1997 through June 2000 and reflected the order in its financial statements. In September 2004, that decision was affirmed by the Third Court of Appeals. No appeal was filed with the Supreme Court of Texas.

TCC Fuel Reconciliation

In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in its True-up Proceeding. This reconciliation covers the period from July 1998 through December 2001.

On February 3, 2004, the ALJ issued a PFD recommending that the PUCT disallow $140 million of eligible fuel costs. In May 2004, the PUCT accepted most of the ALJ’s recommendations in the TCC case, however, the PUCT rejected the ALJ’s recommendation to impute capacity to certain energy-only purchased power contracts and remanded the issue to the ALJ to determine if any energy-only purchased power contracts during the reconciliation period include a capacity component that is not recoverable in fuel revenues. In testimony filed in the remand proceeding, TCC asserted that its energy-only purchased power contracts do not include any capacity component. Intervenors, including the Office of Public Utility Counsel (OPC), have filed testimony recommending that $15 million to $30 million of TCC’s purchased power costs reflect capacity costs which are not recoverable in the fuel reconciliation. The ALJ issued a report on January 13, 2005 on the imputed capacity remand recommending that specified energy-only purchased power contracts include a capacity component with a value of $2 million. At its February 24, 2005 open meeting, the PUCT reviewed the ALJ report and also ruled that specified energy-only purchased power contracts include a capacity component of $2 million. As a result of the PUCT’s acceptance of most of the ALJ’s recommendations in TCC’s case and the PUCT’s rejection in the TNC case of our interpretation of its FERC tariff, TCC has recorded provisions totaling $143 million, with $81 million provided in 2003 and $62 million in 2004. The over-recovery balance and the provisions for probable disallowances totaled $212 million including interest at December 31, 2004.

Management believes they have materially provided for probable to-date disallowances in TCC’s final fuel reconciliation pending receipt of a final order. A final order has not yet been issued in TCC’s final fuel reconciliation. An order from the PUCT, disallowing amounts in excess of the established provision, could have a material adverse effect on future results of operations and cash flows. We will continue to challenge adverse decisions vigorously, including appeals and challenges in Federal Court if necessary. Additional information regarding the True-up Proceeding for TCC can be found in Note 6.

SWEPCo Texas Fuel Reconciliation

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This reconciliation covers the period from January 2000 through December 2002. During the reconciliation period, SWEPCo incurred $435 million of Texas retail eligible fuel expense. In December 2003, SWEPCo agreed to a settlement in principle with all parties in the fuel reconciliation proceeding. The settlement provides for a disallowance in fuel costs of $8 million which was recorded in December 2003. In April 2004, the PUCT approved the settlement.

SWEPCo Fuel Factor Increase

On November 5, 2004, SWEPCo filed a petition with the PUCT to increase its annual fixed fuel factor by $29 million. SWEPCo and the various parties to the proceedings reached a settlement effective January 31, 2005 that increases its annual fixed fuel factor revenues by approximately $25 million or approximately 18% over the amount that would be collected by the fuel factors currently in effect. The settlement agreement was approved by the PUCT on January 31, 2005. Actual fuel costs will be subject to review and approval in a future fuel reconciliation.

SWEPCo Louisiana Fuel Audit

The Louisiana Public Service Commission (LPSC) is performing an audit of SWEPCo’s historical fuel costs. In addition, five SWEPCo customers filed a suit in the Caddo Parish District Court in January 2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has overcharged them for fuel costs since 1975. The LPSC consolidated the customer complaints and audit. In testimony filed in this matter, the LPSC Staff recommended refunds of approximately $5 million. Subsequently, surrebuttal testimony filed by the LPSC Staff recognized that SWEPCo’s costs were reasonable and that most costs could be recovered through the fuel adjustment clause pending LPSC approval. While initial indications from the LPSC Staff surrebuttal testimony would not indicate a material disallowance, management cannot predict the ultimate outcome in this proceeding. If the LPSC or the Court does not agree with LPSC Staff recommendations, it could have an adverse effect on future results of operations and cash flows.

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery 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 submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. PSO filed testimony in February 2004.

An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested that $9 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated off-system sales margins between and among AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and, if corrected, could more than offset the $44 million 2002 reallocation under-recovery. The intervenor and the OCC Staff also argued that off-system sales margins were allocated incorrectly. The intervenors’ reallocation of such margins would reduce PSO’s recoverable fuel by $7 million for 2000 and $11 million for 2001, while under the OCC Staff method, the reduction for 2001 would be $9 million. The intervenor and the OCC Staff also recommended recalculation of PSO’s fuel costs for years subsequent to 2001 using the same revised methods. At a June 2004 prehearing conference, PSO questioned whether the issues in dispute were under the jurisdiction of the OCC because they relate to FERC-approved allocation agreements. As a result, the ALJ ordered that the parties brief the jurisdictional issue. After reviewing the briefs, the ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. In January 2005, the OCC conducted a hearing on the jurisdictional matter and a ruling is expected in the near future. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

Virginia Fuel Factor Filing

On October 29, 2004, APCo filed a request with the Virginia State Corporation Commission (Virginia SCC) to increase its fuel factor effective January 1, 2005. The requested factor is estimated to increase revenues by approximately $19 million on an annual basis. This increase reflects a continuing rise in the projected cost of coal in 2005. By order dated November 16, 2004, the Virginia SCC approved APCo’s request on an interim basis, pending a hearing held in February  2005. The Virginia SCC issued an order on February 11, 2005 approving the continuation of the January 1, 2005 interim fuel factor, which is subject to final audit. This fuel factor adjustment will increase cash flows without impacting results of operations as any over-recovery or under-recovery of fuel cost would be deferred as a regulatory liability or a regulatory asset.

Indiana Fuel Order

On August 27, 2003, the IURC ordered certain parties to negotiate the appropriate action on I&M’s fuel cost recovery beginning March 1, 2004, following the February 2004 expiration of a fixed fuel adjustment charge that capped fuel recoveries (fixed pursuant to a prior settlement of Cook Nuclear Plant outage issues). I&M agreed, contingent on AEP implementing corporate separation for some of its subsidiaries, to a fixed fuel adjustment charge beginning March 2004 and continuing through December 2007. Although we have not corporately separated, certain parties believe the fixed fuel adjustment charge should continue beyond February 2004. Negotiations to resolve this issue are ongoing. The IURC ordered that the fixed fuel adjustment charge remain in place, on an interim basis, through April 2004.

In April 2004, the IURC issued an order that extended the interim fuel factor from May through September 2004, subject to true-up to actual fuel costs following the resolution of the issue regarding the corporate separation agreement. The IURC also reopened the corporate separation docket to investigate issues related to the corporate separation agreement. In July 2004, we filed for approval of a fuel factor for the period October 2004 through March 2005. On September 22, 2004, the IURC issued another order extending the interim fuel factor from October 2004 through March 2005, subject to true-up upon resolution of the corporate separation issues. At December 31, 2004, I&M has under-recovered its fuel costs by $2 million. If I&M’s net recovery should remain an under-recovery and if I&M would be required to continue to bill the existing fixed fuel adjustment factor that caps fuel revenues, future results of operations and cash flows would be adversely affected.

Michigan 2004 Fuel Recovery Plan

On September 30, 2003, I&M filed its 2004 Power Supply Cost Recovery (PSCR) Plan with the Michigan Public Service Commission (MPSC) requesting fuel and power supply recovery factors for 2004, which were implemented pursuant to statute effective with January 2004 billings. A public hearing was held on March 10, 2004. On June 4, 2004, the ALJ recommended that net SO₂ and NO_x credits be excluded from the fuel recovery mechanism. I&M filed its exceptions in June 2004. If the ALJ’s recommendation is adopted by the MPSC and in a future period SO₂ and NO_x are a net cost, it would adversely affect results of operations and cash flows. On September 30, 2004, I&M filed its 2005 PSCR Plan, which reflects net credits of approximately $5 million.

TCC Rate Case

On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC’s proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%.

In February 2004, eight intervening parties and the PUCT Staff filed testimony recommending reductions to TCC’s requested $67 million annual rate increase. Their recommendations ranged from a decrease in annual existing rates of approximately $100 million to an increase in TCC’s current rates of approximately $27 million. Hearings were held in March 2004. In May 2004, TCC agreed to a nonunanimous settlement on cost of capital including capital structure and return on equity with all but two parties in the proceeding. TCC agreed that the return on equity should be established at 10.125% based upon a capital structure with 40% equity resulting in a weighted cost of capital of 7.475%. The settlement and other agreed adjustments reduced TCC’s rate request from $67 million to $41 million.

On July 1, 2004, the ALJs who heard the case issued their recommendations which included a recommendation to approve the cost of capital settlement. The ALJs recommended that an issue related to the allocation of consolidated tax savings to the transmission and distribution utility be remanded back to the ALJs for additional evidence. On July 15, 2004, the PUCT remanded this issue to the ALJs. On August 19, 2004, in a separate ruling, the PUCT remanded six other issues to the ALJs requesting revisions to clarify and support the recommendations in the PFD.

The PUCT ordered TCC to calculate its revenue requirements based upon the recommendations of the ALJs. On July 21, 2004, TCC filed its revenue requirements based upon the recommendations of the ALJs. According to TCC’s calculations, the ALJs’ recommendations would reduce TCC’s annual existing rates between $33 million and $43 million depending on the final resolution of the amount of consolidated tax savings.

On November 16, 2004, the ALJs issued their PFD on remand, increasing their recommended annual rate reduction to a range of $51 million to $78 million, depending on the amount disallowed related to affiliated AEPSC billed expenses. At the January 13, 2005 and January 27, 2005 open meetings, the Commissioners considered a number of issues, but deferred resolution of the affiliated AEPSC billed expenses issue, among other less significant issues, until after additional hearings scheduled for March 2005. Adjusted for the decisions announced by the Commissioners in January 2005, the ALJs' disallowance would yield an annual rate reduction of a range of $48 million to $75 million. If TCC were to prevail on the affiliated expenses issue and all remaining issues, the result would be an annual rate increase of $6 million. When issued, the PUCT order will affect revenues prospectively. An order reducing TCC’s rates could have a material adverse effect on future results of operations and cash flows.

TCC and TNC ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the OPC 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. On June 25, 2003, the District Court ruled in both appeals. The Court ruled in the Mutual Energy WTU case that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors was approximately $2.7 million for Mutual Energy WTU. The Court upheld the initial PTB orders on all other issues. In the Mutual Energy CPL proceeding, the Court also ruled that the PUCT improperly shifted the burden of proof and the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. The District Court decision was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy WTU and other parties. Management believes, based on the advice of counsel, that the PUCT’s original decision will ultimately be upheld. If the District Court’s decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in the years 2002 through 2004 resulting in an adverse effect on future results of operations and cash flows.

TCC Unbundled Cost of Service (UCOS) Appeal

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began. TCC placed new transmission and distribution rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. TCC requested and received approval from the FERC of wholesale transmission rates determined in the UCOS proceeding. Regulated delivery charges include the retail transmission and distribution charge and, among other items, a nuclear decommissioning fund charge, a municipal franchise fee, a system benefit fund fee, a transition charge associated with securitization of regulatory assets and a credit for excess earnings. Certain PUCT rulings, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT’s UCOS order with one exception. The Court ruled that the refund of the 1999 through 2001 excess earnings, solely as a credit to nonbypassable transmission and distribution rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. The distribution rate credit began in January 2002. This decision could potentially affect the PTB rates charged by Mutual Energy CPL and could result in a refund to certain of its customers. Mutual Energy CPL was a subsidiary of AEP until December 23, 2002 when it was sold. Management estimates that the adverse effect of a decision to reduce the PTB rates for the period prior to the sale is approximately $11 million pretax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties. Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court’s decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on future results of operations and cash flows.

SWEPCo Louisiana Compliance Filing

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. The LPSC’s merger order also provides that SWEPCo’s base rates are capped at the present level through mid-2005. In April 2004, SWEPCo filed updated financial information with a test year ending December 31, 2003 as required by the LPSC. Both filings indicated that SWEPCo’s current rates should not be reduced. Subsequently, direct testimony was filed on behalf of the LPSC recommending a $15 million reduction in SWEPCo’s Louisiana jurisdictional base rates. SWEPCo’s rebuttal testimony was filed on January 16, 2005. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ordered in the future, it would adversely impact future results of operations and cash flows.

PSO Rate Review

In February 2003, the OCC Staff filed an application requiring PSO to file all documents necessary for a general rate review. In October 2003 and June 2004, PSO filed financial information and supporting testimony in response to the OCC Staff’s request. PSO’s initial response indicated that its annual revenues were $36 million less than costs. The June 2004 filing updated PSO’s request and indicated a $41 million revenue deficiency. As a result, PSO sought OCC approval to increase its base rates by that amount, which is a 3.9% increase over PSO’s existing revenues.

In August 2004, PSO filed a motion to amend the timeline to consider new service quality and reliability requirements, which took effect on July 1, 2004. Also in August 2004, the OCC approved a revised schedule. In October 2004, PSO filed supplemental information requesting consideration of approximately $55 million of additional annual operations and maintenance expenses and annual capital costs to enhance system reliability. In November 2004, PSO filed a plan with the OCC seeking interim rate relief to fund a portion of the costs to meet the new state service quality and reliability requirements pending the outcome of the current case. In the filing, PSO sought interim approval to collect annual incremental tree trimming costs of approximately $23 million from its customers. Intervenors and the OCC Staff filed testimony recommending that the interim rate relief requested by PSO be modified or denied. The OCC issued an order on PSO’s interim request in January 2005, which allows PSO to recover up to an additional $12 million annually for reliability activities beginning in December 2004. Expenses exceeding that amount and the amount currently included in base rates will be considered in the base rate case.

The OCC Staff and intervenors filed testimony regarding their recommendations on revenue requirement, fuel procurement, resource planning and vegetation management in January 2005. Their recommendations ranged from a decrease in annual existing rates between $15 million and $36 million. In addition, one party recommended that the OCC require PSO file additional information regarding its natural gas purchasing practices. In the absence of such a filing, this party suggested that $30 million of PSO’s natural gas costs not be recovered from customers because it failed to implement a procurement strategy that, according to this party, would have resulted in lower natural gas costs. OCC Staff and intervenors recommended a return on common equity ranging from 9.3% to 10.11%. PSO’s rebuttal testimony was filed in February 2005, and that testimony reflects a number of adjustments to PSO’s June 2004 updated filing. These adjustments result in a decrease of PSO’s revenue deficiency in this case from $41 million to $28 million, although approximately $9 million of that decrease are items that would be recovered through the fuel adjustment clause rather than through base rates. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

PSO Lawton Power Supply Agreement

On November 26, 2003, pursuant to an application by Lawton Cogeneration Incorporated seeking avoided cost payments and approval of a power supply agreement, OCC issued an order approving payment of avoided costs and a Power Supply Agreement (Agreement). Among other things, in the order, the OCC did not approve PSO’s recovery of the costs of the Agreement.

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court. In the appeal, PSO maintains that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. Should the OCC’s order be upheld by the Supreme Court, PSO anticipates full recovery of the costs of the Agreement. However, if the OCC was to deny recovery of a material amount, it would adversely affect future results of operations and cash flows.

Upon resolution of this issue, management would review any transaction for the effect, if any, on the balance sheet relating to lease and FIN 46R accounting.

KPCo Environmental Surcharge Filing

In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at the Big Sandy Plant.

In March 2003, the KPSC granted approximately $18 million of the request. Annual rate relief of $1.7 million became effective in May 2003 and an additional $16.2 million became effective in July 2003. The recovery of such amounts is intended to offset KPCo’s cost of compliance with the CAA.

RTO Formation/Integration

Based on FERC approvals in response to nonaffiliated companies’ requests to defer RTO formation costs, the AEP East companies deferred costs incurred under FERC orders to form a new RTO (the Alliance RTO) or subsequently to join an existing RTO (PJM). In July 2003, the FERC issued an order approving our continued deferral of both Alliance RTO formation costs and PJM integration costs, including the deferral of a carrying charge thereon. The AEP East companies have deferred approximately $37 million of RTO formation and integration costs and related carrying charges through December 31, 2004.

In its July 2003 order, the FERC indicated that it would review the deferred costs at the time they are transferred to a regulatory asset account and scheduled for amortization and recovery in the OATT to be charged by PJM. Management believes that the FERC will grant permission for prudently incurred deferred RTO formation/integration costs to be amortized and included in the OATT. Whether the amortized costs will be fully recoverable depends upon the state regulatory commissions’ treatment of the AEP East companies’ portion of the OATT as these companies file rate cases. As of December 31, 2004, retail base rates are frozen or capped and cannot be increased for retail customers of CSPCo and OPCo until January 1, 2006.

In August 2004, we filed an application with the FERC dividing the RTO formation/integration costs between PJM-incurred integration costs billed to us including related carrying charges, and all other RTO formation/integration costs. We intend to file with the FERC to request that deferred PJM-incurred integration costs billed to us be recovered from all PJM customers. We anticipate the other RTO formation/integration costs will be recovered through transmission rates in the AEP East zone. The AEP East companies will be responsible for paying most of the amount allocated by the FERC to the AEP East zone since it will be attributable to their internal load. In our August 2004 application, we requested permission to amortize over 15 years beginning January 1, 2005 the cost to be billed within the AEP East zone which represents approximately one-half of the total deferred RTO formation/integration costs. We also requested to begin amortizing the deferred PJM-billed integration costs on January 1, 2005, but we did not propose an amortization period in the application. The FERC has not ruled on our application.

The AEP East companies integrated into PJM on October 1, 2004. We intend to file a joint request with other new PJM members to recover approximately one-half of the deferred RTO formation/integration costs (i.e. the PJM-incurred integration expenses billed to AEP) through a new charge in the PJM OATT that would apply to all loads and generation in the PJM region during a 10-year period beginning in May 2005. The AEP East companies will expense their portion of the PJM-incurred integration costs billed by PJM under the new charge. We will amortize the remaining portion of our RTO formation/integration costs over the period to be approved by the FERC and seek recovery of such costs in the retail rates for each of the AEP East companies’ state jurisdictions. Management believes that it is probable that the FERC will approve recovery of the PJM-incurred integration costs to be billed to us through the PJM OATT and that the FERC will grant a long enough amortization period to allow for the opportunity for recovery of the non-PJM incurred RTO formation/integration costs in the AEP East retail jurisdictions. If the FERC ultimately decides not to approve an amortization period that would provide us with the opportunity to include such costs in future retail rate filings or the FERC or the state commissions deny recovery of our share of these deferred costs, future results of operations and cash flows could be adversely affected.

FERC Order on Regional Through and Out Rates

In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (MISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and expanded PJM regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners including AEP East companies under the RTOs’ revenue distribution protocols.

In November 2003, the FERC issued an order finding that the T&O rates of the former Alliance RTO participants, including AEP, should also be eliminated for transactions within the Combined Footprint. The order directed the RTOs and former Alliance RTO participants to file compliance rates to eliminate T&O rates prospectively within the Combined Footprint and simultaneously implement a load-based transitional rate mechanism called the seams elimination cost allocation (SECA), to mitigate the lost T&O revenues for a two-year transition period beginning April 1, 2004. The FERC is expected to implement a new rate design after the two-year period. In April 2004, the FERC approved a settlement that delayed elimination of T&O rates and the implementation of SECA replacement rates until December 1, 2004 when the FERC would implement a new rate design.

On November 18, 2004, the FERC conditionally approved a license plate rate design to eliminate rate pancaking for transmission service within the Combined Footprint and adopted its previously approved SECA transition rate methodology to mitigate the effects of the elimination of T&O rates effective December 1, 2004. Under license plate rates, customers serving load within a RTO pay transmission service rates based on the embedded cost of the transmission facilities in the local pricing zone where the load being served is located. The use of license plate rates would shift costs that we previously recovered from our T&O service customers to mainly AEP’s native load customers within the AEP East pricing zone. The SECA transition rates will remain in effect through March 31, 2006. The SECA rates are designed to mitigate the loss of revenues due to the elimination of T&O rates.

The SECA rates became effective December 1, 2004. Billing statements from PJM for December 2004 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP accrued $11 million in December 2004 for SECA revenues. On January 7, 2005, AEP and Exelon filed joint comments and protests with the FERC including a request that FERC direct PJM and MISO to comply with the FERC decision and collect all SECA revenues due with interest charges for all late-billed amounts. On February 10, 2005, the FERC issued an order indicating that the SECA transition rates would be subject to refund or surcharge and set for hearing all remaining aspects of the compliance filings to the November 18 order, including the our request that the FERC direct PJM and MISO begin billing and collecting the SECA transition rates.

The AEP East companies received approximately $196 million of T&O rate revenues within the PJM/MISO Expanded Footprint for the twelve months ended September 30, 2004, the twelve months prior to AEP joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA charges was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP for its lost T&O revenues through March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Hold Harmless Proceeding

In its July 2002 order conditionally accepting our choice to join PJM, the FERC directed us, ComEd, MISO and PJM to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from us and ComEd joining PJM instead of MISO. In December 2003, AEP and ComEd jointly filed a hold-harmless proposal, which was rejected by the FERC in March 2004 without prejudice to the filing of a new proposal.

In July 2004, AEP and PJM filed jointly with the FERC a new hold-harmless proposal that was nearly identical to a proposal filed jointly by ComEd and PJM in April 2004. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. A hearing is scheduled for April 2005.

The proposed hold-harmless agreement as filed by PJM and us specifies that the term of the agreement commences on October 1, 2004 and terminates when the FERC determines that effective internalization of congestion and loop flows is accomplished. The Michigan and Wisconsin utilities have presented studies that show estimated adverse effects to utilities in the two states in the range of $60 to $70 million over the term of the agreement for ComEd and AEP. The recent supplemental filing by the Michigan companies show estimated adverse effects to utilities in Michigan of up to $50 million over the term of agreement. AEP and ComEd have presented studies that show no adverse effects to the Michigan and Wisconsin utilities. ComEd has separately settled this issue with the Michigan and Wisconsin utilities for a one time total payment of approximately $5 million, which was approved by the FERC. On December 27, 2004, AEP and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250,000 which is pending approval before the FERC.

At this time, management is unable to predict the outcome of this proceeding. AEP will support vigorously its positions before the FERC. No provision has been established. If the FERC ultimately approves a significant hold-harmless payment to the Michigan and Wisconsin utilities, it would adversely impact results of operations and cash flows.

FERC Market Power Mitigation

In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. These two screening tests include a “pivotal supplier” test which determines if the market load can be fully served by alternative suppliers and a “market share” test which compares the amount of surplus generation at the time of the applicant’s minimum load. In July 2004, the FERC issued an order on rehearing, affirming its conclusions in the April order and directing AEP and two nonaffiliated utilities to file generation market power analyses within 30 days. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way.

On August 9, 2004, as amended on September 16, 2004 and November 19, 2004, AEP submitted its generation market power screens in compliance with the FERC’s orders. The analysis focused on the three major areas in which AEP serves load and owns generation resources -- ECAR, SPP and ERCOT, and the “first tier” control areas for each of those areas.

The pivotal supplier and market share screen analyses that AEP filed demonstrated that AEP does not possess market power in any of the control areas to which it is directly connected (first-tier markets). AEP passed both screening tests in all of its “first tier” markets. In its three “home” control areas, AEP passed the pivotal supplier test. AEP, as part of PJM, also passes the market share screen for the PJM destination market. AEP also passed the market share screen for ERCOT. AEP did not pass the market share screen as designed by the FERC for the SPP control area.

In a December 17, 2004 order, FERC affirmed our conclusions that we passed both market power screen tests in all areas except SPP. Because AEP did not pass the market share screen in SPP, FERC initiated proceedings under Section 206 of the Federal Power Act in which AEP is rebuttably presumed to possess market power in SPP. Consequently, our revenues from sales in SPP at market based rates after March 6, 2005 will be collected subject to refund to the extent that prices are ultimately found not to be just and reasonable. On February 15, 2005, although we continue to believe we do not possess market power in SPP, we filed a response and proposed tariff changes to address FERC’s market-power concerns. The proposed tariff change would apply to sales that sink within the service territories of PSO, SWEPCo and TNC within the SPP that encompass the AEP-SPP control area, and make such sales subject to cost-based rate caps. We have requested the amended tariffs to become effective March 6, 2005.

In addition to FERC market monitoring, we are subject to market monitoring oversight by the RTOs in which we are a member, including PJM and SPP. These market monitors have authority for oversight and market power mitigation.

Management believes that we are unable to exercise market power in any region. At this time the impact on future wholesale power revenues, results of operations and cash flows of the FERC’s and PJM’s market power analysis cannot be determined.

5.EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items:

		December 31,				Future Recovery/Refund Period
		2004		2003
		(in millions)
Regulatory Assets:
	Income Tax Related Regulatory Assets, Net	$	796	$	728	Various Periods (a)
	Transition Regulatory Assets		407		529	Up to 6 Years (a)
	Designated for Securitization		1,361		1,289	(b)
	Texas Wholesale Capacity Auction True-up		560		480	(c)
	Unamortized Loss on Reacquired Debt		116		116	Up to 39 Years (d)
	Cook Nuclear Plant Refueling Outage Levelization		44		57	(e)
	Other		317		383	Various Periods (f)
Total Regulatory Assets		$	3,601	$	3,582
Regulatory Liabilities and Deferred Investment Tax Credits:
	Asset Removal Costs	$	1,290	$	1,233	(g)
	Deferred Investment Tax Credits		393		422	Up to 25 Years (a)
	Excess ARO for Nuclear Decommissioning Liability		245		216	(h)
	Over-recovery of Texas Fuel Costs		216		150	(c)
	Deferred Over-recovered Fuel Costs		71		63	(a)
	Texas Retail Clawback		75		57	(c)
	Other		250		254	Various Periods (f)
Total Regulatory Liabilities		$	2,540	$	2,395

(a)	Amount does not earn a return.
(b)	Amount includes a carrying cost, will be included in TCC’s True-up Proceeding and is designated for possible securitization. The cost of the securitization bonds would be recovered over a time period to be determined in a future PUCT proceeding.
(c)	See “Texas Restructuring” and “Carrying Costs on Net-True-up Regulatory Assets” sections of Note 6 for discussion of carrying costs. Amounts will be included in TCC’s and TNC’s true-up proceedings for future recovery/refund over a time period to be determined in a future PUCT proceeding.
(d)	Amount effectively earns a return.
(e)	Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage and does not earn a return.
(f)	Includes items both earning and not earning a return.
(g)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.
(h)	This is the cumulative difference in the amount provided through rates and the amount as measured by applying SFAS 143. This amount earns a return, accrues monthly, and will be paid when the nuclear plant is decommissioned.

Texas Restructuring Related Regulatory Assets and Liabilities

Regulatory Assets Designated for Securitization, Texas Wholesale Capacity Auction True-up regulatory assets, Over-recovery of Fuel Costs and Texas Retail Clawback regulatory liabilities are not currently being recovered from or returned to ratepayers. Management believes that the laws and regulations established in Texas for industry restructuring provide for the recovery from ratepayers of these net amounts. These amounts require approval of the PUCT in a future True-up Proceeding. See Note 6 for a complete discussion of our plans to seek recovery of these regulatory assets, net of regulatory liabilities.

Nuclear Plant Restart

I&M completed the restart of both units of the Cook Plant in 2000. Settlement agreements in the Indiana and Michigan retail jurisdictions that addressed recovery of Cook Plant related outage restart costs were approved in 1999 by the Indiana Utility Regulatory Commission and Michigan Public Service Commission.

The amount of deferrals amortized to maintenance and other operation expenses under the settlement agreements were $40 million in both 2003 and 2002. The Nuclear Plant Restart regulatory asset was fully amortized as of December 31, 2004 and 2003. Also, pursuant to the settlement agreements, accrued fuel-related revenues of approximately $37 million in 2003 and $38 million in 2002 were amortized as a reduction of revenues. The amortization of amounts deferred under Indiana and Michigan retail jurisdictional settlement agreements adversely affected results of operations through December 31, 2003 when the amortization period ended.

Merger with CSW

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. The following table summarizes significant merger-related agreements:

Summary of key provisions of Merger Rate Agreements:

State/Company	Ratemaking Provisions
Texas - SWEPCo, TCC, TNC	Rate reductions of $221 million over 6 years.
Indiana - I&M	Rate reductions of $67 million over 8 years.
Michigan - I&M	Customer billing credits of approximately $14 million over 8 years.
Kentucky - KPCo	Rate reductions of approximately $28 million over 8 years.
Oklahoma - PSO	Rate reductions of approximately $28 million over 5 years.
Arkansas - SWEPCo	Rate reductions of $6 million over 5 years.
Louisiana - SWEPCo	Rate reductions to share merger savings estimated to be $18 million over 8 years and a base rate cap until June 2005.

If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected.

See “Merger Litigation” section of Note 7 for information on a court decision concerning the merger.

6.CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

With the passage of restructuring legislation, six of our eleven electric utility companies (CSPCo, I&M, APCo, OPCo, TCC and TNC) are in various stages of transitioning to customer choice and/or market pricing for the supply of electricity in four of the eleven state retail jurisdictions (Ohio, Texas, Michigan and Virginia) in which the AEP domestic electric utility companies operate. The following paragraphs discuss significant events related to industry restructuring in those states.

OHIO RESTRUCTURING

The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005. The Public Utilities Commission of Ohio (PUCO) may terminate the MDP for one or more customer classes before that date if it determines either that effective competition exists in the incumbent utility’s certified territory or that there is a twenty percent switching rate of the incumbent utility’s load by customer class. Following the MDP, retail customers will receive cost-based regulated distribution and transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. Retail customers will continue to have the right to choose their electric power suppliers or receive Default Service, which must be offered by the incumbent utility at market rates.

On December 17, 2003, the PUCO adopted a set of rules concerning the method by which it will determine market rates for Default Service following the MDP. The rules provide for a Market Based Standard Service Offer (MBSSO) which would be a variable rate based on transparent forward market, daily market, and/or hourly market prices. The rules also require a fixed-rate Competitive Bidding Process (CBP) for residential and small nonresidential customers and permits a fixed-rate CBP for large general service customers and other customer classes. Customers who do not switch to a competitive generation provider can choose between the MBSSO and the CBP. Customers who make no choice will be served pursuant to the CBP. The rules also required that electric distribution utilities file an application for MBSSO and CBP by July 1, 2004. CSPCo and OPCo were granted a waiver from making the required MBSSO/CBP filing, pending the outcome of a rate stabilization plan they filed with the PUCO in February 2004. As of December 31, 2004, none of OPCo’s customers have elected to choose an alternate power supplier and only a modest number of CSPCo’s small commercial customers has switched suppliers. This is believed to be due to CSPCo’s and OPCo’s rates being below market.

The PUCO invited default service providers to propose an alternative to all customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo and OPCo filed rate stabilization plans with the PUCO addressing prices for the three-year period following the end of the MDP, January 1, 2006 through December 31, 2008. The plans are intended to provide price stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP’s generation resources that serve Ohio customers. On January 26, 2005, the PUCO approved the plans with some modifications.

The approved plans include annual fixed increases in the generation component of all customers’ bills (3% a year for CSPCo and 7% a year for OPCo) in 2006, 2007 and 2008. The plan also includes the opportunity to annually request an additional increase in supply prices averaging up to 4% per year for each company to recover certain new governmentally-mandated increased expenditures set out in the approved plan. The plans maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level in effect on December 31, 2005. Such rates could be adjusted with PUCO approval for specified reasons. Transmission charges could also be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion and ancillary services. The approved plans provide for the continued amortization and recovery of stranded transition generation-related regulatory assets. The plans, as modified by the PUCO, require CSPCo and OPCo to allot a combined total of $14 million of previously provided for unspent shopping incentives for the benefit of their low-income customers and economic development over the three-year period ending December 31, 2008 which will not have an effect on net income. The plan also authorized each company to establish unavoidable riders applicable to all distribution customers in order to be compensated in 2006 through 2008 for certain new costs incurred in 2004 and 2005 of fulfilling the companies’ Provider of Last Resort (POLR) obligations. These costs include RTO administrative fees and congestion costs net of financial transmission revenues and carrying cost of environmental capital expenditures. As a result, in 2005, CSPCo and OPCo expect to record regulatory assets of $8 million and $21 million, respectively, for the subject costs related to 2004 and $14 million and $52 million, respectively, for expected subject costs related to 2005. These regulatory assets, totaling $22 million for CSPCo and $73 million for OPCo will be amortized as the costs are recovered through POLR riders in 2006 through 2008. The riders, together with the fixed annual increases in generation rates are estimated to provide additional cumulative revenues to CSPCo and OPCo of $190 million and $500 million, respectively, in the three-year period ended December 31, 2008. Other revenue increases may occur related to other provisions of the plan discussed above.

On February 25, 2005, various intervenors filed Applications for Rehearing with the PUCO regarding their approval of the rate stabilization plans.  Management expects the PUCO to address the applications before the end of March 2005.  Management cannot predict the ultimate impact these proceedings will have on the results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, we are deferring customer choice implementation costs and related carrying costs in excess of $40 million. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. Through December 31, 2004, we incurred $78 million of such costs, and accordingly, we deferred $38 million such costs for probable future recovery in distribution rates. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the rate stabilization plan, recovery of these amounts will be deferred until the next distribution rate filing to change rates after December 31, 2008. Management believes that the deferred customer choice implementation costs were prudently incurred 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.

TEXAS RESTRUCTURING

Texas Restructuring Legislation enacted in 1999 provides the framework and timetable to allow retail electricity competition for all Texas customers. On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in the SPP area of Texas until at least January 1, 2007. TCC and TNC operate in ERCOT while SWEPCo and a small portion of TNC’s business is in SPP.

The Texas Restructuring Legislation, among other things:

● provides for the recovery of net stranded generation costs and other generation true-up amounts through securitization and nonbypassable wires charges,

● requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility,

● provides for an earnings test for each of the years 1999 through 2001 and,

● provides for a stranded cost True-up Proceeding after January 10, 2004.

The Texas Restructuring Legislation also required vertically integrated utilities to legally separate their generation and retail-related assets from their transmission and distribution-related assets. Prior to 2002, TCC and TNC functionally separated their operations. AEP formed new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1, 2002 (the start date of retail competition). In December 2002, AEP sold two of its affiliated price-to-beat REPs serving ERCOT customers to a nonaffiliated company.

TEXAS TRUE-UP PROCEEDINGS

The True-up Proceedings will determine the amount and recovery of:

● net stranded generation plant costs and net generation-related regulatory assets less any unrefunded excess earnings (net stranded generation costs),

● a true-up of actual market prices determined through legislatively-mandated capacity auctions to the projected power costs used in the PUCT’s excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up revenues),

● excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback),

● final approved deferred fuel balance, and

● net carrying costs on true-up amounts.

The PUCT adopted a rule in 2003 regarding the timing of the True-up Proceedings scheduling TCC’s filing 60 days after the completion of the sale of TCC’s generation assets. Due to regulatory and contractual delays in the sale of its generating assets, TCC has not yet filed its true-up request. TNC filed its true-up request in June 2004 and updated the filing in October 2004. Since TNC is not a stranded cost company under Texas Restructuring Legislation, the majority of the true-up items in the table below do not apply to TNC.

Net True-up Regulatory Asset (Liability) Recorded at December 31, 2004:

	TCC			TNC
	(in millions)
Stranded Generation Plant Costs	$	897		$	-
Net Generation-related Regulatory Asset		249			-
Unrefunded Excess Earnings		(10	)		-
Net Stranded Generation Costs		1,136			-
Carrying Costs on Stranded Generation Plant Costs		225			-
Net Stranded Generation Costs Designated for Securitization		1,361			-
Wholesale Capacity Auction True-up		483			-
Carrying Costs on Wholesale Capacity Auction True-up		77			-
Retail Clawback		(61	)		(14	)
Deferred Over-recovered Fuel Balance		(212	)		(4	)
Net Other Recoverable True-up Amounts		287			(18	)
Total Recorded Net True-up Regulatory Asset (Liability)	$	1,648		$	(18	)

Amounts listed above include fourth quarter 2004 adjustments made to reflect the applicable portion of the PUCT’s decisions in prior nonaffiliated utilities’ True-up Proceedings discussed below.

Net Stranded Generation Costs

The Texas Restructuring Legislation required utilities with stranded generation plant costs to use market-based methods to value certain generation assets for determining stranded generation plant costs. TCC is the only AEP subsidiary that has stranded generation plant costs under the Texas Restructuring Legislation. TCC elected to use the sale of assets method to determine the market value of its generation assets for determining stranded generation plant costs. For purposes of the True-up Proceeding, the amount of stranded generation plant costs under this market valuation methodology will be the amount by which the book value of TCC’s generation assets exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets.

In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC’s generation capacity in Texas. We received bids for all of TCC’s generation plants. In January 2004, TCC agreed to sell its 7.81% ownership interest in the Oklaunion Power Station to a nonaffiliated third party for approximately $43 million. In March 2004, TCC agreed to sell its 25.2% ownership interest in STP for approximately $333 million and its other coal, gas and hydro plants for approximately $430 million to nonaffiliated entities. Each sale is subject to specified price adjustments. TCC sent right of first refusal notices to the co-owners of Oklaunion and STP. TCC filed for FERC approval of the sales of Oklaunion, STP and the coal, gas and hydro plants. TCC received a notice from co-owners of Oklaunion and STP exercising their rights of first refusal; therefore, SEC approval will be required. The original nonaffiliated third party purchaser of Oklaunion has petitioned for a court order declaring its contract valid and the co-owners’ rights of first refusal void. The sale of STP will also require approval from the Nuclear Regulatory Commission. On July 1, 2004, TCC completed the sale of its other coal, gas and hydro plants for approximately $428 million, net of adjustments. The closings of the sales of STP and Oklaunion plants are expected to occur in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals. In addition, there could be delays in resolving litigation with a third party affecting Oklaunion. In order to sell these assets, TCC defeased all of its remaining outstanding first mortgage bonds in May 2004. In December 2003, based on an expected loss from the sale of its generating assets, TCC recognized as a regulatory asset an estimated impairment from the sale of TCC’s generation assets of approximately $938 million. The impairment was computed based on an estimate of TCC’s generation assets sales price compared to book basis at December 31, 2003. On February 15, 2005, TCC filed with the PUCT requesting a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closings of the sales of all the generation assets. TCC asked the PUCT to rule on the request in April 2005.

On December 17, 2004, the PUCT issued an Order on Rehearing in the CenterPoint True-Up Proceeding (CenterPoint Order). All motions for rehearing of that order were denied on January 18, 2005, and the PUCT’s decision is now final and appealable. Among other things, the CenterPoint Order provided certain adjustments to stranded generation plant costs to avoid what the PUCT deemed to be duplicative recovery of stranded costs and the capacity auction true-up amount, as further discussed below (See “Wholesale Capacity Auction True-up” below). The CenterPoint Order also confirmed that stranded costs are to be determined as of December 31, 2001, and, as also discussed below, the CenterPoint Order identified how carrying costs from that date are to be computed (see “Carrying Costs on Net True-Up Regulatory Assets” below).

In the fourth quarter of 2004, TCC made adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis (instead of December 31, 2003 book basis), including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on a PUCT adjustment in the CenterPoint Order discussed below under “Wholesale Capacity Auction True-up.” These adjustments are reflected as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax in our Consolidated Statements of Operations. Management believes that with these adjustments to TCC’s stranded generation plant costs regulatory asset, it has complied with the portions of the PUCT’s to-date orders in other Texas companies’ true-up proceedings that apply to TCC.

In addition to the two items discussed above (the $938 million impairment in 2003 and the $185 million adjustment in 2004), TCC had recorded $121 million of impairments in 2002 and 2003 on its gas-fired plants. Additionally, other miscellaneous items and the costs to complete the sales, which are still ongoing, of $23 million are included in the recoverable stranded generation plant costs of $897 million.

The Texas Restructuring Legislation permits TCC to recover as its net stranded generation costs $897 million of stranded generation plant cost plus its remaining not yet securitized net generation-related transition regulatory asset of $249 million less a regulatory liability for the unrefunded excess earnings of $10 million, discussed below. With the above net extraordinary basis adjustments from applicable portions of the PUCT’s prior nonaffiliated true-up orders, TCC’s net stranded generation costs before carrying costs totaled $1.1 billionat December 31, 2004.

In the CenterPoint Order, the PUCT decided that net stranded generation costs should be reduced by the present value of deferred investment tax credits (ITC) and excess deferred federal income taxes applicable to generating assets. CenterPoint testified in its true-up proceeding that acceleration of the sharing of deferred ITC with customers may be a violation of the Internal Revenue Code’s normalization provisions. Management agrees with CenterPoint that the PUCT’s acceleration of deferred ITC and excess deferred federal income taxes may be a violation of the normalization provisions. As a result, management does not intend to include as a reduction of its net stranded generation costs the present value of TCC’s generation-related deferred ITC of $70 million and the present value of excess deferred federal income taxes of $6 million in its future true-up filing. As a result, such amounts are not reflected as a reduction of TCC’s net stranded generation costs in the above table. The Internal Revenue Service (IRS) has issued proposed regulations that would make an exception to the normalization provisions for a utility whose electric generation assets cease to be public utility property. If the IRS does not issue final regulations with protective provisions prior to the filing of TCC’s true-up, management intends to seek a private letter ruling from the IRS to determine whether the PUCT’s action would result in a normalization violation. A normalization violation could result in the repayment of TCC’s accumulated deferred ITC on all property, not just generation property, which approximates $108 million as of December 31, 2004, and a loss of the ability to elect accelerated tax depreciation in the future. Management is unable to predict how the IRS will rule on a private letter ruling request and whether TCC will ultimately suffer any adverse effects on its future results of operations and cash flows.

Unrefunded Excess Earnings

The Texas Restructuring Legislation provides for the calculation of excess earnings for each year from 1999 through 2001. The total excess earnings determined by the PUCT for this three-year period were $3 million for SWEPCo, $42 million for TCC and $15 million for TNC. TCC, TNC and SWEPCo challenged the PUCT’s treatment of fuel-related deferred income taxes in the computation of excess earnings and appealed the PUCT’s final 2000 excess earnings to the Travis County District Court which upheld the PUCT ruling. However, upon further appeal of the District Court ruling upholding the PUCT decision, the Third Court of Appeals reversed the PUCT order and the District Court’s judgment. The District Court remanded to the PUCT an appeal of the same issue from the PUCT’s 2001 order upon agreement of the parties after issuance of the Third Court of Appeals decision. On September 14, 2004, the parties to the PUCT remand reached an agreement, which changed the method for calculating excess earnings which, in turn, revised the calculation for 2000 and 2001 consistent with the ruling of the court. The PUCT issued a final order approving the agreement in October 2004. Since an expense and regulatory liability had been accrued in prior years in compliance with the PUCT orders, all three companies reversed a portion of their regulatory liability for the years 2000 and 2001 consistent with the Appeals Court’s decision and credited amortization expense during the third quarter of 2003. Under the Texas Restructuring Legislation, since TNC and SWEPCo do not have stranded generation plant costs, excess earnings have been applied to reduce T&D capital expenditures and are not a true-up item.

In 2001, the PUCT issued an order requiring TCC to return estimated excess earnings by reducing distribution rates by approximately $55 million plus accrued interest over a five-year period beginning January 1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order had no additional effect on reported net income but reduces cash flows over the refund period. The remaining $10 millionto be refunded is recorded as a regulatory liability at December 31, 2004 and will be included as a reduction to TCC’s net stranded generation costs unless it has been fully refunded. Management believes that TCC has stranded generation plant costs and that it is, therefore, inconsistent with the Texas Restructuring Legislation for the PUCT to have ordered a refund prior to TCC’s True-up Proceeding. TCC appealed the PUCT’s premature refund of excess earnings to the Travis County District Court. That court affirmed the PUCT’s decision and further ordered that the refunds be provided to ultimate customers. TCC has appealed the decision to the Third Court of Appeals.

In January 2005, intervenors filed testimony in TNC’s True-up Proceeding recommending that TNC’s excess earnings be increased by approximately $5 million to reflect carrying charges on its excess earnings for the period from January 1, 2002 to March 2005. A decision from the PUCT will likely be received in the second quarter of 2005.

Wholesale Capacity Auction True-up

The Texas Restructuring Legislation required that electric utilities and their affiliated power generation companies (PGCs) offer for sale at auction, in 2002, 2003 and thereafter, at least 15% of the PGCs’ Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation. According to the legislation, the actual market power prices received in the state-mandated auctions are used to calculate wholesale capacity auction true-up revenues for recovery in the True-up Proceeding. According to PUCT rules, the wholesale capacity auction true-up is only applicable to the years 2002 and 2003. Based on its auction prices, TCC recorded a regulatory asset and related revenues of $262 million in 2002 and $218 million in 2003 which represented the quantifiable amount of the wholesale capacity auction true-up. The cumulative amount before carrying costs was adjusted to $483 million in the fourth quarter of 2004. TCC also recorded $77 million of carrying costs in the fourth quarter of 2004 related to the wholesale capacity auction true-up, increasing the total asset to $560 million.

In the CenterPoint Order, the PUCT made three significant adverse adjustments to CenterPoint’s and its affiliated PGCs’ request for recovery related to its capacity auction true-up regulatory asset. First, the PUCT determined that CenterPoint had not met what the PUCT interpreted as a requirement to sell 15% of its generation capacity at the state-mandated auctions. Accordingly, an adjustment was made to reflect prices obtained in other auctions of CenterPoint’s affiliated PGCs’ generation. Parties to the TCC proceeding may also contend that TCC has not met the requirement to auction 15% of its generation capacity. However, based on facts not applicable to the CenterPoint case, TCC will contend that it has met the requirement. Even if it were determined that TCC has not complied with the requirement, facts unique to TCC might mitigate the potential impact and make the method of calculating an impact uncertain. Since the facts in the CenterPoint decision differ from TCC’s facts and circumstances, TCC has not recorded any provisions to reflect a similar adverse adjustment to its net true-up regulatory asset.

Second, the PUCT determined that the purpose of the capacity auction true-up is to provide a traditional regulated level of recovery during 2002-2003. The PUCT then determined that depreciation is a component of that recovery and, because depreciation represents a return of investment in generation assets, it disallowed 2002 and 2003 depreciation as a duplicative recovery of stranded costs. In the CenterPoint Order, the PUCT determined that there was a duplication of depreciation due to the fact that the stranded generation plant costs also include amounts depreciated in 2002 and 2003 because the stranded generation plant costs were determined as of December 31, 2001. TCC disagrees that the purpose of the capacity auction true-up is to provide a traditional regulated recovery during 2002 through 2003. Moreover, TCC will contend, among other things, that the PUCT’s method of calculating the capacity auction true-up did not permit TCC to fully recover 2002 through 2003 depreciation expense. Nonetheless, based on the determination made by the PUCT in the CenterPoint case and the probability that it will interpret the law in the same manner in TCC’s case, TCC recorded a $238 million reduction to its stranded generation plant costs in December 2004 which is reflected as a component of the Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax in our Consolidated Statements of Operations.

Third, the PUCT determined in the CenterPoint case that any nonfuel revenues produced by the capacity auction true-up regulatory asset which exceed nonfuel revenues for 2002-2003 from traditional regulation is a margin or return which is duplicative of the carrying cost. As noted above, TCC intends to challenge the conclusion that the capacity auction true-up was intended to provide a traditional regulated recovery. In addition, TCC will contend, that when applied to TCC, the calculation adopted for CenterPoint in which the PUCT determined that CenterPoint had duplicative return of carrying costs actually produces a $206 million negative margin. It will be TCC’s position that it should have the right to recover the negative margin if the purpose of the capacity auction is to allow a traditional regulated recovery. As a result, TCC has recorded no adjustment to reflect this determination in the CenterPoint case.

Retail Clawback

The Texas Restructuring Legislation provides for the affiliated PTB REPs serving residential and small commercial customers to refund to its T&D utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This is referred to as the the retail clawback. If, prior to January 1, 2004, 40% of the load for the residential or small commercial classes is served by competitive REPs, the retail clawback is not applicable for that class of customer. In December 2003, the PUCT certified that the REPs in the TCC and TNC service territories had reached the 40% threshold for the small commercial class. As a result, TCC and TNC reversed $6 million and $3 million, respectively, of retail clawback regulatory liabilities previously accrued for the small commercial class. Based upon customer information filed by the nonaffiliated company, which operates as the PTB REP for TCC and TNC, TCC and TNC updated their estimated residential retail clawback regulatory liability. At December 31, 2004, TCC’s recorded retail clawback regulatory liability was $61 million and TNC’s was $14 million. TCC and TNC each recorded a receivable from the nonaffiliated company which operates as their PTB REP totaling $32 million and $7 million, respectively, for their share of the retail clawback liability.

Fuel Balance Recoveries

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to establish its deferred unrecovered fuel balance applicable to retail sales within its ERCOT service area for inclusion in the True-up Proceeding. In October 2004, the PUCT issued a final order which resulted in an over-recovery balance of $4 million. TNC had adjusted its deferred fuel balance in 2003 by $20 million and in 2004 by $10 million in compliance with the final PUCT order. Challenges to that order were filed in December 2004 in federal and state district courts.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery fuel balance for inclusion in the True-up Proceeding. TCC provided for disallowances increasing its regulatory fuel over-recovery liability by $81 million in 2003 and $62 million in 2004. On February 24, 2005, the PUCT in its open meeting increased the over-recovery by approximately $2 million, inclusive of interest, for imputed capacity. TCC has provided for a $212 million deferred over-recovery fuel balance at December 31, 2004, which does not include the $2 million disallowance ruled by the PUCT. However, management is unable to predict the amount, if any, of any additional disallowances of TCC’s final fuel over-recovery balance which will be included in its True-up Proceeding until a final order is issued. Management believes it has materially provided for probable to date disallowances in TCC’s final fuel proceeding pending receipt of an order.

See “TCC Fuel Reconciliation” and “TNC Fuel Reconciliations” in Note 4 for further discussion.

Carrying Costs on Net True-up Regulatory Assets

In December 2001, the PUCT issued a rule concerning stranded cost true-up proceedings stating, among other things, that carrying costs on stranded costs would begin to accrue on the date that the PUCT issued its final order in the True-up Proceeding. TCC and one other Texas electric utility company filed a direct appeal of the rule to the Texas Third Court of Appeals contending that carrying costs should commence on January 1, 2002, the day that retail customer choice began in ERCOT.

The Third Court of Appeals ruled against the utilities, who then appealed to the Texas Supreme Court. On June 18, 2004, the Texas Supreme Court reversed the decision of the Third Court of Appeals determining that a carrying cost should be accrued beginning January 1, 2002 and remanded the proceeding to the PUCT for further consideration. The Supreme Court determined that utilities with stranded costs are not permitted to over-recover stranded costs and ordered that the PUCT should address whether any portion of the 2002 and 2003 wholesale capacity auction true-up regulatory asset includes a recovery of stranded costs or carrying costs on stranded costs. A motion for rehearing with the Supreme Court was denied and the ruling became final.

In the CenterPoint Order, the PUCT addressed the Supreme Court’s remand decision and specified the manner in which carrying costs should be calculated. In December 2004, TCC computed, based on its interpretation of the methodology contained in the CenterPoint Order, carrying costs of $470 million for the period January 1, 2002 through December 31, 2004 on its stranded generation plant costs net of excess earnings and its wholesale capacity auction true-up regulatory assets at the 11.79% overall pretax cost of capital rate in its UCOS rate proceeding. The embedded 8.12% debt component of the carrying cost of $302 million ($225 million on stranded generation plant costs and $77 million on wholesale capacity auction true-up) was recognized in income in December 2004. This amount is included in Carrying Costs on Texas Stranded Cost Recovery in our Consolidated Statements of Operations. Of the $302 million recorded in 2004, approximately $109 million, $105 million and $88 million related to the years 2004, 2003 and 2002, respectively. The remaining equity component of $168 million will be recognized in income as collected.

TCC will continue to accrue a carrying cost at the rate set forth above until it recovers its approved net true-up regulatory asset. The deferred over-recovered fuel balance accrues interest payable at a short-term rate set by the PUCT until one year after a final order is issued in the fuel proceeding or a final order is issued in TCC’s True-up Proceeding, whichever comes first. At that time, a carrying cost will begin to accrue on the deferred fuel. For all remaining true-up items, including the retail clawback, a carrying cost will begin to accrue when a final order is issued in TCC’s True-up Proceeding. If the PUCT further adjusts TCC’s net true-up regulatory asset in TCC’s True-up Proceeding, the carrying cost will also be adjusted.

Stranded Cost Recovery

When the True-up Proceeding is completed, TCC intends to file to recover PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through nonbypassable transition charges and competition transition charges in the regulated T&D rates. TCC will seek to securitize the approved net stranded generation costs plus related carrying costs. The annual costs of the resultant securitization bonds will be recovered through a nonbypassable transition charge collected by the T&D utility over the term of the securitization bonds. The other approved net true-up items will be recovered or refunded over time through a nonbypassable competition transition wires charge or credit inclusive of a carrying cost.

TCC’s recorded net true-up regulatory asset for amounts subject to approval in the True-up Proceeding is approximately $1.6 billionat December 31, 2004. The securitizable portion of this net true-up regulatory asset, which consists of net stranded generation costs plus related carrying costs, was $1.4 billion at December 31, 2004. We expect that TCC’s True-up Proceeding filing will seek to recover an amount in excess of the total of its recorded net true-up regulatory asset through December 31, 2004. The PUCT will review TCC’s filing and determine the amount for the recoverable net true-up regulatory assets.

Due to differences between CenterPoint’s and TCC’s facts and circumstances, the lack of direct applicability of certain portions of the CenterPoint Order to TCC and the unknown nature of future developments in TCC’s True-up Proceeding, we cannot, at this time, determine if TCC will incur disallowances in its True-up Proceeding in excess of the $185 million provided in December 2004. We believe that our recorded net true-up regulatory asset at December 31, 2004 is in compliance with the Texas Restructuring Legislation, and the applicable portions of the CenterPoint Order and other nonaffiliated true-up orders, and we intend to seek vigorously its recovery. If, however, we determine that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset of $1.6 billion at December 31, 2004 and we are able to estimate the amount of such nonrecovery, we will record a provision for such amount, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition. To the extent decisions in the TCC True-up Proceeding differ from management’s interpretation of the Texas Restructuring Legislation and its evaluation of the applicable portions of the CenterPoint and other true-up orders, additional material disallowances are possible.

TNC 2004 True-up Filing

In June 2004, TNC filed its True-up Proceeding which included the fuel reconciliation balance and the retail clawback calculation. The amount of the deferred over-recovered fuel balance at December 31, 2004 was approximately $4 million. TNC filed an update to its true-up filing to reflect the final order in its fuel reconciliation proceeding. The retail clawback regulatory liability included in the filing was adjusted in 2004 to $14 million, reflecting the number of customers served on January 1, 2004. In January 2005, intervenors filed testimony recommending that TNC’s over-recovery be increased by up to approximately $2 million. In addition, they recommended that TNC’s excess earnings be increased by approximately $5 million for carrying charges and its T&D rates be reduced by a maximum amount of approximately $3 million on an annual basis to reflect the return on excess earnings approved by the PUCT for the period 1999 through 2001. TNC does not agree with the intervenor’s reconciliation and filed rebuttal testimony. Management believes it has materially provided for all probable to date disallowances in TNC’s True-up Proceeding.

MICHIGAN RESTRUCTURING

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Effective with that date, the rates on I&M’s Michigan customers’ bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M’s total base rates in Michigan remain unchanged and reflect cost of service. At December 31, 2004, none of I&M’s customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory. As a result, management has concluded that as of December 31, 2004 the requirements to apply SFAS 71 continue to be met since I&M’s rates for generation in Michigan continue to be cost-based regulated.

VIRGINIA RESTRUCTURING

In April 2004, the Governor of Virginia signed legislation that extends the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides specified cost recovery opportunities during the capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004.

ARKANSAS RESTRUCTURING

In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo’s Arkansas operations reapplied SFAS 71 regulatory accounting, which had been discontinued in 1999. The reapplication of SFAS 71 had an insignificant effect on results of operations and financial condition.

WEST VIRGINIA RESTRUCTURING

In 2000, the Public Service Commission of West Virginia (WVPSC) issued an order approving an electricity- restructuring plan, which the West Virginia Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the West Virginia legislature made tax law changes necessary to preserve the revenues of state and local governments.

In the 2001 and 2002 legislative sessions, the West Virginia Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring during the summer of 2002.

In the 2003 legislative session, the West Virginia Legislature again failed to enact the required tax legislation. Also, legislation enacted in March 2003 clarified the jurisdiction of the WVPSC over electric generation facilities in West Virginia. In March 2003, APCo’s outside counsel advised us that restructuring in West Virginia was no longer probable and confirmed facts relating to the WVPSC’s jurisdiction and rate authority over APCo’s West Virginia generation. As a result, in March 2003, management concluded that deregulation of APCo’s West Virginia generation business was no longer probable and operations in West Virginia met the requirements to reapply SFAS 71. Reapplying SFAS 71 in West Virginia had an insignificant effect on 2003 results of operations and financial condition.

7.COMMITMENTS AND CONTINGENCIES

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 modified certain units at coal-fired generating plants in violation of the NSRs 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.

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 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). 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.

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, eight Northeastern States filed a separate complaint containing the same allegations against the Conesville and Amos plants that the judge disallowed in the pending case. AEP filed an answer to the complaint in January 2005, denying the allegations and stating its defenses.

On August 7, 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, a nonaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not “routine” maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any nonroutine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A remedy trial was scheduled for July 2004, but has been postponed to facilitate further settlement discussions.

Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in our case also vary widely from plant to plant. Further, the Ohio Edison decision is limited to liability issues, and provides no insight as to the remedies that might ultimately be ordered by the Court.

On August 26, 2003, the District Court for the Middle District of South Carolina issued a decision on cross-motions for summary judgment prior to a liability trial in a case pending against Duke Energy Corporation, a nonaffiliated utility. The District Court denied all the pending motions, but set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is “routine maintenance, repair, or replacement” and on whether or not a “significant net emissions increase” results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is “routine within the relevant source category” in determining if it is “routine.” Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA has requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals. The District Court denied the Federal EPA’s motion. On April 13, 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that eliminated the need for a trial, but preserving plaintiffs’ right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. The United States subsequently filed a notice of appeal to the Fourth Circuit Court of Appeals. The case is fully briefed and oral argument was heard on February 3, 2005.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged CAA violations. The 11th Circuit determined that the administrative compliance order was not a final agency action, and that the enforcement provisions authorizing the issuance and enforcement of such orders under the CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and in May 2004, that petition was denied.

On June 26, 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which our subsidiaries are members, to reopen petitions for review of the 1980 and 1992 CAA rulemakings that are the basis for the Federal EPA claims in our case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in our case. Briefing continues in this case and oral argument was held in January 2005.

On August 27, 2003, the Administrator of the Federal EPA signed a final rule that defines “routine maintenance repair and replacement” to include “functionally equivalent equipment replacement.” Under the new rule, replacement of a component within an integrated industrial operation (defined as a “process unit”) with a new component that is identical or functionally equivalent will be deemed to be a “routine replacement” if the replacement does not change any of the fundamental design parameters of the process unit, does not result in emissions in excess of any authorized limit, and does not cost more than twenty percent of the replacement cost of the process unit. The new rule is intended to have prospective effect, and was to become effective in certain states 60 days after October 27, 2003, the date of its publication in the Federal Register, and in other states upon completion of state processes to incorporate the new rule into state law. On October 27, 2003, twelve states, the District of Columbia and several cities filed an action in the United States Court of Appeals for the District of Columbia Circuit seeking judicial review of the new rule. The UARG has intervened in this case. On December 24, 2003, the Circuit Court granted a motion from the petitioners to stay the effective date of this rule, which had been December 26, 2003.

In December 2000, Cinergy Corp., a nonaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle litigation regarding generating plant emissions under the CAA. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy’s settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement’s impact on its jointly-owned facilities and its future results of operations and cash flows.

On July 21, 2004, the Sierra Club issued a notice of intent to file a citizen suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power & Light Company for alleged violations of the New Source Review programs at the Stuart Station. CSPCo owns a 26% share of the Stuart Station. On September 21, 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio state implementation plan occurred at the Stuart Station, and seeking injunctive relief and civil penalties. The owners have filed a motion to dismiss portions of the complaint. We believe the allegations in the complaint are without merit, and intend to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

We are unable to estimate the loss or range of loss related to the contingent liability 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, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 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 SWEPCo's Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations made by a terminated AEP employee. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions.

On July 19, 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. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of volatile organic compound emissions at the Pirkey Plant, but after investigation determined further enforcement action was not warranted and withdrew the notice on January 5, 2005.

SWEPCo has previously reported to the TCEQ deviations related to the receipt of off-specification fuel at Knox Lee, the volatile organic compound emissions at Pirkey, and the referenced recordkeeping and reporting requirements and heat input value at Welsh. We have submitted additional responses to the Notice of Enforcement and the notice from the special interest groups. 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

On July 21, 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 and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions allege that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and seek 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. Management believes the actions are without merit and intends to defend vigorously against the claims.

NUCLEAR

Nuclear Plants

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement, I&M and TCC are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition would be adversely affected.

Nuclear Incident Liability

The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $10.8 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $300 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $101 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $20 million. TCC could be assessed $50 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited.

Under an industry-wide program insuring workers at nuclear facilities, I&M and TCC are also obligated for assessments of up to $6 million and $2 million, respectively, for potential claims. These obligations will remain in effect until December 31, 2007.

Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $43 million for I&M and $2 million for TCC which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The current Price-Anderson Act expired in August 2002. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed in 2005 with increases in required third party financial protection for nuclear incidents.

SNF Disposal

Federal law provides for government responsibility for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $229 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2004, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and exceed the liability amount. TCC is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal

Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. In November 2003, I&M filed to extend the operating licenses of the two Cook Plant units for up to an additional 20 years. The review of the license extension application is expected to take at least two years. After expiration of the licenses, Cook Plant is expected to be decommissioned using the prompt decontamination and dismantlement (DECON) method. The estimated cost of decommissioning and low-level radioactive waste accumulation disposal costs for Cook Plant ranges from $889 million to $1.1 billion in 2003 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2004, 2003 and 2002.

The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the DECON method. In May 2004, an updated decommissioning study was completed for STP. The study estimates TCC’s share of the decommissioning costs of STP to be $344 million in nondiscounted 2004 dollars. TCC is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of approximately $8 million per year. As discussed in Note 10, TCC is in the process of selling its ownership interest in STP to two nonaffiliates, and upon completion of the sale, it is anticipated that TCC will no longer be obligated for nuclear decommissioning liabilities associated with STP.

Decommissioning costs recovered from customers are deposited in external trusts. I&M deposited in its decommissioning trust an additional $4 million in 2004 and $12 million in both 2003 and 2002 related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in Other Operation expense for the Cook Plant. For STP, nuclear decommissioning costs are recorded in Other Operation expense, interest income of the trusts are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Charges.

TCC’s nuclear decommissioning trust asset and liability are included in held for sale amounts on the Consolidated Balance Sheets.

OPERATIONAL

Construction and Commitments

The AEP System has substantial construction commitments to support its operations. Aggregate construction expenditures for 2005 for consolidated operations are estimated to be$2.7 billion including amounts for proposed environmental rules. 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.

Our subsidiaries have entered into long-term contracts to acquire fuel for electric generation. The longest contract extends to the year 2014. The contracts provide for periodic price adjustments and contain various clauses that would release the subsidiaries from their obligations under certain conditions.

The AEP System has a unit contingent contract to supply approximately 250 MW of capacity to a nonaffiliated entity through December 31, 2009. The commitment is pursuant to a unit power agreement requiring the delivery of energy only if the unit capacity is available.

Potential Uninsured Losses

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

Power Generation Facility

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 have subleased the Facility to the Dow Chemical Company (Dow) under a 5-year term with three 5-year renewal terms for a total term of up to 20 years. The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA. Commercial operation of the Facility as required by the agreements between Juniper, AEP and Dow was achieved on March 18, 2004. The initial term of our lease with Juniper (Juniper Lease) commenced on March 18, 2004 and terminates on June 17, 2009. We may extend the term of the Juniper Lease to a total lease term of 30 years. Our lease of the Facility is reported as an owned asset under a lease financing transaction. Therefore, the asset and related liability for the debt and equity of the facility are recorded on our Consolidated Balance Sheets and the obligations under the lease agreement are excluded from the table of future minimum lease payment in Note 16.

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 with debt financing of up to $494 million and equity of up to $31 million from investors with no relationship to AEP or any of AEP’s subsidiaries.

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 of $520 million. 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.

We have the right to purchase the Facility for the acquisition cost during the last month of the Juniper Lease’s initial term or on any monthly rent payment date during any extended term of the lease. In addition, we may purchase the Facility from Juniper for the acquisition cost at any time during the initial term if we have arranged a sale of the Facility to a nonaffiliated third party. A purchase of the Facility from Juniper by AEP should not alter Dow’s rights to lease the Facility or our contract to purchase energy from Dow as described below. If the lease is renewed for up to a 30-year lease term, then at the end of that 30-year term we may further renew the lease at fair market value subject to Juniper’s approval, purchase the Facility at its acquisition cost, or sell the Facility, on behalf of Juniper, to an independent third party. If the Facility is sold and the proceeds from the sale are insufficient to pay all of Juniper’s acquisition costs, we may be required to make a payment (not to exceed $415 million) to Juniper for the excess of Juniper’s acquisition cost over the proceeds from the sale. We have guaranteed the performance of our subsidiaries to Juniper during the lease term. Because we now report Juniper’s funded obligations related to the Facility on our Consolidated Balance Sheets, the fair value of the liability for our guarantee (the $415 million payment discussed above) is not separately reported.

At December 31, 2004, Juniper’s acquisition costs for the Facility totaled $520 million, and the total acquisition cost for the completed Facility is currently expected to be approximately $525 million. For the 30-year extended lease term, the base lease rental is a variable rate obligation indexed to three-month LIBOR (plus a component for a fixed-rate return on Juniper’s equity investment and an administrative charge). Consequently, as market interest rates increase, the base rental payments under the lease will also increase. Annual payments of approximately $23 million represent future minimum lease payments to Juniper during the initial term. The majority of the payment is calculated using the indexed LIBOR rate (2.55% at December 31, 2004). Annual sublease payments received from Dow are approximately $27 million (substantially based on an adjusted three-month LIBOR rate discussed above).

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has 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 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) 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 purpose of the PPA began April 2, 2004.

On September 5, 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We allege that TEM has breached the PPA, and we are seeking a determination of our rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of AEP’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, 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 claimed termination value damages from TEM. The corporate parent of TEM (Tractebel SA) has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there was no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted AEP partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA. The litigation is in the discovery phase, with trial scheduled to begin in March 2005.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the District Court that the PPA has been terminated and (iii) would be pursuing against TEM, and Tractebel SA under the guaranty, damages and the full termination payment value of the PPA.

See “Power Generation Facility” section of Note 10 for further discussion.

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ. We expect an initial decision from the ALJ later this year. The SEC will review the initial decision.

Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.

Enron Bankruptcy

In 2002, certain of our subsidiaries filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain of our subsidiaries had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, we purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy - Bammel storage facility and HPL indemnification matters - In connection with the 2001 acquisition of HPL, we entered into a prepaid arrangement under which we acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipeline pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years.

In January 2004, we filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which we acquired title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million, which increased our investment in HPL. AEP and Enron agreed to release each other from all claims associated with the Bammel facility, including our indemnity claims. The settlement received Bankruptcy Court approval in September 2004 and closed in November 2004. The parties’ respective trading claims and Bank of America’s (BOA) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement.

Enron Bankruptcy - Right to use of cushion gas agreements - In connection with the 2001 acquisition of HPL, we also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (including the 10.5 BCF described in the preceding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, 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 also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate 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 state court in Texas 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. 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 has objected to the Magistrate Judge’s decision and the matter is now before the District Judge.

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 have objected to Enron’s attempted rejection of these agreements.

On January 26, 2005, we sold a 98% limited partner interest in HPL. We have indemnified the buyer of our 98% interest in HPL against any damages resulting from the BOA litigation. The determination of the gain on sale and the recognition of the gain is dependent on the ultimate resolution of the BOA dispute (see Note 19).

Enron Bankruptcy - Commodity trading settlement disputes - In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas-related trading transactions. We asserted our right to offset trading payables owed to various Enron entities against trading receivables due to several of our subsidiaries. The parties are currently in nonbinding, court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claim in the action being brought by Enron. The parties are currently in nonbinding, court-sponsored mediation.

Enron Bankruptcy - Summary - The amount expensed in prior years in connection with the Enron bankruptcy was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged our offsetting of receivables and payables and there is a dispute regarding the cushion gas agreement. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows or financial condition.

Shareholder Lawsuits

In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging securities law violations and seeking class action certification were filed in federal District Court, Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits, members of the AEP Board of Directors and certain investment banking firms. The lawsuits claim that we failed to disclose that alleged “round trip” trades resulted in an overstatement of revenues, that we failed to disclose that our traders falsely reported energy prices to trade publications that published gas price indices and that we failed to disclose that we did not have in place sufficient management controls to prevent “round trip” trades or false reporting of energy prices. The plaintiffs sought recovery of an unstated amount of compensatory damages, attorney fees and costs. In September 2004, the U.S. District Court Judge dismissed the cases and expressly denied the plaintiffs’ request for an opportunity to file amended complaints with new and revised allegations. The plaintiffs did not appeal this decision.

In the fourth quarter of 2002, two shareholder derivative actions were filed in state court in Columbus, Ohio against AEP and its Board of Directors alleging a breach of fiduciary duty for failure to establish and maintain adequate internal controls over our gas trading operations. In November 2004, these cases were dismissed. Also, 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 have filed a Motion to Dismiss these actions, which the Court denied. We have filed a Motion for Leave to file an interlocutory appeal seeking review of part of the Court’s decision. The cases are in the discovery stage. 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 has been dismissed from the case. The plaintiff had stated an intention to amend the complaint to add an AEP subsidiary as a defendant. The plaintiff amended the complaint but did not name any AEP company as a defendant. Since then, a number of 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. Management is unable to predict the outcome of these lawsuits but intends to defend vigorously against the claims made in 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. On December 5, 2003, the Court issued its initial Pretrial Order consolidating all related cases, appointing co-lead counsel and providing for the filing of an amended consolidated complaint. In January 2004, plaintiffs filed an amended consolidated complaint. We and the other defendants filed a motion to dismiss the complaint, which the Court denied in September 2004. We intend to defend vigorously against these claims.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against certain nonaffiliated energy companies, ERCOT, four AEP subsidiaries and us. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit.

Bank of Montreal Claim

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals with us and claimed that we owed approximately $34 million. In April 2003, we filed a lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had acted contrary to the appropriate trading contract and industry practice in terminating the contract and calculating termination and liquidation amounts and that BOM had acknowledged just prior to the termination and liquidation that it owed us approximately $68 million. We are claiming that BOM owes us at least $45 million related to previously recorded receivables on which we hold approximately $20 million of credit collateral. We have reserved $4 million against these receivables to reflect the risks of loss, based on the low end of a range of valuations calculated for purposes of the litigation and related mediation. Although management is unable to predict the outcome of this matter, it is not expected to have a material impact on results of operations, cash flows or financial condition.

Coal Transportation Dispute

Certain of our subsidiaries, as joint owners of a generating station have disputed transportation costs billed for coal received between July 2000 and the present time. Our subsidiaries have remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, our subsidiaries recorded a provision for possible loss in December 2004. Of the total provision, a share for deregulated subsidiaries affected income in 2004, a share was recorded as a receivable due to partial ownership of the plant by third parties and the remainder was deferred under the operation of a deferred fuel mechanism. Management continues to work toward mitigating the disputed amounts to the extent possible.

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 had 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 had failed to demonstrate that the public interest required that 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.

Energy Market Investigation

AEP and other energy market participants received data requests, subpoenas and requests for information from the FERC, the SEC, the PUCT, the U.S. Commodity Futures Trading Commission (CFTC), the U.S. Department of Justice and the California attorney general during 2002. Management responded to the inquiries and provided the requested information and continued to respond to supplemental data requests from some of these agencies in 2003 and 2004.

In September 2003, the CFTC filed a complaint against AEP and AEPES in federal district court in Columbus, Ohio. The CFTC alleged that AEP and AEPES provided false or misleading information about market conditions and prices of natural gas in an attempt to manipulate the price of natural gas in violation of the Commodity Exchange Act. The CFTC sought civil penalties, restitution and disgorgement of benefits. We responded to the complaint in September 2004. In January 2005, we reached settlement agreements totaling $81 million with the CFTC, the U.S. Department of Justice and the FERC regarding investigations of past gas price reporting and gas storage activities, these being all agencies known still to be then investigating these matters as to AEP. Our settlements do not admit nor should they be construed as an admission of violation of any applicable regulation or law. We made settlement payments to the agencies in the first quarter of 2005 in accordance with the respective contractual terms. The agencies have ended their investigations and the CFTC litigation filed in September 2003 has also ended. During 2003 and 2004, we provided for the settlements payment in the amounts of $45 million and $36 million (nondeductible for federal income tax purposes), respectively. We do not expect any impact on 2005 results of operations as a result of these investigations and settlements.

8.GUARANTEES

There are certain immaterial liabilities recorded for guarantees entered subsequent to December 31, 2002 in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

LETTERS OF CREDIT

We have entered into standby letters of credit (LOC) with third parties. These LOCs cover gas and electricity risk management contracts, construction contracts, insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. We issued all of these LOCs in our ordinary course of business. At December 31, 2004, the maximum future payments for all the LOCs are approximately $242 million with maturities ranging from February 2005 to January 2011. As the parent of various subsidiaries, we hold all assets of the subsidiaries as collateral. There is no recourse to third parties in the event these letters of credit are drawn.

GUARANTEES OF THIRD-PARTY OBLIGATIONS

CSW Energy and CSW International

CSW Energy and CSW International, our subsidiaries, have guaranteed 50% of the required debt service reserve of Sweeny Cogeneration L.P. (Sweeny), an IPP of which CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve as a part of a financing. In the event that Sweeny does not make the required debt payments, CSW Energy and CSW International have a maximum future payment exposure of approximately $4 million, which expires June 2020.

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $53 million with maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide 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 a third party miner. At December 31, 2004, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

Effective July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46. SWEPCo does not have an ownership interest in Sabine.

INDEMNIFICATIONS AND OTHER GUARANTEES

Contracts

We entered into several types of contracts, which would 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. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events. In 2004 and 2003, we entered into several sale agreements discussed in Note 10. These sale agreements include indemnifications with a maximum exposure of approximately $970 million. There are no material liabilities recorded for any indemnifications entered during 2004 or 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive 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 have 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 December 31, 2004, the maximum potential loss for these lease agreements was approximately $42 million ($27 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

See Note 16 for disclosure of other lease residual value guarantees.

9.SUSTAINED EARNINGS IMPROVEMENT INITIATIVE

In response to difficult conditions in our business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth.

Termination benefits expense relating to 1,120 terminated employees totaling $75 million pretax was recorded in the fourth quarter of 2002. Of this amount, we paid $10 million to these terminated employees in the fourth quarter of 2002. No additional termination benefits expense related to the SEI initiative was recorded in 2004 or 2003. The remaining SEI related payments were made in 2003. The termination benefits expense is classified as Maintenance and Other Operation expense on our Consolidated Statements of Operations. We determined that the termination of the employees under our SEI initiative did not constitute a plan curtailment of any of our retirement benefit plans.

10.ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, IMPAIRMENTS, ASSETS HELD FOR SALE AND ASSETS HELD AND USED

ACQUISITIONS

2002

Acquisition of Nordic Trading (Investments - UK Operations segment)

In January 2002, we acquired the trading operations, including key staff, of Enron's Norway and Sweden-based energy trading businesses (Nordic Trading). Results of operations are included in our Consolidated Statements of Operations from the date of acquisition. In the fourth quarter of 2002, a decision was made to exit this noncore European trading business. The sale of Nordic Trading in the second quarter of 2003 is discussed in the “Dispositions” section of this note.

Acquisition of USTI (Investments - Other segment)

In January 2002, we acquired 100% of the stock of United Sciences Testing, Inc. (USTI) for $13 million. USTI provides equipment and services related to automated emission monitoring of combustion gases to both our affiliates and external customers. Results of operations are included in our Consolidated Statements of Operations from the date of acquisition.

DISPOSITIONS

2004

Pushan Power Plant (Investments - Other segment)

In the fourth quarter of 2002, we began active negotiations to sell our interest in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest partner. A purchase and sale agreement was signed in the fourth quarter of 2003. The sale was completed in March 2004 for $61 million. An estimated pretax loss on disposal of $20 million ($13 million net of tax) was recorded in December 2002, based on an indicative price expression at that time, and was classified in Discontinued Operations. The effect of the sale on our 2004 results of operations was not significant.

Results of operations of Pushan have been classified as Discontinued Operations in our Consolidated Statements of Operations. The assets and liabilities of Pushan have been included in Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held For Sale, respectively, on our Consolidated Balance Sheets at December 31, 2003. See “Discontinued Operations” and “Assets Held for Sale” sections of this note for additional information.

LIG Pipeline Company and its Subsidiaries (Investments - Gas Operations segment)

As a result of our 2003 decision to exit our noncore businesses, we actively marketed LIG Pipeline Company which had approximately 2,000 miles of natural gas gathering and transmission pipelines in Louisiana and five gas processing facilities that straddle the system. After receiving and analyzing initial bids during the fourth quarter of 2003, we recorded a pretax impairment loss of $134 million ($99 million net of tax); of this pretax loss, $129 million relates to the impairment of goodwill and $5 million relates to other charges. In January 2004, a decision was made to sell LIG’s pipeline and processing assets separate from LIG’s gas storage assets. (See “Jefferson Island Storage & Hub, LLC” section of this note for further information.) In February 2004, we signed a definitive agreement to sell LIG Pipeline Company, which owned all of the pipeline and processing assets of LIG. The sale of LIG Pipeline Company and its assets for $76 million was completed in April 2004 and the impact on results of operations in 2004 was not significant. The assets and liabilities of LIG are classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, on our Consolidated Balance Sheets at December 31, 2003. The results of operations (including the above-mentioned impairments and other related charges) are classified in Discontinued Operations in our Consolidated Statements of Operations. See “Discontinued Operations” and “Assets Held for Sale” sections of this note for additional information.

Jefferson Island Storage & Hub, LLC (Investments - Gas Operations segment)

In August 2004, a definitive agreement was signed to sell the gas storage assets of Jefferson Island Storage & Hub, LLC (JISH). The sale of JISH and its assets for $90 million was completed in October 2004. The sale resulted in a pretax loss of $12 million ($2 million net of tax). The assets and liabilities of JISH are classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, on our Consolidated Balance Sheets at December 31, 2003. The results of operations and loss on sale of JISH are classified as Discontinued Operations in our Consolidated Statements of Operations. See “Discontinued Operations” and “Assets Held for Sale” sections of this note for additional information.

AEP Coal, Inc. (Investments - Other segment)

In October 2001, we acquired out of bankruptcy certain assets and assumed certain liabilities of nineteen coal mine companies formerly known as “Quaker Coal” and renamed “AEP Coal, Inc.” During 2002, the coal operations suffered from a decline in prices and adverse mining factors resulting in significantly reduced mine productivity and revenue. Based on an extensive review of economically accessible reserves and other factors, future mine productivity and production is expected to continue below historical levels. In December 2002, a probability-weighted discounted cash flow analysis of fair value of the mines was performed which indicated a 2002 pretax impairment loss of $60 million including a goodwill impairment of $4 million. This impairment loss is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations.

In 2003, as a result of management’s decision to exit our noncore businesses, we retained an advisor to facilitate the sale of AEP Coal, Inc. In the fourth quarter of 2003, after considering the current bids and all other options, we recorded a pretax charge of $67 million ($44 million net of tax) comprised of a $30 million asset impairment, a $25 million charge related to accelerated remediation cost accruals and a $12 million charge (accrued at December 31, 2003) related to a royalty agreement. These impairment losses were included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. The assets and liabilities of AEP Coal, Inc. that are held for sale have been included in Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, in our Consolidated Balance Sheets at December 31, 2003.

In March 2004, an agreement was reached to sell assets, exclusive of certain reserves and related liabilities, of the mining operations of AEP Coal, Inc. We received approximately $9 million cash and the buyer assumed an additional $11 million in future reclamation liabilities. We retained an estimated $37 million in future reclamation liabilities. The sale closed in April 2004 and the effect of the sale on our 2004 results of operations was not significant. See “Assets Held for Sale” section of this note for additional information.

Independent Power Producers (Investments - Other segment)

During the third quarter of 2003, we initiated an effort to sell four domestic Independent Power Producer (IPP) investments accounted for under the equity method (two located in Colorado and two located in Florida). Our two Colorado investments included a 47.75% interest in Brush II, a 68-megawatt, gas-fired, combined cycle, cogeneration plant in Brush, Colorado and a 50% interest in Thermo, a 272-megawatt, gas-fired, combined cycle, cogeneration plant located in Ft. Lupton, Colorado. Our two Florida investments included a 46.25% interest in Mulberry, a 120-megawatt, gas-fired, combined cycle, cogeneration plant located in Bartow, Florida and a 50% interest in Orange, a 103-megawatt, gas-fired, combined cycle, cogeneration plant located in Bartow, Florida. In accordance with GAAP, we were required to measure the impairment of each of these four investments individually. Based on indicative bids, it was determined that an other than temporary impairment existed on the two equity method investments located in Colorado. A pretax impairment of $70 million ($46 million net of tax) was recorded in September 2003 as the result of the measurement of fair value that was triggered by our decision to sell these assets. This loss of investment value was included in Investment Value Losses on our Consolidated Statements of Operations for the period ending December 31, 2003.

In March 2004, we entered into an agreement to sell the four domestic IPP investments for a total sales price of $156 million, subject to closing adjustments. An additional pretax impairment of $2 million was recorded in June 2004 (recorded to Investment Value Losses) to decrease the carrying value of the Colorado plant investments to their estimated sales price, less selling expenses. We closed on the sale of the two Florida investments and the Brush II plant in Colorado in July 2004. The sale resulted in a pretax gain of $105 million ($64 million net of tax) generated primarily from the sale of the two Florida IPPs which were not originally impaired. The gain was recorded to Gain on Disposition of Equity Investments, Net in our 2004 Consolidated Statements of Operations. The sale of the Ft. Lupton, Colorado plant closed in October 2004 and did not have a significant effect on our 2004 results of operations. Prior to the completion of the sale of each of the four IPPs, the assets for each of the four IPPs have been included in Investments in Power and Distribution Projects.

U.K. Generation (Investments - UK Operations segment)

In December 2001, we acquired two coal-fired generation plants (U.K. Generation) in the U.K. for a cash payment of $942 million and assumption of certain liabilities. Subsequently and continuing through 2002, wholesale U.K. electric power prices declined sharply as a result of domestic over-capacity and static demand. External industry forecasts and our own projections made during the fourth quarter of 2002 indicated that this situation may extend many years into the future. As a result, the U.K. Generation fixed asset carrying value at year-end 2002 was substantially impaired. A December 2002 probability-weighted discounted cash flow analysis of the fair value of our U.K. Generation indicated a 2002 pretax impairment loss of $549 million ($414 million net of tax). This impairment loss is included in Discontinued Operations on our Consolidated Statements of Operations for the year ended December 31, 2002.

In the fourth quarter of 2003, the U.K. generation plants were determined to be noncore assets and management engaged an investment advisor to assist in determining the best methodology to exit the U.K. business. Based on bids received and other market information, we recorded a pretax charge of $577 million ($375 net of tax), including asset impairments of $421 million during the fourth quarter of 2003 to write down the value of the assets to their estimated realizable value. Additional pretax charges of $157 million were also recorded in December 2003, including $122 million related to the net loss on certain cash flow hedges previously recorded in Accumulated Other Comprehensive Income (Loss) that were reclassified into earnings as a result of management’s determination that the hedged event was no longer probable of occurring and $35 million related to a first quarter of 2004 sale of certain power contracts. All write downs related to the U.K. that were booked in the fourth quarter of 2003 were included in Discontinued Operations of our Consolidated Statements of Operations for the year ended December 31, 2003. The assets and liabilities of U.K. Generation have been classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, on our December 31, 2003 Consolidated Balance Sheets.

In July 2004, we completed the sale of substantially all operations and assets within the U.K. The sale included our two coal-fired generation plants (Fiddler’s Ferry and Ferrybridge), related coal assets, and a number of related commodities contracts for approximately $456 million. The sale resulted in a pretax gain of $266 million ($128 million net of tax). As a result of the sale, the buyer assumed an additional $46 million in future reclamation liabilities and $10 million in pension liabilities. The remaining assets and liabilities include certain physical power and capacity positions and financial coal and freight swaps. Substantially all of these positions mature or have been settled with the applicable counterparties during the first quarter of 2005. The results of operations and gain on sale are included in Discontinued Operations on our Consolidated Statements of Operations for the year ended December 31, 2004. See “Discontinued Operations” and “Assets Held for Sale” sections of this note for additional information.

Texas Plants - TCC and TNC Generation Assets (Utility Operations segment)

In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies, which determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of those studies, ERCOT and AEP mutually agreed to enter into reliability-must-run (RMR) agreements, which expired in December 2002, and were subsequently renewed through December 2003. However, certain contractual provisions provided ERCOT with a 90-day termination clause if the contracted facility was no longer needed to ensure reliability of the electricity grid. With ERCOT’s approval, AEP proceeded with its planned deactivation of the remaining nine plants. In August 2003, pursuant to contractual terms, ERCOT provided notification to AEP of its intent to cancel a RMR agreement at one of the TNC plants. Upon termination of the agreement, AEP proceeded with its planned deactivation of the plant. In December 2003, AEP and ERCOT mutually agreed to renew RMR contracts at the six plants (4 TCC plants and 2 TNC plants) through December 2004, subject to ERCOT’s 90-day termination clause and the divestiture of the TCC facilities.

As a result of the decision to deactivate the TNC plants, a pretax write-down of utility assets of approximately $34 million was recorded in Asset Impairments and Other Related Charges expense during the third quarter of 2002 on our Consolidated Statements of Operations. The decision to deactivate the TCC plants resulted in a pretax write-down of utility assets of approximately $96 million, which was deferred and recorded in Regulatory Assets during the third quarter of 2002 in our Consolidated Balance Sheets.

During the fourth quarter of 2002, evaluations continued as to whether assets remaining at the deactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional pretax asset impairment charge to Asset Impairments and Other Related Charges expense of $4 million in the fourth quarter of 2002. In addition, TNC recorded related fuel inventory and materials and supplies write-downs of $3 million ($1 million in Fuel for Electric Generation and $2 million in Maintenance and Other Operation). Similarly, TCC recorded an additional pretax asset impairment write-down of $7 million, which was deferred and recorded in Regulatory Assets in the fourth quarter of 2002. TCC also recorded related inventory write-downs and adjustments of $18 million which were deferred and recorded in Regulatory Assets.

The total Texas plant pretax asset impairment of $38 million in 2002 (all related to TNC) is included in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations.

During the fourth quarter of 2003, after receiving indicative bids from interested buyers, we recorded a $938 million impairment loss and changed the classification of the plant assets from plant in service to Assets of Discontinued Operations and Held for Sale on our Consolidated Balance Sheets. In accordance with Texas legislation, the $938 million impairment was offset by the establishment of a regulatory asset, which is expected to be recovered through a wires charge, subject to the final outcome of the True-up Proceeding. As a result of the True-up Proceeding, if we are unable to recover all or a portion of our requested costs (see “Net Stranded Generation Costs” section of Note 6), any unrecovered costs could have a material adverse effect on our results of operations, cash flows and possibly financial condition.

In March 2004, we signed an agreement to sell eight natural gas plants, one coal-fired plant and one hydro plant to a nonrelated joint venture. The sale was completed in July 2004 for approximately $428 million, net of adjustments. The sale did not have a significant effect on our results of operations during the period ended December 31, 2004.

In December 2004, we recorded a pretax deduction of $185 million ($121 million net of tax) related to the TCC true-up regulatory asset for stranded generation plant costs (see “Net Stranded Generation Costs” section of Note 6). This deduction is shown as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax on our 2004 Consolidated Statements of Operations.

The remaining generation assets and liabilities of TCC are classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, on our Consolidated Balance Sheets. See “Assets Held for Sale” section of this note for additional information.

South Coast Power Limited (Investments - Other Segment)

South Coast Power Limited (SCPL) is a 50% owned venture that was formed in 1996 to build, own and operate Shoreham Power Station, a 400-megawatt, combined-cycle, gas turbine power station located in Shoreham, England. In 2002, SCPL was subject to adverse wholesale electric power rates. A December 2002 projected cash flow estimate of the fair value of the investment indicated a 2002 pretax other than temporary impairment of the equity interest in the amount of $63 million. This loss of investment value was included in Investment Value Losses in the 2002 Consolidated Statements of Operations.

In the fourth quarter of 2003, management determined that our U.K. operations were no longer part of our core business and as a result, a decision was made to exit the U.K. market. In September 2004, we completed the sale of our 50% ownership in SCPL for $47 million, resulting in a pretax gain of $48 million ($31 million net of tax) in the third quarter of 2004. This gain was recorded to Gain on Disposition of Equity Investments, Net in our Consolidated Statements of Operations for the period ended December 31, 2004. The gain reflects improved conditions in the U.K. power market.

Excess Real Estate (Investments - Other segment)

In the fourth quarter of 2002, we began to market an under-utilized office building in Dallas, Texas obtained through our merger with CSW in June 2000. One prospective buyer executed an option to purchase the building. The sale of the facility was projected by second quarter of 2003 and an estimated 2002 pretax loss on disposal of $16 million was recorded, based on the option sale price. The estimated loss was included in Asset Impairments and Other Related Charges in our 2002 Consolidated Statements of Operations. We recorded an additional pretax impairment of $6 million in Maintenance and Other Operation in our 2003 Consolidated Statements of Operations based on market data. The original prospective buyer did not complete their purchase of the building by the end of 2003, and thus, the asset no longer qualified for held for sale status. The building was then reclassified to held and used status as of December 31, 2003.

In June 2004, we entered into negotiations to sell the Dallas office building. This resulted in the asset again being classified as held for sale in the second quarter of 2004. An additional pretax impairment of $3 million was recorded in Maintenance and Other Operation expense during the second quarter of 2004 to write down the value of the office building to the current estimated sales price, less estimated selling expenses. In October 2004, we completed the sale of the Dallas office building for $8 million. The sale did not have a significant effect on our results of operations. The property asset of $12 million at December 31, 2003 has been classified on our Consolidated Balance Sheets as Assets of Discontinued Operations and Held for Sale. See “Assets Held for Sale” section of this note for additional information.

Numanco LLC (Investments - Other segment)

In November 2004, we completed the sale of Numanco LLC for a sale price of $25 million. Numanco was a provider of staffing services to the utility industry. The sale did not have a significant effect on our 2004 results of operations.

2003

C3 Communications (Investments - Other segment)

In February 2003, C3 Communications sold the majority of its assets for a sales price of $7 million. We provided for a pretax asset impairment of $82 million ($53 million net of tax) in December 2002 and the effect of the sale on 2003 results of operations was not significant. The impairment is classified in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations.

Mutual Energy Companies(Utility Operations segment)

On December 23, 2002, we sold the general partner interests and the limited partner interests in Mutual Energy CPL LP and Mutual Energy WTU LP for a base purchase price paid in cash at closing and certain additional payments, including a net working capital payment. The buyer paid a base purchase price of $146 million which was based on a fair market value per customer established by an independent appraiser and an agreed customer count. We recorded a pretax gain of $129 million ($84 million net of tax) in Other Income during 2002. We provided the buyer with a power supply contract for the two REPs and back-office services related to these customers for a two-year period. In addition, we retained the right to share in earnings from the two REPs above a threshold amount through 2006 in the event the Texas retail market develops increased earnings opportunities. No revenue was recorded in 2004 and 2003 related to these sharing agreements, pending resolution of various contracted matters. Under the Texas Restructuring Legislation, REPs are subject to a clawback liability if customer change does not attain thresholds required by the legislation. We are responsible for a portion of such liability, if any, for the period we operated the REPs in the Texas competitive retail market (January 1, 2002 through December 23, 2002). In addition, we retained responsibility for regulatory obligations arising out of operations before closing. Our wholly-owned subsidiary, Mutual Energy Service Company LLC (MESC), received an up-front payment of approximately $30 million from the buyer associated with the back-office service agreement, and MESC deferred its right to receive payment of an additional amount of approximately $9 million to secure certain contingent obligations. These prepaid service revenues were deferred on the books of MESC as of December 31, 2002 and were amortized over the two-year term of the back-office service agreement.

In February 2003, we completed the sale of MESC for $30 million dollars and realized a pretax gain of approximately $39 million, which included the recognition of the remaining balance of the original prepayment of $30 million ($27 million), as no further service obligations existed for MESC. This gain was recorded in Other Income in our Consolidated Statements of Operations.

Water Heater Assets (Utility Operations segment)

We sold our water heater rental program for $38 million and recorded a pretax loss of $4 million in the first quarter of 2003 based upon final terms of the sale agreement. We had provided for a pretax charge of $7 million in the fourth quarter of 2002 based on an estimated sales price ($3 million asset impairment charge and $4 million lease prepayment penalty). The impairment loss is included in Investment Value Losses in our Consolidated Statements of Operations. We operated a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and offer the assets for sale.

AEP Gas Power Systems LLC (Investments - Other segment)

In 2001, we acquired a 75% interest in a startup company, seeking to develop low-cost peaking generator sets powered by surplus jet turbine engines. In January 2003, AEP Gas Power Systems LLC sold its assets. We recognized a pretax goodwill impairment loss of $12 million in the first quarter of 2002 based on cash flow studies that reflect technological and operational problems associated with the underlying technology (also see “Goodwill” section of Note 3). The impairment loss was recorded in Investment Value Losses on our Consolidated Statements of Operations. The effect of the asset sale on the 2003 results of operations was not significant.

Newgulf Facility (Investments - Other segment)

In 1995, we purchased an 85 MW gas-fired peaking electrical generation facility located near Newgulf, Texas (Newgulf). In October 2002, we began negotiations with a likely buyer of the facility. We estimated a pretax loss on sale of $12 million based on the indicative bid. This loss was recorded as Asset Impairments and Other Related Charges on our Consolidated Statements of Operations during the fourth quarter of 2002. During the second quarter of 2003, we completed the sale of Newgulf and the impact on earnings in 2003 was not significant.

Nordic Trading (Investments - UK Operations segment)

In October 2002, we announced that our ongoing energy trading operations would be centered around our generation assets. As a result, we took steps to exit our coal, gas and electricity trading activities in Europe with the exception of those activities predominantly related to our U.K. generation operations. The Nordic Trading business acquired earlier in 2002 was made available for sale to potential buyers later in 2002. The estimated pretax loss on disposal recorded in 2002 of $5 million consisted of impairment of goodwill of $4 million and impairment of assets of $1 million. The estimated loss of $5 million is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. Management’s determination of a zero fair value was based on discussions with a potential buyer. The transfer of the Nordic Trading business, including the trading portfolio, to new owners was completed during the second quarter of 2003 and the impact on earnings during 2003 was not significant.

Eastex (Investments - Other segment)

In 1998, we began construction of a natural gas-fired cogeneration facility (Eastex) located near Longview, Texas and commercial operations commenced in December 2001. In June 2002, we requested that the FERC allow us to modify the FERC Merger Order and substitute Eastex as a required divestiture under the order due to the fact that the agreed upon market-power related divestiture of a plant in Oklahoma was no longer feasible. The FERC approved the request at the end of September 2002. Subsequently, in the fourth quarter of 2002, we solicited bids for the sale of Eastex and several interested buyers were identified by December 2002. The estimated pretax loss on the sale of $219 million ($142 million net of tax), which was based on the estimated fair value of the facility and indicative bids by interested buyers, was recorded in Discontinued Operations in our Consolidated Statements of Operations during the fourth quarter of 2002.

We completed the sale of Eastex during the third quarter of 2003 and the effect of the sale on 2003 results of operations was not significant. The results of operations of Eastex have been reclassified as Discontinued Operations in accordance with SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” for all years presented. See the “Discontinued Operations” section of this note for additional information.

Grupo Rede Investment (Investments - Other segment)

In December 2002, we recorded a pretax other than temporary impairment loss of $217 million ($141 million net of tax) of our 44% equity investment in Vale and our 20% equity interest in Caiua, both Brazilian electric operating companies (referred to as Grupo Rede). This impairment was due to the continuing decline in the Brazilian economy and currency which increased credit risks within Grupo Rede. This amount is included in Investment Value Losses on our 2002 Consolidated Statements of Operations.

In December 2003, we transferred our share and investment in Vale to Grupo Rede for $1 million. The effect of the transfer on our 2003 results of operations was not significant.

Excess Equipment (Investments - Other segment)

In November 2002, as a result of a cancelled development project, we obtained title to a surplus gas turbine generator. We were unsuccessful in finding potential buyers of the unit due to an over-supply of generation equipment available for sale during 2002. An estimated pretax loss on disposal of $24 million was recorded in December 2002, based on market prices of similar equipment. The loss is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations.

We completed the sale of the surplus gas turbine generator in November 2003. The proceeds from the sale were $9 million. A pretax loss of $2 million was recorded in the fourth quarter of 2003.

Ft. Davis Wind Farm (Investments - Other segment)

In the 1990’s, we developed a 6 MW wind energy project located on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002, our engineering staff determined that operation of the facility was no longer technically feasible and the lease of the underlying site should not be renewed. Dismantling of the facility was completed in 2004. An estimated pretax loss on abandonment of $5 million was recorded in December 2002. The loss was recorded in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations.

2002

SEEBOARD(Investments - Other segment)

On June 18, 2002, through a wholly-owned subsidiary, we entered into an agreement, subject to European Union (EU) approval, to sell our consolidated subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU approval was received July 25, 2002 and the sale was completed on July 29, 2002. We received approximately $941 million in net cash from the sale, subject to a working capital true-up, and the buyer assumed SEEBOARD debt of approximately $1.1 billion, resulting in a net loss of $345 million at June 30, 2002. The results of operations of SEEBOARD have been classified as Discontinued Operations for all years presented. A pretax net loss of $22 million ($14 million net of tax) was classified as Discontinued Operations in the second quarter of 2002. The remaining $323 million of the net loss has been classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see “Goodwill and Other Intangible Assets” section of Note 2 and “Goodwill” section of Note 3) and has been reported as a Cumulative Effect of Accounting Change retroactive to January 1, 2002. A $59 million pretax reduction of the net loss ($38 million net of tax) was recognized in the second half of 2002 to reflect changes in exchange rates to closing, settlement of working capital true-up and selling expenses. The total net loss recognized on the disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were used to pay down bank facilities and short-term debt. See “Discontinued Operations” section of this note for additional information.

CitiPower (Investments - Other segment)

On July 19, 2002, through a wholly-owned subsidiary, we entered into an agreement to sell CitiPower, a retail electricity and gas supply and distribution subsidiary in Australia. We completed the sale on August 30, 2002 and received net cash of approximately $175 million and the buyer assumed CitiPower debt of approximately $674 million. We recorded a pretax charge of $192 million ($125 million net of tax) as of June 30, 2002. The charge included a pretax impairment loss of $151 million ($98 million net of tax) on the remaining carrying value of an intangible asset related to a distribution license for CitiPower. The remaining $41 million pretax net loss ($27 million net of tax) was classified as a transitional goodwill impairment loss from the adoption of SFAS 142 (see “Goodwill and Other Intangible Assets” section of Note 2 and “Goodwill” section of Note 3) and was recorded as a Cumulative Effect of Accounting Change retroactive to January 1, 2002.

The pretax loss on the sale of CitiPower increased $37 million ($24 million net of tax) to $229 million ($149 million net of tax; $122 million plus $27 million of cumulative effect) in the second half of 2002 based on actual closing amounts and exchange rates. See the “Discontinued Operations” section of this note for additional information.

DISCONTINUED OPERATIONS

Management periodically assesses the overall AEP business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify the operations of those businesses or operations as discontinued operations. The assets and liabilities of these discontinued operations are classified as Assets and Liabilities of Discontinued Operations and Held for Sale until the time that they are sold.

Certain of our operations were determined to be discontinued operations and have been classified as such in 2004, 2003 and 2002. Results of operations of these businesses have been classified as shown in the following table (in millions):

	SEEBOARD			CitiPower			Eastex			Pushan Power Plant			LIG (a)			U.K. Generation			Total
2004 Revenue	$	-		$	-		$	-		$	10		$	165		$	125		$	300
2004 Pretax Income (Loss)		(3	)		-			-			9			(12	)		164			158
2004 Earnings (Loss), Net of Tax		(2	)		-			-			6			(12	)		91	(b)		83
2003 Revenue		-			-			58			60			653			125			896
2003 Pretax Income (Loss)		-			(20	)		(23	)		4			(122	)		(713	)		(874	)
2003 Earnings (Loss), Net of Tax		16			(13	)		(14	)		5			(91	)		(508	)(c)		(605	)
2002 Revenue		694			204			73			57			507			251			1,786
2002 Pretax Income (Loss)		180			(190	)		(239	)		(13	)		14			(579	)		(827	)
2002 Earnings (Loss), Net of Tax		96			(123	)		(156	)		(7	)		8			(472	)(d)		(654	)

(a)	Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC.
(b)	Earnings per share related to the UK Operations was $0.23.
(c)	Earnings per share related to the UK Operations was $(1.32).
(d)	Earnings per share related to the UK Operations was $(1.42).

ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES

In 2004, AEP recorded pretax impairments of assets (including goodwill) and investments totaling $18 million ($15 million related to Investment Value Losses, and $3 million related to charges recorded for Excess Real Estate in Maintenance and Other Operation in the Consolidated Statements of Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, our decision to exit noncore businesses and other factors.

In 2003, AEP recorded pretax impairments of assets (including goodwill) and investments totaling $1.4 billion [consisting of approximately $650 million related to Asset Impairments of $610 million and Other Related Charges of $40 million, $70 million related to Investment Value Losses, $711 million related to Discontinued Operations ($550 million of impairments and $161 million of other charges) and $6 million related to charges recorded for Excess Real Estate in Maintenance and Other Operation in the Consolidated Statements of Operations] that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, our decision to exit noncore businesses and other factors.

In 2002, AEP recorded pretax impairments of assets (including goodwill) and investments totaling $1.7 billion (consisting of approximately $318 million related to Asset Impairments, $321 million related to Investment Value Losses, $938 million related to Discontinued Operations and $88 million related to charges recorded in other lines within the Consolidated Statements of Operations) that reflected downturns in energy trading markets, projected long-term decreases in electricity prices, and other factors. These impairments exclude the transitional goodwill impairment loss from adoption of SFAS 142 (see “Goodwill and Other Intangible Assets” section of Note 2).

The categories of impairments and gains on dispositions include:

	2004			2003			2002
	(in millions)
Asset Impairments and Other Related Charges (Pretax)
AEP Coal, Inc.	$	-		$	67		$	60
HPL and Other		-			315			-
Power Generation Facility		-			258			-
Blackhawk Coal Company		-			10			-
Ft. Davis Wind Farm		-			-			5
Texas Plants		-			-			38
Newgulf Facility		-			-			12
Excess Equipment		-			-			24
Nordic Trading		-			-			5
Excess Real Estate		-			-			16
Telecommunications - AEPC/C3		-			-			158
Total	$	-		$	650		$	318
Investment Value Losses (Pretax)
Independent Power Producers	$	(2	)	$	(70	)	$	-
Bajio		(13	)		-			-
Water Heater Assets		-			-			(3	)
South Coast Power Investment		-			-			(63	)
Telecommunications - AFN		-			-			(14	)
AEP Gas Power Systems		-			-			(12	)
Grupo Rede Investment - Vale		-			-			(217	)
Technology Investments		-			-			(12	)
Total	$	(15	)	$	(70	)	$	(321	)
Gain on Disposition of Equity Investments, Net
Independent Power Producers	$	105		$	-		$	-
South Coast Power Investment		48			-			-
Total	$	153		$	-		$	-
“Impairments and Other Related Charges” and “Operations” Included in  Discontinued Operations (Net of tax)
Impairments and Other Related Charges:
U.K. Generation Plants	$	-		$	(375	)	$	(414	)
Louisiana Intrastate Gas (a)		-			(99	)		-
CitiPower		-			-			(122	)
Eastex		-			-			(142	)
SEEBOARD		-			-			24
Pushan		-			-			(13	)
Total (b)	$	-		$	(474	)	$	(667	)
Operations:
U.K. Generation Plants	$	91		$	(133	)	$	(58	)
Louisiana Intrastate Gas (a)		(12	)		8			8
CitiPower		-			(13	)		(1	)
Eastex		-			(14	)		(14	)
SEEBOARD		(2	)		16			72
Pushan		6			5			6
Total	$	83		$	(131	)	$	13
Total Discontinued Operations	$	83		$	(605	)	$	(654	)

(a)	Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC.
(b)	See the “Dispositions” and “Discontinued Operations” sections of this note for the pretax impairment figures.

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 an unrelated party. In May 2004, we received notice from the two 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 our nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. One of these agreements is currently being challenged in Dallas County, Texas State District Court by the unrelated party with which we entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. 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 and liabilities related to the Oklaunion Power Station have been classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, in our Consolidated Balance Sheets as of December 31, 2004 and 2003.

Texas Plants - South Texas Project (Utility Operations segment)

In February 2004, we signed an agreement to sell TCC’s 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, we received notice from co-owners of their decisions to exercise their rights of first refusal with terms similar to the original agreement. In September 2004, we entered into sales agreements with two of our nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. We do not expect the sale to have a significant effect on our future results of operations. We expect the sale to close in the first six months of 2005. TCC’s assets and liabilities related to STP have been classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, in our Consolidated Balance Sheets as of December 31, 2004 and 2003.

The Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale at December 31, 2004 and 2003 are as follows:

December 31, 2004	Texas Plants
Assets:	(in millions)
Other Current Assets	$	24
Property, Plant and Equipment, Net		413
Regulatory Assets		48
Nuclear Decommissioning Trust Fund		143
Total Assets of Discontinued Operations and Held for Sale	$	628
Liabilities:
Regulatory Liabilities	$	1
Asset Retirement Obligations		249
Total Liabilities of Discontinued Operations and Held for Sale	$	250

December 31, 2003	AEP Coal		Pushan Power Plant		LIG (excluding Jefferson Island)		Excess Real Estate		Jefferson Island		U.K. Generation		Texas Plants		Total
Assets:	(in millions)
Current Risk Management Assets	$	-	$	-	$	-	$	-	$	-	$	560	$	-	$	560
Other Current Assets		6		24		49		-		1		685		57		822
Property, Plant and Equipment, Net		13		142		109		12		62		99		797		1,234
Regulatory Assets		-		-		-		-		-		-		49		49
Decommissioning Trusts		-		-		-		-		-		-		125		125
Goodwill		-		-		1		-		14		-		-		15
Long-term Risk Management Assets		-		-		-		-		-		274		-		274
Other		-		-		8		-		1		6		-		15
Total Assets of Discontinued  Operations and Held for Sale	$	19	$	166	$	167	$	12	$	78	$	1,624	$	1,028	$	3,094
Liabilities:
Current Risk Management Liabilities	$	-	$	-	$	15	$	-	$	-	$	767	$	-	$	782
Other Current Liabilities		-		26		42		-		4		221		-		293
Long-term Debt		-		20		-		-		-		-		-		20
Long-term Risk Management  Liabilities		-		-		-		-		-		435		-		435
Regulatory Liabilities		-		-		-		-		-		-		9		9
Asset Retirement Obligations		11		-		-		-		-		29		219		259
Employee Pension Obligations		-		-		-		-		-		12		-		12
Deferred Credits and Other		3		57		6		-		-		-		-		66
Total Liabilities of Discontinued  Operations and Held for Sale	$	14	$	103	$	63	$	-	$	4	$	1,464	$	228	$	1,876

ASSETS HELD AND USED

In 2003 and 2002, we recorded the following impairments related to assets held and used (including goodwill) to Asset Impairments and Other Related Charges on our Consolidated Statements of Operations as discussed below:

HPL and Other (Investments - Gas Operations segment)

HPL owns, or leases, and operates natural gas gathering, transportation and storage operations in Texas. In 2003, management announced that we were in the process of divesting our noncore assets, which includes the assets within our Investments-Gas Operations segment. During the fourth quarter of 2003, based on a probability-weighted, net of tax cash flow analysis of the fair value of HPL, we recorded a pretax impairment of $300 million ($218 million net of tax). This impairment included a pretax impairment of $150 million related to goodwill, reflecting management’s decision not to operate HPL as a major trading hub. The cash flow analysis used management’s estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters (see “Enron Bankruptcy” section of Note 7) and a net of tax risk free discount rate of 3.3% over the remaining life of the assets.

We also recorded a pretax charge of $15 million ($10 million net of tax) in the fourth quarter of 2003. This impairment is included in Asset Impairments and Other Related Charges on our Consolidated Statements of Operations. This charge related to the effect of the write-off of certain HPL and LIG assets and the impairment of goodwill related to our former optimization strategy of LIG assets by AEP Energy Services.

The total HPL pretax impairment of $315 million in 2003 is included in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations.

See Note 19 for additional discussion of the sale of HPL in 2005.

Blackhawk Coal Company (Utility Operations segment)

Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M and was formerly engaged in coal mining operations until they ceased due to gas explosions in the mine. During the fourth quarter of 2003, it was determined that the carrying value of the investment was impaired based on an updated valuation reflecting management’s decision not to pursue development of potential gas reserves. As a result, a pretax charge of $10 million was recorded to reduce the value of the coal and gas reserves to their estimated realizable value. This charge was recorded in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations.

Power Generation Facility (Investments - Other segment)

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop, construct, and finance a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to us. Juniper will own the Facility and lease it to AEP after construction is completed and we will sublease the Facility to The Dow Chemical Company.

At December 31, 2002, we would have reported the Facility and related obligations as an operating lease upon achieving commercial operation. In the fourth quarter of 2003, we chose to not seek funding from Juniper for budgeted and approved pipeline construction costs related to the Facility. In order to continue reporting the Facility as an off-balance sheet financing, we were required to seek funding of our construction costs from Juniper. As a result, we recorded $496 million of construction work in progress and the related financing liability for the debt and equity as of December 31, 2003. At December 31, 2004 and 2003, the lease of the Facility is reported as an owned asset under a lease financing transaction. Since Juniper’s funded obligations of the Facility are recorded on our financial statements, the obligations under the lease agreement are excluded from the table of future minimum lease payments in Note 16.

The uncertainty of the litigation between Tractebel Energy Marketing, Inc. (TEM) and ourselves, combined with a substantial oversupply of generation capacity in the markets where we would otherwise sell the power freed up by TEM contract termination, triggered us to review the project for possible impairment of its reported values. We determined that the value of the Facility was impaired and recorded a pretax impairment of $258 million ($168 million net of tax) in December 2003. The impairment was recorded to Asset Impairments and Other Related Charges on our Consolidated Statements of Operations.

See further discussion in “Power Generation Facility” section of Note 7.

OTHER LOSSES

2004

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-megawatt power plant in Mexico. Due to the decision to divest noncore assets, we began marketing our investment in Bajio to potential buyers in the third quarter of 2003.

In December 2004, on the basis of an indicative bid by a prospective buyer, an estimated pretax other than temporary impairment of $13 million was recorded for Bajio and classified in Investment Value Losses on our Consolidated Statements of Operations.

2002

Telecommunications (Investments - Other segment)

We developed businesses to provide telecommunication services to businesses and other telecommunication companies through broadband fiber optic networks. The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50% share of AFN, LLC (AFN), a joint venture. Due to the difficult economic conditions in these businesses and the overall telecommunications industry, the AEP Board approved in December 2002 a plan to cease operations of these businesses. We took steps to market the assets of the businesses to potential interested buyers in the fourth quarter of 2002.

We completed the sale of substantially all the assets of C3 in the first quarter of 2003 as discussed in the “Dispositions” section of this note. AFN closed on the sale of substantially all of its assets in January 2004 with no significant additional effect on results of operations in 2004. The sale of remaining telecommunication assets is proceeding.

An estimated pretax impairment loss of $158 million ($76 million related to AEPC and $82 million related to C3) was recorded in December 2002 and is classified in Asset Impairments and Other Related Charges in our Consolidated Statements of Operations. An estimated pretax loss in value of the investment in AFN of $14 million was recorded in December 2002 and is classified in Investment Value Losses in our Consolidated Statements of Operations. The estimated losses were based on indicative bids by potential buyers.

Technology Investments (Investments - Other segment)

We previously made investments totaling $12 million in four early-stage or startup technologies involving pollution control and procurement. An analysis in December 2002 of the viability of the underlying technologies and the projected performance of the investee companies indicated that the investments were unlikely to be recovered, and an other than temporary impairment of the entire amount of the equity interest under APB 18, “The Equity Method of Accounting for Investments in Common Stock,” was recorded. The loss of investment value is included in Investment Value Losses on our Consolidated Statements of Operations.

11.BENEFIT PLANS

In the U.S. we sponsor two qualified pension plans and two nonqualified pension plans. A substantial majority of our employees in the U.S. are covered by either one qualified plan or both a qualified and a nonqualified pension plan. Other postretirement benefit plans are sponsored by us to provide medical and life insurance benefits for retired employees in the U.S. We implemented FSP FAS 106-2 in the second quarter of 2004, retroactive to the first quarter of 2004 (see “FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” section of Note 2). The Medicare subsidy reduced our FAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service by $202 million contributing to an actuarial gain in 2004. The tax-free subsidy reduced 2004’s net periodic postretirement benefit cost by a total of $29 million, including $12 million of amortization of the actuarial gain, $4 million of reduced service cost, and $13 million of reduced interest cost on the APBO.

We also had a foreign pension plan for employees of AEP Energy Services UK Generation Limited (Genco) in the U.K. The Genco pension plan had $7 million of accumulated benefit obligations in excess of plan assets at December 31, 2002. The plan was in an overfunded position at December 31, 2003. The plan was transferred in 2004 in conjunction with the sale of the U.K. generation assets.

The following tables provide a reconciliation of the changes in the plans’ projected benefit obligations and fair value of assets over the two-year period ending at the plan’s measurement date of December 31, 2004, and a statement of the funded status as of December 31 for both years:

Projected Pension Obligations, Plan Assets, Funded Status as of December 31, 2004 and 2003:

	Pension Plans						Other Postretirement Benefit Plans
	2004			2003			2004			2003
	(in millions)
Change in Projected Benefit Obligation:
Projected Obligation at January 1	$	3,688		$	3,583		$	2,163		$	1,877
Service Cost		86			80			41			42
Interest Cost		228			233			117			130
Participant Contributions		-			-			18			14
Actuarial (Gain) Loss		379			91			(130	)		192
Benefit Payments		(273	)		(299	)		(109	)		(92	)
Projected Obligation at December 31	$	4,108		$	3,688		$	2,100		$	2,163
Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1	$	3,180		$	2,795		$	950		$	723
Actual Return on Plan Assets		409			619			98			122
Company Contributions (a)		239			65			136			183
Participant Contributions		-			-			18			14
Benefit Payments (a)		(273	)		(299	)		(109	)		(92	)
Fair Value of Plan Assets at December 31	$	3,555		$	3,180		$	1,093		$	950
Funded Status:
Funded Status at December 31	$	(553	)	$	(508	)	$	(1,007	)	$	(1,213	)
Unrecognized Net Transition Obligation		-			2			179			206
Unrecognized Prior Service Cost (Benefit)		(9	)		(12	)		5			6
Unrecognized Net Actuarial Loss		1,040			797			795			977
Net Asset (Liability) Recognized	$	478		$	279		$	(28	)	$	(24	)

(a) Our contributions and benefit payments include only those amounts contributed directly to or paid directly from plan assets.

Amounts Recognized in the Balance Sheet as of December 31, 2004 and 2003:

	Pension Plans						Other Postretirement Benefit Plans
	2004			2003			2004			2003
	(in millions)
Prepaid Benefit Costs	$	524	(a)	$	325		$	-		$	-
Accrued Benefit Liability		(46	)		(46	)		(28	)		(24	)
Additional Minimum Liability		(566	)		(723	)		N/A			N/A
Intangible Asset		36			39			N/A			N/A
Pretax Accumulated Other Comprehensive Income		530			684			N/A			N/A
Net Asset (Liability) Recognized	$	478		$	279		$	(28	)	$	(24	)

N/A = Not Applicable

(a) Includes $386 million related to the qualified plan that became fully funded upon receipt of the December 2004 discretionary contribution.

Pension and Other Postretirement Plans’ Assets:

The asset allocations for our pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2005		2004		2003
Asset Category	(in percentage)
Equity Securities		70		68		71
Debt Securities		28		25		27
Cash and Cash Equivalents		2		7		2
Total		100		100		100

The asset allocations for our other postretirement benefit plans at the end of 2004 and 2003, and target allocation for 2005, by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2005		2004		2003
Asset Category	(in percentage)
Equity Securities		70		70		61
Debt Securities		28		28		36
Other		2		2		3
Total		100		100		100

Our investment strategy for our employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. We regularly review the actual asset allocation and periodically rebalance the investments to our targeted allocation when considered appropriate. Because of a $200 million discretionary contribution at the end of 2004, the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2005.

The value of our pension plans’ assets increased to $3.6 billion at December 31, 2004 from $3.2 billion at December 31, 2003. The qualified plans paid $265 million in benefits to plan participants during 2004 (nonqualified plans paid $8 million in benefits).

We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.

Accumulated Benefit Obligation:	2004		2003
	(in millions)
Qualified Pension Plans	$	3,918	$	3,549
Nonqualified Pension Plans		80		76
Total	$	3,998	$	3,625

Minimum Pension Liability:

Our combined pension funds are underfunded in total (plan assets are less than projected benefit obligations) by $553 million at December 31, 2004. For our underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets of these plans at December 31, 2004 and 2003 were as follows:

	Underfunded Pension Plans
	2004		2003
End of Year	(in millions)
Projected Benefit Obligation	$	2,978	$	3,688
Accumulated Benefit Obligation		2,880		3,625
Fair Value of Plan Assets		2,406		3,180
Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets		474		445

A minimum pension liability is recorded for pension plans with an accumulated benefit obligation in excess of the fair value of plan assets. The minimum pension liability for the underfunded pension plans declined during 2004 and 2003, resulting in the following favorable changes, which do not affect earnings or cash flow:

	Decrease in Minimum Pension Liability
	2004			2003
	(in millions)
Other Comprehensive Income	$	(92	)	$	(154	)
Deferred Income Taxes		(52	)		(75	)
Intangible Asset		(3	)		(5	)
Other		(10	)		13
Minimum Pension Liability	$	(157	)	$	(221	)

We made an additional discretionary contribution of $200 million in the fourth quarter of 2004 and intend to make additional discretionary contributions of approximately $100 million per quarter in 2005 to meet our goal of fully funding all qualified pension plans by the end of 2005.

Actuarial Assumptions for Benefit Obligations:

The weighted-average assumptions as of December 31, used in the measurement of our benefit obligations are shown in the following tables:

	Pension Plans				Other Postretirement Benefit Plans
	2004		2003		2004		2003
	(in percentages)
Discount Rate		5.50		6.25		5.80		6.25
Rate of Compensation Increase		3.70		3.70		N/A		N/A

The method used to determine the discount rate that we utilize for determining future benefit obligations was revised in 2004. Historically, it has been based on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, we changed to a duration based method in which a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody's AA bond index was constructed with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for pension plans and 5.80% for other postretirement benefit plans.

The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.

Estimated Future Benefit Payments and Contributions:

Information about the expected cash flows for the pension (qualified and nonqualified) and other postretirement benefit plans is as follows:

	Pension Plans						Other Postretirement Benefit Plans
Employer Contributions	2005			2004			2005		2004
	(in millions)
Required Contributions (a)	$	17		$	31			N/A		N/A
Additional Discretionary Contributions		400	(b)		200	(b)	$	142	$	137

(a)	Contribution required to meet minimum funding requirement per the U.S. Department of Labor.
(b)	Contribution in 2004 and expected contribution in 2005 in excess of the required contribution to fully fund our qualified pension plans by the end of 2005.

The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ expense for accounting purposes and is provided for in agreements with state regulatory authorities.

The table below reflects the total benefits expected to be paid from the plan or from our assets, including both our share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates, and variances in actuarial results. The estimated payments for pension benefits and other postretirement benefits are as follows:

	Pension Plans		Other Postretirement Benefit Plans
	Pension Payments		Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2005	$	293	$	115	$	-
2006		302		122		(9	)
2007		317		131		(10	)
2008		327		140		(11	)
2009		348		151		(12	)
Years 2010 to 2014, in Total		1,847		867		(72	)

Components of Net Periodic Benefit Cost:

The following table provides the components of our net periodic benefit cost (credit) for the plans for fiscal years 2004, 2003 and 2002:

	Pension Plans									Other Postretirement Benefit Plans
	2004			2003			2002			2004			2003			2002
	(in millions)
Service Cost	$	86		$	80		$	72		$	41		$	42		$	34
Interest Cost		228			233			241			117			130			114
Expected Return on Plan Assets		(292	)		(318	)		(337	)		(81	)		(64	)		(62	)
Amortization of Transition (Asset) Obligation		2			(8	)		(9	)		28			28			29
Amortization of Prior Service Cost		(1	)		(1	)		(1	)		-			-			-
Amortization of Net Actuarial (Gain) Loss		17			11			(10	)		36			52			27
Net Periodic Benefit Cost (Credit)		40			(3	)		(44	)		141			188			142
Capitalized Portion		(10	)		(3	)		15			(46	)		(43	)		(26	)
Net Periodic Benefit Cost (Credit)   Recognized as Expense	$	30		$	(6	)	$	(29	)	$	95		$	145		$	116

Actuarial Assumptions for Net Periodic Benefit Costs:

The weighted-average assumptions as of January 1, used in the measurement of our benefit costs are shown in the following tables:

	Pension Plans						Other Postretirement Benefit Plans
	2004		2003		2002		2004		2003		2002
	(in percentage)
Discount Rate		6.25		6.75		7.25		6.25		6.75		7.25
Expected Return on Plan Assets		8.75		9.00		9.00		8.35		8.75		8.75
Rate of Compensation Increase		3.70		3.70		3.70		N/A		N/A		N/A

The expected return on plan assets for 2004 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as unrelated business income taxes) was reduced to 8.35%.

The health care trend rate assumptions used for other postretirement benefit plans measurement purposes are shown below:

Health Care Trend Rates:	2004			2003
Initial		10.0	%		10.0	%
Ultimate		5.0	%		5.0	%
Year Ultimate Reached		2009			2008

Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit health care plans. A 1% change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost	$	27	$	(21	)
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation		302		(245	)

AEP Savings Plans

We sponsor various defined contribution retirement savings plans eligible to substantially all non-United Mine Workers of America (UMWA) U.S. employees. These plans include features under Section 401(k) of the Internal Revenue Code and provide for company matching contributions. On January 1, 2003, the two major AEP Savings Plans merged into a single plan. Our contributions to the plan are 75% of the first 6% of eligible employee compensation. The cost for contributions to these plans totaled $55.0 million in 2004, $57.0 million in 2003 and $60.1 million in 2002.

Other UMWA Benefits

We provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds.

The health and welfare benefits are administered by us and benefits are paid from our general assets. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2004, 2003 and 2002.

12.STOCK-BASED COMPENSATION

The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) authorizes the use of 15,700,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. The Plan was adopted in 2000 by the Board of Directors and shareholders.

Stock-based compensation awards granted by AEP include restricted stock units, restricted shares, performance share units and stock options. Restricted stock units generally vest, subject to the participant’s continued employment, in approximately equal 1/3 or 1/5 increments on each of the first three or five 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. AEP awarded 105,852 and 105,910 restricted stock units, including units awarded for dividends, with weighted-average grant-date fair values of $32.03 and $22.17 per unit in 2004 and 2003, respectively. Restricted stock units were not granted prior to 2003. Compensation cost is recorded over the vesting period based on the market value on the grant date. Expense associated with units that are forfeited is reversed in the period of forfeiture.

AEP awarded 300,000 restricted shares in 2004, which vest over periods ranging from 1 to 8 years. Compensation cost is recorded over the vesting period based on the market value of $30.76 per unit on the grant date. Restricted shares were not granted prior to 2004.

Performance share units are equal in value to shares of AEP common stock but are subject to an attached performance factor ranging from 0% to 200%. The performance factor 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. Performance share units are typically paid in cash at the end of a three-year 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 until the end of the participant’s AEP career. Phantom stock units have a value equivalent to AEP common stock and are typically paid in cash upon the participant’s termination of employment. AEP awarded 171,270, 1,103,542 and 167,040 performance share units, including units awarded for dividends on other units, with weighted-average grant-date fair values of $31.42, $27.94 and $42.14 per unit in 2004, 2003 and 2002, respectively. In 2004 and 2003, no performance share units were deferred into phantom stock units to satisfy stock ownership requirements. However, AEP awarded 8,809 and 14,042 additional phantom stock units as dividends on other units with weighted-average grant-date fair values of $32.92 and $25.60 per unit in 2004 and 2003, respectively. In 2002, 42,115 performance share units were deferred into phantom stock units to satisfy stock ownership requirements and 15,388 phantom stock units with a weighted-average grant-date fair value of $34.20 per unit were awarded as dividends on other units. The compensation cost for performance share units is recorded over the vesting period, and the liability for both the performance share and phantom stock unit is adjusted for changes in fair market value. Amounts equivalent to cash dividends on both performance share and phantom stock units accrue as additional units.

Under the Plan, the exercise price of all stock option grants must equal or exceed the market price of AEP’s common stock on the date of grant, and in accordance with its policy, AEP does not record compensation expense. AEP does, however, anticipate adopting SFAS 123R effective July 1, 2005 which will result in the recording of compensation expense for stock options (see “SFAS 123R” in Note 2). AEP historically has granted options that have a ten-year life and vest, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1 following the first, second and third anniversary of the grant date.

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 or expired. Under the CSW stock option plan, the option price was equal to the fair market valueof 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.

A summary of AEP stock option transactions in fiscal years 2004, 2003 and 2002 is as follows:

	2004					2003					2002
	Options			Weighted Average Exercise Price		Options			Weighted Average Exercise Price		Options			Weighted Average Exercise Price
	(in thousands)					(in thousands)					(in thousands)
Outstanding at beginning of year		9,095		$	33		8,787		$	34		6,822		$	37
Granted		149		$	31		928		$	28		2,923		$	27
Exercised		(525	)	$	27		(23	)	$	27		(600	)	$	36
Forfeited		(489	)	$	34		(597	)	$	33		(358	)	$	41
Outstanding at end of year		8,230		$	33		9,095		$	33		8,787			34
Options exercisable at end of year		6,069		$	35		3,909		$	36		2,481		$	36
Weighted average exercise price   of options:
Granted above Market Price					N/A					N/A				$	27
Granted at Market Price				$	31				$	28				$	27

The following table summarizes information about AEP stock options outstanding at December 31, 2004:

Options Outstanding

Range of Exercise Prices	Number Outstanding		Weighted Average Remaining Life		Weighted Average Exercise Price
	(in thousands)		(in years)
$25.73 - $27.95		2,833		7.3	$	27.30
$30.76 - $35.63		4,905		4.9		35.47
$43.79 - $49.00		492		6.4		46.05
		8,230		5.8		33.29

Options Exercisable

Range of Exercise Prices	Number Outstanding		Weighted Average Exercise Price
	(in thousands)
$25.73 - $27.95		914	$	27.11
$30.76 - $35.63		4,756		35.62
$43.79 - $49.00		399		46.42
		6,069		35.05

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

The fair value of each option award is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used to estimate the fair value of AEP options granted:

	2004			2003			2002
Risk Free Interest Rate		4.14	%		3.92	%		3.53	%
Expected Life		7 years			7 years			7 years
Expected Volatility		28.17	%		27.57	%		29.78	%
Expected Dividend Yield		4.84	%		4.86	%		6.15	%
Weighted average fair value of options:
Granted above Market Price		N/A			N/A		$	4.58
Granted at Market Price	$	6.06		$	5.26		$	4.37

13.BUSINESS SEGMENTS

We identified our reportable segments based on the nature of the product and services and geography. Our core operations involve domestic utility operations, including generation, transmission and distribution of electric energy. Certain Investments segments are reported by product or service (Gas Operations and Other) while our Investments - UK Operations segment is distinguished by its geography. These operating segments are not aggregated.

In addition to our business operations with external customers, our business segments also provide products and services between business segments. These intersegment activities primarily consist of risk management activities and barging activities performed by our Utility Operations segment and the sale of gas by our Investments - Gas Operations segment. Our Investments - Other segment provides accounts receivable factoring, barging activities and until the second quarter of 2004, the sale of coal to our Utility Operations segment. Our All Other segment includes items such as interest related to financing costs, litigation costs on behalf of other segments and other corporate-type services.

Our current international portfolio, presented in our Investments - Other segment, includes only limited investments in the generation and supply of power in Mexico and the Pacific Rim. We sold our generation assets in the U.K. and China in 2004. In 2002, we sold our investments in international distribution companies in Australia and the U.K.

Our segments and their related business activities are as follows:

Utility Operations

· Domestic generation of electricity for sale to retail and wholesale customers

· Domestic electricity transmission and distribution

Investments - Gas Operations (a)

· Gas and pipeline and storage services

Investments - UK Operations (b)

· International generation of electricity for sale to wholesale customers

· Coal procurement and transportation to AEP’s U.K. plants

Investments - Other (c)

· Bulk commodity barging operations, wind farms, independent power producers and other energy supply businesses

(a)	Operations of LIG Pipeline Company and its subsidiaries, including Jefferson Island Storage & Hub LLC, were classified as discontinued during 2003 and were sold during 2004. The remaining gas assets were sold during the first quarter of 2005.
(b)	UK Operations were classified as discontinued during 2003 and were sold during 2004.
(c)	Four independent power producers were sold during 2004.

The tables below present segment income statement information for the twelve months ended December 31, 2004, 2003 and 2002 and balance sheet information for the years ended December 31, 2004 and 2003. These amounts include certain estimates and allocations where necessary. Prior year amounts have been reclassified to conform to the current year’s presentation.

					Investments
		Utility Operations			Gas Operations			UK Operations			Other		All Other (a)			Reconciling Adjustments (b)			Consolidated
2004			(in millions)
Revenues from:
	External Customers	$	10,513		$	3,064		$	-		$	480	$	-		$	-		$	14,057
	Other Operating Segments		120			50			-			80		7			(257	)		-
Total Revenues		$	10,633		$	3,114		$	-		$	560	$	7		$	(257	)	$	14,057
Income (Loss) Before Discontinued   Operations, Extraordinary Item and   Cumulative Effect of Accounting Changes		$	1,171		$	(51	)	$	-		$	78	$	(71	)	$	-		$	1,127
Discontinued Operations, Net of Tax			-			(12	)		91			4		-			-			83
Extraordinary Item, Net of Tax			(121	)		-			-			-		-			-			(121	)
Net Income (Loss)		$	1,050		$	(63	)	$	91		$	82	$	(71	)	$	-		$	1,089
Depreciation and Amortization Expense		$	1,256		$	11		$	-		$	32	$	1		$	-		$	1,300
Gross Property Additions			1,527			132			-			34		-			-			1,693
As of December 31, 2004
Total Assets		$	32,281		$	1,801		$	221	(c)	$	1,345	$	10,158		$	(11,143	)	$	34,663
Assets Held for Sale			628			-			-			-		-			-			628
Investments in Equity Method Subsidiaries			-			33			-			117		-			-			150

(a)	All Other includes interest, litigation and other miscellaneous parent company expenses.
(b)	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.
(c)	Total Assets of $221 million for the Investments-UK Operations segment include $124 million in affiliated accounts receivable that are eliminated in consolidation. The majority of the remaining $97 million in assets represents cash equivalents and third party receivables.

			Investments
	Utility Operations		Gas Operations			UK Operations			Other			All Other (a)			Reconciling Adjustments(b)			Consolidated
2003	(in millions)
Revenues from:
External Customers	$	10,869	$	3,099		$	-		$	699		$	-		$	-		$	14,667
Other Operating Segments		146		27			-			94			11			(278	)		-
Total Revenues	$	11,015	$	3,126		$	-		$	793		$	11		$	(278	)	$	14,667
Income (Loss) Before Discontinued   Operations, Extraordinary Item and      Cumulative Effect of Accounting Changes	$	1,219	$	(290	)	$	-		$	(278	)	$	(129	)	$	-		$	522
Discontinued Operations, Net of Tax		-		(91	)		(508	)		(6	)		-			-			(605	)
Cumulative Effect of Accounting Changes,   Net of Tax		236		(22	)		(21	)		-			-			-			193
Net Income (Loss)	$	1,455	$	(403	)	$	(529	)	$	(284	)	$	(129	)	$	-		$	110
Depreciation and Amortization Expense	$	1,250	$	18		$	-		$	39		$	-		$	-		$	1,307
Gross Property Additions		1,323		25			-			10			-			-			1,358
As of December 31, 2003
Total Assets	$	30,829	$	2,494		$	1,662		$	1,738		$	13,604		$	(13,546	)	$	36,781
Assets Held for Sale		1,028		245			1,624			185			12			-			3,094
Investments in Equity Method Subsidiaries		-		36			-			156			-			-			192

(a)	All Other includes interest, litigation and other miscellaneous parent company expenses.
(b)	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

			Investments
	Utility Operations		Gas Operations			UK Operations			Other			All Other(a)			Reconciling Adjustments			Consolidated
2002	(in millions)
Revenues from:
External Customers	$	10,446	$	2,071		$	-		$	910		$	-		$	-		$	13,427
Other Operating Segments		45		212			-			149			-			(406	)		-
Total Revenues	$	10,491	$	2,283		$	-		$	1,059		$	-		$	(406	)	$	13,427
Income (Loss) Before Discontinued Operations,   Extraordinary Item and Cumulative Effect of   Accounting Changes	$	1,154	$	(99	)	$	-		$	(522	)	$	(48	)	$	-		$	485
Discontinued Operations, Net of Tax		-		8			(472	)		(190	)		-			-			(654	)
Cumulative Effect of Accounting Changes,   Net of Tax		-		-			-			(350	)		-			-			(350	)
Net Income (Loss)	$	1,154	$	(91	)	$	(472	)	$	(1,062	)	$	(48	)	$	-		$	(519	)
Depreciation and Amortization Expense	$	1,276	$	13		$	-		$	67		$	-		$	-		$	1,356
Gross Property Additions		1,517		47			-			25			96			-			1,685

(a) All Other includes interest, litigation and other miscellaneous parent company expenses.

14.DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS

DERIVATIVES AND HEDGING

SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. However, energy markets are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Contracts that have been designated as normal purchase or normal sale under SFAS 133 are not considered derivatives and are recognized on the accrual or settlement basis.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on if the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Consolidated Statements of Operations. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses in the Consolidated Statements of Operations depending on the relevant facts and circumstances.

We designate the hedging instrument, based on the exposure being hedged, as a fair value hedge, a cash flow hedge or a hedge of a net investment in a foreign operation. For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), we recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in Revenues in the Consolidated Statements of Operations during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) and subsequently reclassify it to Revenues in the Consolidated Statements of Operations when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change. For a hedge of a net investment in a foreign currency, we include the effective portion of the gain or loss in Accumulated Other Comprehensive Income as part of the cumulative translation adjustment. We recognize any ineffective portion of the gain or loss in Revenues immediately during the period of change.

Fair Value Hedging Strategies

We enter into natural gas forward and swap transactions to hedge natural gas inventory. The purpose of the hedging activity was to protect the natural gas inventory against changes in fair value due to changes in the spot gas prices. The derivative contracts designated as fair value hedges of our natural gas inventory were MTM each month based upon changes in the NYMEX forward prices, whereas the natural gas inventory was MTM on a monthly basis based upon changes in the Gas Daily spot price at the end of the month. The differences between the indices used to MTM the natural gas inventory and the forward contracts designated as fair value hedges can result in volatility in our reported net income. However, over time gains or losses on the sale of the natural gas inventory will be offset by gains or losses on the fair value hedges, resulting in the realization of gross margin the Company anticipated at the time the transaction was structured. In the third quarter of 2004, the fair value hedges were de-designated, as a result the existing hedged inventory was held at the market price on the fair value hedge de-designation date with subsequent additions to inventory carried at cost. During the years ended December 31, 2004 and 2003, we recognized a pretax loss of approximately $(27.0) million and $(3.4) million, respectively, within revenues related to hedge ineffectiveness and changes in time value excluded from the assessment of hedge ineffectiveness.

We enter into interest rate forward and swap transactions in order to manage interest rate risk exposure. The interest rate forward and swap transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. We do not hedge all interest rate exposure.

Cash Flow Hedging Strategies

We enter into forward contracts to protect against the reduction in value of forecasted cash flows resulting from transactions denominated in foreign currencies. When the dollar strengthens significantly against the foreign currencies, the decline in value of future foreign currency revenue is offset by gains in the value of the forward contracts designated as cash flow hedges. Conversely, when the dollar weakens, the increase in the value of future foreign currency cash flows is offset by losses in the value of forward contracts. We do not hedge all foreign currency exposure.

We enter into interest rate forward and swap transactions in order to manage interest rate risk exposure. These transactions effectively modify our exposure to interest risk by converting a portion of our floating-rate debt to a fixed rate. During 2004, we also entered into various forward starting interest rate swap contracts to manage the interest rate exposure on anticipated borrowings of fixed-rate debt through the second quarter of 2005. The anticipated debt offerings have a high probability of occurrence because the proceeds will be utilized to fund existing debt maturities as well as fund projected capital expenditures. We do not hedge all interest rate exposure. During 2004, we reclassified an immaterial amount to earnings because the original forecasted transaction did not occur within the originally specified time period.

We enter into, and designate as cash flow hedges, certain forward and swap transactions for the purchase and sale of electricity and natural gas to manage the variable price risk related to the forecasted purchase and sale of electricity. We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future sales and generation revenues. We do not hedge all variable price risk exposure related to the forecasted purchase and sale of electricity. During 2004, we classified an immaterial amount into earnings as a result of hedge ineffectiveness related to our cash flow hedging strategies.

We enter into natural gas futures contracts to protect against the reduction in value of forecasted cash flows resulting from spot purchases and sales of natural gas at Houston Ship Channel (HSC). We closely monitor the potential impacts of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future spot purchases and sales. We do not hedge all variable price risk exposure related to the forecasted spot purchase and sale of natural gas. The amount of hedges’ ineffectiveness was immaterial during 2004.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets at December 31, 2004 are:

	Hedging Assets		Hedging Liabilities			Accumulated Other Comprehensive Income (Loss) After Tax			Portion Expected to be Reclassified to Earnings during the Next 12 Months
	(in millions)
Power and Gas	$	88	$	(60	)	$	23		$	(26	)
Interest Rate		1		(23	)		(23	)(a)		4
Foreign Currency		-		-			-			-
	$	89	$	(83	)	$	-		$	(22	)

(a) Includes $3 million loss recorded in an equity investment.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets at December 31, 2003 are:

	Hedging Assets		Hedging Liabilities			Accumulated Other Comprehensive Income (Loss) After Tax
	(in millions)
Power and Gas	$	21	$	(121	)	$	(65	)
Interest Rate		-		(7	)		(9	)(a)
Foreign Currency		-		(30	)		(20	)
	$	21	$	(158	)	$	(94	)

(a) Includes $6 million loss recorded in an equity investment.

The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ due to market price changes. As of December 31, 2004 and 2003, fourteen months and five years, respectively, are the maximum lengths of time that we are hedging, with SFAS 133 designated contracts, our exposure to variability in future cash flows for forecasted transactions.

The following table represents the activity in Accumulated Comprehensive Other Income (Loss) for derivative contracts that qualify as cash flow hedges at December 31, 2004:

	Amount
	(in millions)
Beginning Balance, December 31, 2001	$	(3	)
Changes in fair value		(56	)
Reclasses from AOCI to net earnings		43
Balance at December 31, 2002		(16	)
Changes in fair value		(79	)
Reclasses from AOCI to net earnings		1
Balance at December 31, 2003		(94	)
Changes in fair value		8
Reclasses from AOCI to net earnings		86
Ending Balance, December 31, 2004	$	-

Hedge of Net Investment in Foreign Operations

In 2002, we used foreign denominated fixed-rate debt to protect the value of our investments in foreign subsidiaries in the U.K. Realized gains and losses from these hedges are not included in the income statement, but are shown in the cumulative translation adjustment account included in Accumulated Other Comprehensive Income (Loss).

During 2002, we recognized $64 million of net losses, included in the cumulative translation adjustment, related to the foreign denominated fixed-rate debt.

FINANCIAL INSTRUMENTS

The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

The book values and fair values of significant financial instruments at December 31, 2004 and 2003 are summarized in the following tables.

	2004				2003
	Book Value		Fair Value		Book Value		Fair Value
	(in millions)
Long-term Debt	$	12,287	$	12,813	$	14,101	$	14,621
Cumulative Preferred Stocks of Subsidiaries  Subject to   Mandatory Redemption		66		67		76		76

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value

The trust investments which are classified as available for sale for decommissioning and SNF disposal, reported in “Spent Nuclear Fuel and Decommissioning Trusts” and “Assets of Discontinued Operations and Held for Sale” on our Consolidated Balance Sheets, are recorded at market value in accordance with SFAS 115, “Accounting for Certain Investments in Debt and Equity Securities.” At December 31, 2004 and 2003, the fair values of the trust investments were $1.2 billion and $1.1 billion, respectively, and had a cost basis of $1.0 billion and $1.0 billion, respectively. The change in market value in 2004, 2003 and 2002 was a net unrealized gain of $41 million and $53 million and a net unrealized loss of $33 million, respectively.

15.INCOME TAXES

The details of our consolidated income taxes before discontinued operations, extraordinary item and cumulative effect of accounting changes as reported are as follows:

	Year Ended December 31,
	2004			2003		2002
	(in millions)
Federal:
Current	$	262		$	297	$	307
Deferred		263			34		(60	)
Total		525			331		247
State and Local:
Current		49			19		32
Deferred		(3	)		1		28
Total		46			20		60
International:
Current		1			7		8
Deferred		-			-		-
Total		1			7		8
Total Income Tax as Reported Before Discontinued Operations,   Extraordinary Item and Cumulative Effect of Accounting Changes	$	572		$	358	$	315

The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported.

	Year Ended December 31,
	2004			2003			2002
	(in millions)
Net Income (Loss)	$	1,089		$	110		$	(519	)
Discontinued Operations (net of income tax of $75 million, $(312) million and   $(174) million in 2004, 2003 and 2002, respectively)		(83	)		605			654
Extraordinary Loss on Texas Stranded Cost Recovery,   (net of income tax of $(64) million in 2004)		121			-			-
Cumulative Effect of Accounting Changes   (net of income tax of $138 million and $0 in 2003 and 2002, respectively)		-			(193	)		350
Preferred Stock Dividends		6			9			11
Income Before Preferred Stock Dividends of Subsidiaries		1,133			531			496
Income Taxes Before Discontinued Operations, Extraordinary Item and   Cumulative Effect of Accounting Changes		572			358			315
Pretax Income	$	1,705		$	889		$	811
Income Taxes on Pretax Income at Statutory Rate (35%)	$	597		$	311		$	284
Increase (Decrease) in Income Taxes resulting from the following Items:
Depreciation		36			34			32
Asset Impairments and Investment Value Losses		-			23			4
Investment Tax Credits (net)		(29	)		(33	)		(35	)
Tax Effects of International Operations		1			8			27
Energy Production Credits		(16	)		(15	)		(14	)
State Income Taxes		30			13			39
Other		(47	)		17			(22	)
Total Income Taxes as Reported Before Discontinued Operations,   Extraordinary Item and Cumulative Effect of Accounting Changes	$	572		$	358		$	315
Effective Income Tax Rate		33.5	%		40.3	%		38.8	%

The following table shows our elements of the net deferred tax liability and the significant temporary differences.

	As of December 31,
	2004			2003
	(in millions)
Deferred Tax Assets	$	2,280		$	3,354
Deferred Tax Liabilities		(7,099	)		(7,311	)
Net Deferred Tax Liabilities		(4,819	)		(3,957	)
Property Related Temporary Differences	$	(3,273	)	$	(2,850	)
Amounts Due From Customers For Future Federal Income Taxes		(184	)		(180	)
Deferred State Income Taxes		(452	)		(416	)
Transition Regulatory Assets		(211	)		(254	)
Securitized Transition Assets		(258	)		(281	)
Regulatory Assets		(578	)		(195	)
Deferred Income Taxes on Other Comprehensive Loss		186			306
All Other (net)		(49	)		(87	)
Net Deferred Tax Liabilities	$	(4,819	)	$	(3,957	)

The IRS and other taxing authorities routinely examine our tax returns. Management believes that we have filed tax returns with positions that may be challenged by these tax authorities. These positions relate to, among others, the federal treatment of taxes paid to foreign taxing authorities (the most significant of which is the federal treatment of the U.K. Windfall Profits Tax), the timing and amount of deductions and the tax treatment related to acquisitions and divestitures. We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent’s Reports from the IRS for the years 1991 through 1999, and have filed protests contesting certain proposed adjustments. CSW, which was a separate consolidated group prior to its merger with AEP, is currently being audited for the years 1997 through the date of merger in June 2000. Returns for the years 2000 through 2003 are presently being audited by the IRS.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. As of December 31, 2004, the Company has total provisions for uncertain tax positions of approximately $144 million.  In addition, the Company accrues interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

16.LEASES

Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:

	Year Ended December 31,
	2004		2003		2002
	(in millions)
Lease Payments on Operating Leases	$	317	$	344	$	359
Amortization of Capital Leases		54		64		65
Interest on Capital Leases		11		9		14
Total Lease Rental Costs	$	382	$	417	$	438

Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:

	December 31,
	2004		2003
	(in millions)
Property, Plant and Equipment Under Capital Leases:
Production	$	91	$	37
Distribution		15		15
Other		323		470
Total Property, Plant and Equipment		429		522
Accumulated Amortization		186		218
Net Property, Plant and Equipment Under Capital Leases	$	243	$	304
Obligations Under Capital Leases:
Noncurrent Liability	$	190	$	131
Liability Due Within One Year		53		51
Total Obligations under Capital Leases	$	243	$	182

Future minimum lease payments consisted of the following at December 31, 2004:

	Capital Leases		Noncancelable Operating Leases
	(in millions)
2005	$	64	$	291
2006		55		259
2007		42		246
2008		30		231
2009		21		221
Later Years		92		2,181
Total Future Minimum Lease Payments	$	304	$	3,429
Less Estimated Interest Element		61
Estimated Present Value of Future Minimum Lease Payments	$	243

Gavin Scrubber Financing Arrangement

In 1994, OPCo entered into an agreement with JMG, an unrelated special purpose entity. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and previously leased it to OPCo. Prior to July 1, 2003, the lease was accounted for as an operating lease.

On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon consolidation, OPCo recorded the assets and liabilities of JMG ($470 million). Since the debt obligations of JMG are now consolidated, the JMG lease is no longer accounted for as an operating lease. For 2002 and the first half of 2003, operating lease payments related to the Gavin Scrubber were recorded as operating lease expense by OPCo. After July 1, 2003, OPCo records the depreciation, interest and other operating expenses of JMG and eliminates JMG’s rental revenues against OPCo’s operating lease expenses. There was no cumulative effect of an accounting change recorded as a result of the requirement to consolidate JMG and there was no change in net income due to the consolidation of JMG. The debt obligations of JMG are now included in long-term debt as Notes Payable and Installment Purchase Contracts and are excluded from the above table of future minimum lease payments.

At any time during the obligation, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber on behalf of JMG. The initial 15-year term is noncancelable. At the end of the initial term, OPCo can renew the obligation, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber on behalf of JMG. In the case of a sale at less than the adjusted acquisition cost, OPCo is required pay the difference to JMG.

Rockport Lease

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The future minimum lease payments for each respective company as of December 31, 2004 are $1.3 billion.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt.

Railcar Lease

In June 2003, we entered into an agreement with an unrelated, unconsolidated leasing company to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years and may be renewed for up to three additional five-year terms, for a maximum of twenty years. We intend to renew the lease for the full twenty 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 with the future payments included in the future minimum lease payments schedule earlier in this note. This operating lease agreement allows us to avoid a large initial capital expenditure, and to spread our railcar costs evenly over the expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least a lessee obligation amount specified in the lease, which declines over the term from approximately 86% to 77% of the projected fair market value of the equipment. At December 31, 2004, the maximum potential loss was approximately $32 million ($21 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. The railcars are subleased for one year to a nonaffiliated company under an operating lease. The sublessee may renew the lease for up to three additional one-year terms. AEP has other rail car lease arrangements that do not utilize this type of structure.

17.FINANCING ACTIVITIES

Dividend Restrictions

Under PUHCA, AEP and its public utility subsidiaries can only pay dividends out of retained or current earnings.

Trust Preferred Securities

SWEPCo has a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46. The trust, which holds mandatorily redeemable trust preferred securities, is reported as two components on the Balance Sheet. The investment in the trust is reported as Other within Other Noncurrent Assets while the Junior Subordinated Debentures are reported as Notes Payable to Trust within Long-term Debt.

In October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are due October 1, 2043. Junior Subordinated Debentures were retired in the second quarter of 2004 for PSO and in the third quarter of 2004 for TCC. The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2004 and 2003:

Business Trust	Security		Units Issued/ Outstanding at 12/31/04	Amount in Other at 12/31/04 (a)		Amount in Notes Payable to Trust at 12/31/04 (b)		Amount in Other at 12/31/03 (a)		Amount in Notes Payable to Trust at 12/31/03 (b)		Description of Underlying Debentures of Registrant
		(in millions)
CPL Capital I	8.00%, Series A		-	$	-	$	-	$	5	$	141	TCC, $141 million,   8.00%, Series A
PSO Capital I	8.00%, Series A		-		-		-		2		77	PSO, $77 million,   8.00%, Series A
SWEPCo Capital I	5.25%, Series B		110,000		3		113		3		113	SWEPCo, $113   million, 5.25%    5-year fixed rate   period, Series B
Total			110,000	$	3	$	113	$	10	$	331

(a)	Amounts are in Other within Other Noncurrent Assets.
(b)	Amounts are in Notes Payable to Trust within Long-term Debt.

Each of the business trusts is treated as a nonconsolidated subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under the subordinated debentures, the parent company has also agreed to a security obligation, which represents a full and unconditional guarantee of its capital trust obligation.

Minority Interest in Finance Subsidiary

We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated subsidiary that held the assets of HPL and LIG. Caddis was capitalized with $2 million cash from SubOne for a managing member interest and $750 million from Steelhead Investors LLC (Steelhead) for a noncontrolling preferred member interest. As managing member, SubOne consolidated Caddis. Steelhead was an unconsolidated special purpose entity whose investors had no relationship to us or any of our subsidiaries. The money invested in Caddis by Steelhead was loaned to SubOne.

On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis. As a result, a note payable ($533 million) to Caddis was reported as a component of Long-term Debt on July 1, 2003, the balance of which was $0 and $525 million on December 31, 2004 and December 31, 2003, respectively. Due to the prospective application of FIN 46, we did not change the presentation of Minority Interest in Finance Subsidiary in periods prior to July 1, 2003.

Equity Units

In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consists of a forward purchase contract and a senior note.

The forward purchase contracts obligate the holders to purchase shares of AEP common stock on August 16, 2005. The purchase price per equity unit is $50. The number of shares to be purchased under the forward purchase contract will be determined under a formula based upon the average closing price of AEP common stock near the stock purchase date. Holders may satisfy their obligation to purchase AEP common stock under the forward purchase contracts by allowing the senior notes to be remarketed or by continuing to hold the senior notes and using other resources as consideration for the purchase of stock. If holders remarket their notes, the proceeds from the remarketing will be used to purchase a portfolio of U.S. treasury securities that the holders will pledge to AEP in order to meet their obligations under the forward purchase contracts.

The senior notes have a principal amount of $50 each and mature on August 16, 2007. The senior notes are the collateral that secures the holders’ requirement to purchase common stock under the forward purchase contracts.

AEP is making quarterly interest payments on the senior notes at an initial annual rate of 5.75%. The interest rate can be reset through a remarketing, which is initially scheduled for May 2005. AEP makes contract adjustment payments to the purchaser at the annual rate of 3.50% on the forward purchase contracts. The present value of the contract adjustment payments was recorded as a $31 million liability in Equity Unit Senior Notes offset by a charge to Paid-in Capital in June 2002. Interest payments on the senior notes are reported as interest expense. Accretion of the contract adjustment payment liability is reported as interest expense.

AEP applies the treasury stock method to the equity units to calculate diluted earnings per share. This method of calculation theoretically assumes that the proceeds received as a result of the forward purchase contract are used to repurchase outstanding shares.

Lines of Credit - AEP System

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 December 31, 2004, we had credit facilities totaling $2.8 billion to support our commercial paper program. At December 31, 2004, we had $23 million in outstanding commercial paper related to JMG Funding. This commercial paper is specifically associated with the Gavin Scrubber as identified in the “Gavin Scrubber Financing Arrangement” section of Note 16 and is backed by a separate credit facility. This commercial paper does not reduce our available liquidity. As of December 31, 2004, our commercial paper outstanding related to the corporate borrowing program was $0. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $661 million in June 2004 and the weighted average interest rate of commercial paper outstanding during the year was 1.81%. On February 10, 2003, Moody’s Investor Services downgraded our short-term rating for commercial paper to Prime-3 from Prime-2. On March 7, 2003, Standard & Poor’s Rating Services reaffirmed our A-2 short-term rating for commercial paper. On August 2, 2004, Moody’s Investor Services placed our ratings on positive outlook.

Outstanding Short-term Debt consisted of:

	December 31,
	2004		2003
	(in millions)
Balance Outstanding
Notes Payable	$	-	$	18
Commercial Paper - AEP		-		282
Commercial Paper - JMG		23		26
Total	$	23	$	326

Sale of Receivables - AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of AEP Credit’s balance sheet and allowing AEP Credit to repay any debt obligations. We have no ownership interest in the commercial paper conduits and are not required to consolidate these entities in accordance with GAAP. We continue to service the receivables. We entered into this off-balance sheet transaction to allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables, and accelerate its cash collections.

During 2004, AEP Credit renewed its sale of receivables agreement which had expired on August 25, 2004. As a result of the renewal, AEP Credit’s sale of receivables agreement will now expire on August 24, 2007. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2004, $435 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit.

Comparative accounts receivable information for AEP Credit is as follows:

	Year Ended December 31,
	2004			2003
	(in millions)
Proceeds from Sale of Accounts Receivable	$	5,163		$	5,221
Accounts Receivable Retained Interest and Pledged as Collateral Less   Uncollectible Accounts		80			124
Deferred Revenue from Servicing Accounts Receivable		1			1
Loss on Sale of Accounts Receivable		7			7
Average Variable Discount Rate		1.50	%		1.33	%
Retained Interest if 10% Adverse Change in   Uncollectible Accounts		78			122
Retained Interest if 20% Adverse Change in   Uncollectible Accounts		76			121

Historical loss and delinquency amount for the AEP System’s customer accounts receivable managed portfolio is as follows:

	Face Value Year Ended December 31,
	2004			2003
	(in millions)
Customer Accounts Receivable Retained	$	930		$	1,155
Accrued Unbilled Revenues Retained		592			596
Miscellaneous Accounts Receivable Retained		79			83
Allowance for Uncollectible Accounts Retained		(77	)		(124	)
Total Net Balance Sheet Accounts Receivable		1,524			1,710
Customer Accounts Receivable Securitized (Affiliate)		435			385
Total Accounts Receivable Managed	$	1,959		$	2,095
Net Uncollectible Accounts Written Off	$	86		$	39

Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized.

Delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors were $25 million and $30 million at December 31, 2004 and 2003, respectively.

18.UNAUDITED QUARTERLY FINANCIAL INFORMATION

Our unaudited quarterly financial information is as follows:

	2004 Quarterly Periods Ended
(In Millions - Except Per Share Amounts)	March 31		June 30		September 30		December 31
Revenues	$	3,364	$	3,408	$	3,780	$	3,505
Operating Income		633		413		639		306
Income Before Discontinued Operations and Extraordinary Item		289		151		412		275
Net Income		282		100		530		177
Earnings per Share Before Discontinued Operations and    Extraordinary Item (a)		0.73		0.38		1.04		0.69
Earnings per Share		0.71		0.25		1.34		0.45

	2003 Quarterly Periods Ended
(In Millions - Except Per Share Amounts)	March 31		June 30		September 30		December 31
Revenues	$	3,806	$	3,491	$	3,966	$	3,404
Operating Income (Loss)		651		434		760		(91	)
Income (Loss) Before Discontinued Operations and   Cumulative Effect of  Accounting Changes		293		177		307		(255	)
Net Income (Loss)		440		175		257		(762	)
Earnings (Loss) per Share Before Discontinued Operations and   Cumulative Effect of Accounting Changes (b)		0.82		0.45		0.78		(0.65	)
Earnings (Loss) per Share (c)		1.24		0.44		0.65		(1.93	)

(a)	Amounts for 2004 do not add to $2.85 earnings per share before Discontinued Operations and Extraordinary Item due to rounding.
(b)	Amounts for 2003 do not add to $1.35 earnings per share before Discontinued Operations, Extraordinary Item and Cumulative Effect of Accounting Changes due to rounding and the dilutive effect of shares issued in 2003.
(c)	Amounts for 2003 do not add to $0.29 earnings per share due to rounding and the dilutive effect of shares issued in 2003.

Income (Loss) Before Discontinued Operations and Cumulative Effect of Accounting Changes for the fourth quarter of 2003 ($255 million loss) was significantly lower than the previous three quarters due to asset impairments, investment value losses and other related charges. These pretax writedowns ($650 million in the fourth quarter of 2003) were made to reflect impairments and discontinued operations as discussed in Note 10.

19. SUBSEQUENT EVENT

On January 27, 2005, we sold a 98% controlling interest in HPL, 30 BCF of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. We are retaining a 2% ownership interest in HPL and will provide certain transitional administrative services to the buyer. The determination of the amount of the gain on sale and the recognition of the gain is dependent on the ultimate resolution of the Bank of America (BOA) dispute. We provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA (see “Enron Bankruptcy - Right to use of cushion gas agreements” section of Note 7).

We also have a put option expiring in 2006, which allows us to sell our remaining 2% interest to the buyer for approximately $16 million.

HPL is classified as held and used instead of held for sale as of December 31, 2004 due to the magnitude and uncertainty surrounding the BOA dispute and what level of indemnification a potential buyer might require. In addition, the indicative bid and our Board of Director’s approval to sell HPL were received subsequent to December 31, 2004.

AEP GENERATING COMPANY

AEP GENERATING COMPANY

SELECTED FINANCIAL DATA

(in thousands)

	2004			2003		2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	241,788		$	233,165	$	213,281	$	227,548	$	228,516
Operating Income		6,904			7,174		6,129		6,977		8,424
Interest Charges		2,446			2,550		2,258		2,586		3,869
Net Income		7,842			7,964		7,552		7,875		7,984
BALANCE SHEETS DATA
Electric Utility Plant	$	689,577		$	674,055	$	652,213	$	648,254	$	642,302
Accumulated Depreciation and Amortization		368,484			351,062		330,187		310,804		290,858
Net Electric Utility Plant	$	321,093		$	322,993	$	322,026	$	337,450	$	351,444
TOTAL ASSETS	$	376,393		$	380,045	$	377,716	$	387,688	$	399,310
Common Shareholder's Equity		48,671			45,875		42,597		38,195		34,156
Long-term Debt(a)		44,820			44,811		44,802		44,793		44,808
Obligations Under Capital Leases (a)		12,474	(b)		269		501		311		591

(a)	Including portion due within one year.
(b)	Increased primarily due to a new coal transportation lease. See Note 15.

AEP GENERATING COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

AEGCo, co-owner of the Rockport Plant, is engaged in the generation and wholesale sale of electric power to two affiliates, I&M and KPCo, under long-term agreements. I&M is the operator and the other co-owner of the Rockport Plant.

Operating revenues are derived from the sale of Rockport Plant energy and capacity to I&M and KPCo pursuant to FERC approved long-term unit power agreements. Under the terms of its unit power agreement, I&M agreed to purchase all of our Rockport energy and capacity unless it is sold to other utilities or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo. In December 2004, KPSC and the FERC approved a Stipulation and Settlement Agreement which, among other things, extends the unit power agreement with KPCo until December 7, 2022.

The unit power agreements provide for a FERC approved rate of return on common equity, a return on other capital (net of temporary cash investments) and recovery of costs including operation and maintenance, fuel and taxes. Under the terms of the unit power agreements, AEGCo accumulates all expenses monthly and prepares bills for its affiliates. In the month the expenses are incurred, AEGCo recognizes the billing revenues and establishes a receivable from the affiliated companies. Costs of operating the plant are divided between the co-owners.

Results of Operations

Net Income decreased $0.1 million for 2004 compared with 2003. The fluctuation in Net Income is a result of terms in the unit power agreements which allow for a return on total capital of the Rockport Plant calculated and adjusted monthly.

2004 Compared to 2003

Operating Income

Operating Income decreased $0.3 million from the prior year. The largest variances related to:

· A $3.2 million increase in Fuel for Electric Generation expense primarily due to an 8.7% increase in average fuel costs per KWH generated.

· A $1.9 million increase in Income Taxes. See Income Taxes section below for further discussion.

· A $1.8 million increase in Maintenance expenses as a result of increased planned boiler inspections and forced repairs.

· A $0.8 million increase in Taxes Other Than Income Taxes as a result of Indiana property tax reappraisals.

· A $0.7 million increase in Depreciation and Amortization reflecting an increase in assets being depreciated.

· A $0.5 million increase in Other Operation expenses reflecting increased employee pension and benefit costs.

The above expense increases were recovered per the terms of the unit power agreement by:

· An $8.6 million increase in Operating Revenues as a result of increased recoverable expenses.

Income Taxes

The effective tax rates for 2004 and 2003 were (1.5)% and (31.5)%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is primarily due to amortization of investment tax credits, flow-through of book versus tax temporary differences, and state income taxes. The increase in the effective tax rate is primarily due to higher state income taxes and changes in flow-through temporary differences.

Off-Balance Sheet Arrangements

Rockport Plant Unit 2

In 1989, AEGCo and I&M entered into a sale and leaseback transaction with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each company are $1.3 billion.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote (see Note 15). The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.

Our contractual obligations include amounts reported on the Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payments due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Advances from Affiliates (a)	$	26.9	$	-	$	-	$	-	$	26.9
Capital Lease Obligations (b)		1.0		2.0		1.9		18.0		22.9
Noncancelable Operating Leases (b)		74.0		147.9		147.9		960.2		1,330.0
Total	$	101.9	$	149.9	$	149.8	$	978.2	$	1,379.8

(a)	Represents short-term borrowings from the Utility Money Pool.
(b)	See Note 15.  The lease of the Plant is reported in Noncancelable Operating Leases.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, income taxes, and the impact of new accounting pronouncements.

AEP GENERATING COMPANY

STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004		2003		2002
OPERATING REVENUES	$	241,788	$	233,165	$	213,281
OPERATING EXPENSES
Fuel for Electric Generation		112,470		109,238		89,105
Rent - Rockport Plant Unit 2		68,283		68,283		68,283
Other Operation		10,866		10,399		12,924
Maintenance		12,152		10,346		9,418
Depreciation and Amortization		23,390		22,686		22,560
Taxes Other Than Income Taxes		4,181		3,396		3,281
Income Taxes		3,542		1,643		1,581
TOTAL		234,884		225,991		207,152
OPERATING INCOME		6,904		7,174		6,129
Nonoperating Income		43		151		344
Nonoperating Expenses		317		361		199
Nonoperating Income Tax Credits		3,658		3,550		3,536
Interest Charges		2,446		2,550		2,258
NET INCOME	$	7,842	$	7,964	$	7,552

STATEMENTS OF RETAINED EARNINGS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004		2003		2002
BALANCE AT BEGINNING OF PERIOD	$	21,441	$	18,163	$	13,761
Net Income		7,842		7,964		7,552
Cash Dividends Declared		5,046		4,686		3,150
BALANCE AT END OF PERIOD	$	24,237	$	21,441	$	18,163

The common stock of AEGCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004		2003
ELECTRIC UTILITY PLANT
Production	$	681,254	$	645,251
General		3,739		4,063
Construction Work in Progress		7,729		24,741
Total		692,722		674,055
Accumulated Depreciation and Amortization		368,484		351,062
TOTAL - NET		324,238		322,993
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		119		119
CURRENT ASSETS
Accounts Receivable - Affiliated Companies		23,078		24,748
Fuel		16,404		20,139
Materials and Supplies		5,962		5,419
TOTAL		45,444		50,306
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Unamortized Loss on Reacquired Debt		4,496		4,733
Asset Retirement Obligations		1,117		928
Deferred Property Taxes		557		502
Other Deferred Charges		422		464
TOTAL		6,592		6,627
TOTAL ASSETS	$	376,393	$	380,045

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004		2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $1,000 Par Value Per Share:
Authorized and Outstanding - 1,000 Shares	$	1,000	$	1,000
Paid-in Capital		23,434		23,434
Retained Earnings		24,237		21,441
Total Common Shareholder’s Equity		48,671		45,875
Long-term Debt		44,820		44,811
TOTAL		93,491		90,686
CURRENT LIABILITIES
Advances from Affiliates		26,915		36,892
Accounts Payable:
General		443		498
Affiliated Companies		17,905		15,911
Taxes Accrued		8,806		6,070
Interest Accrued		911		911
Obligations Under Capital Leases		210		87
Rent Accrued - Rockport Plant Unit 2		4,963		4,963
Other		73		-
TOTAL		60,226		65,332
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		24,762		24,329
Regulatory Liabilities:
Asset Removal Costs		25,428		27,822
Deferred Investment Tax Credits		46,250		49,589
SFAS 109 Regulatory Liability, Net		12,852		15,505
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		99,904		105,475
Obligations Under Capital Leases		12,264		182
Asset Retirement Obligations		1,216		1,125
TOTAL		222,676		224,027
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	376,393	$	380,045

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	7,842		$	7,964		$	7,552
Adjustments to Reconcile Net Income to Net Cash Flows From Operating Activities:
Depreciation and Amortization		23,390			22,686			22,560
Deferred Income Taxes		(2,219	)		(5,838	)		(5,028	)
Deferred Investment Tax Credits		(3,339	)		(3,354	)		(3,361	)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		(5,571	)		(5,571	)		(5,571	)
Changes in Other Noncurrent Assets		3,455			3,486			(5,455	)
Changes in Other Noncurrent Liabilities		(2,511	)		1,120			102
Changes in Components of Working Capital:
Accounts Receivable		1,670			(6,294	)		4,037
Fuel, Materials and Supplies		3,192			(385	)		(5,450	)
Accounts Payable		1,939			476			6,697
Taxes Accrued		2,736			3,743			(2,450	)
Other Current Assets		-			-			244
Other Current Liabilities		196			(113	)		(2,397	)
Net Cash Flows From Operating Activities		30,780			17,920			11,480
INVESTING ACTIVITIES
Construction Expenditures		(15,757	)		(22,197	)		(5,298	)
Change in Other Cash Deposits, Net		-			-			983
Proceeds from Sale of Assets		-			105			-
Net Cash Flows Used For Investing Activities		(15,757	)		(22,092	)		(4,315	)
FINANCING ACTIVITIES
Change in Advances to/from Affiliates, Net		(9,977	)		8,858			(4,015	)
Dividends Paid		(5,046	)		(4,686	)		(3,150	)
Net Cash Flows From (Used For) Financing Activities		(15,023	)		4,172			(7,165	)
Net Change in Cash and Cash Equivalents		-			-			-
Cash and Cash Equivalents at Beginning of Period		-			-			-
Cash and Cash Equivalents at End of Period	$	-		$	-		$	-

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $2,179,000, $2,283,000 and $2,019,000 and for income taxes was $542,000, $6,483,000 and $7,884,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $12,297,000.

   See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

SCHEDULE OF LONG-TERM DEBT

December 31, 2004 and 2003

(in thousands)

			2004			2003
LONG-TERM DEBT - Installment Purchase Contracts - City of Rockport (a)
	Series	Due Date
	1995 A	2025 (b)	$	22,500		$	22,500
	1995 B	2025 (b)		22,500			22,500
Unamortized Discount				(180	)		(189	)
TOTAL LONG-TERM DEBT			$	44,820		$	44,811

(a)

We entered into installment purchase contracts in connection with the issuance of pollution control revenue bonds by the City of Rockport, Indiana.  The terms of the installment purchase contracts require our payment of amounts sufficient to enable the payment of interest and principal on the related pollution control revenue bonds issued to refinance the construction costs of pollution control facilities at the Rockport Plant.  The bonds due in 2025 are subject to mandatory tender for purchase in July 2006. Consequently, the bonds have been classified for repayment purposes in 2006.

(b)

These series have an adjustable interest rate that we can designate as a daily, weekly, commercial paper or term rate.  In July 2001, we selected a term rate of 4.05% for five years ending July 12, 2006.

None of our long-term debt obligations have been guaranteed or secured by AEP or any of our affiliates.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP GENERATING COMPANY

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to AEGCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to AEGCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Effects of Regulation	Note 5
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

AEP Generating Company:

We have audited the accompanying balance sheets of AEP Generating Company as of December 31, 2004 and 2003, and the related statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Generating Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004			2003		2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	1,175,266		$	1,747,511	$	1,690,493	$	1,738,837	$	1,770,402
Operating Income		196,019			321,540		393,733		295,731		307,098
Carrying Costs on Stranded Cost Recovery (a)		301,644			-		-		-		-
Interest Charges		123,785			133,812		125,871		116,268		124,766
Income Before Extraordinary Loss and   Cumulative Effect of Accounting Change		294,656			217,547		275,941		182,278		189,567
Extraordinary Loss on Stranded   Cost Recovery, Net of Tax (a)		(120,534	)		-		-		-		-
Cumulative Effect of Accounting Change,   Net of Tax		-			122		-		-		-
Net Income		174,122			217,669		275,941		182,278		189,567
BALANCE SHEETS DATA
Electric Utility Plant	$	2,492,798		$	2,425,038	$	2,334,794	$	2,231,287	$	2,097,497
Accumulated Depreciation and Amortization		725,225			695,359		662,345		616,526		570,522
Net Electric Utility Plant	$	1,767,573		$	1,729,679	$	1,672,449	$	1,614,761	$	1,526,975
Total Assets	$	5,695,790		$	5,854,429	$	5,515,723	$	4,989,381	$	5,556,275
Common Shareholder's Equity		1,268,643			1,209,049		1,101,134		1,400,100		1,366,123
Cumulative Preferred Stock Not Subject   to Mandatory Redemption		5,940			5,940		5,942		5,952		5,951
Trust Preferred Securities (b)		-			-		136,250		136,250		148,500
Long-term Debt (c)		1,907,294			2,291,625		1,438,565		1,253,768		1,454,559
Obligations Under Capital Leases (c)		880			1,043		-		-		-

(a)	See “Carrying Costs on Net True-up Regulatory Assets” and “Net Stranded Generation Costs” sections of Note 6.
(b)	See “Trust Preferred Securities” section of Note 16.
(c)	Including portion due within one year.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

TCC is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power. We consolidate AEP Texas Central Transition Funding LLC, our wholly-owned subsidiary. As a power pool member with AEP West companies, we share in the revenues and expenses of the power pool’s sales to neighboring utilities and power marketers. We also sell electric power at wholesale to other utilities, a municipality, rural electric cooperatives and REPs in Texas.

Power pool members are compensated for energy delivered to other members based upon the delivering members’ incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

2004 Compared to 2003

Net Income decreased $44 million for 2004. The major factors driving the decline are decreased revenues associated with establishing regulatory assets in Texas in 2003 and the extraordinary item related to stranded cost in 2004, offset in part in 2004 by the cessation of depreciation on plants held for sale and the capitalization of carrying costs on recoverable stranded costs. The sale of several of our generation plants in July 2004 affected numerous line items on the income statement and reduced the amount of margins recognized from the generation operations.

Operating Income

Operating Income decreased $126 million primarily due to:

· A $215 million decrease in revenues associated with establishing regulatory assets in Texas in 2003 (see “Texas Restructuring” and “Wholesale Capacity Auction True-up” section of Note 6).

· A $214 million decrease in off-system sales, including those to REPs, primarily due to lower KWH sales of 36%. The decrease in KWH sales is due to customer choice in Texas and the sale of certain generation plants.

· A $127 million decrease in Reliability Must Run (RMR) revenues from ERCOT, which includes both a fuel recovery decrease of $108 million and a fixed cost component decrease of $19 million due to TCC no longer having RMR plants. In 2004, RMR revenues totaled $115 million of which $16 million was for reimbursement of fixed costs.

· A $24 million decrease in revenues from ERCOT for various services including balancing energy and prior year adjustments made by ERCOT.

· A $13 million decrease in margins from risk management activities.

· A $12 million increase in Other Operation expenses primarily due to a $10 million increase of ERCOT-related transmission expense and affiliated ancillary services resulting from revised data received from ERCOT for the years 2001-2003; a $4 million increase in distribution related expense; and a $6 million increase in general and administrative expenses; offset by a $9 million decrease in production expenses due to the sale of certain generation plants.

· A $10 million decrease in Qualified Scheduling Entity (QSE) fees primarily due to one REP not using TCC as their QSE in 2004.

The decrease in Operating Income was partially offset by:

· A $303 million net decrease in fuel and purchased power expenses. KWHs purchased decreased 51% while the per unit cost increased 20%. Per unit generation costs decreased 29% and KWHs generated decreased 21% due to the sale of certain generation plants and the fact that lower cost nuclear fuel generation became a larger part of the generation mix after the sale.

· A $75 million decrease in Depreciation and Amortization expenses primarily due to the cessation of depreciation on plants sold and plants classified as held for sale (see “Dispositions” and “Assets Held for Sale” sections of Note 10).

· A $71 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $21 million increase in revenues due to a decrease in provisions for rate refunds primarily due to fuel reconciliation issues (see “TCC Fuel Reconciliation” section of Note 4).

· A $15 million increase in transmission revenue primarily due to affiliated open access transmission tariff (including an $8 million true-up for prior years recorded in 2004 resulting from revised data received from ERCOT for the years 2001-2003) and ancillary services.

· An $8 million decrease in Maintenance expenses primarily due to the sale of certain generation plants.

Other Impacts on Earnings

We recorded in income a carrying cost of $302 million on stranded cost recovery (see “Carrying Costs on Net True-up Regulatory Assets” section of Note 6).

Nonoperating income decreased $8 million primarily due to a decrease in risk management activities.

Interest Charges decreased $10 million primarily due to the defeasance of $112 million of First Mortgage Bonds, and the resultant deferral of the interest cost as a regulatory asset related to the cost of the sale of generation assets, the redemption of the 8% Notes Payable to Trust, and other financing activities.

Income Taxes

The effective tax rates for 2004 and 2003 were 31.4% and 32.6%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35.0% is due to permanent differences, amortization of investment tax credits, consolidated tax savings, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Extraordinary Loss on Stranded Cost Recovery, Net of Tax

See “Texas Restructuring” and “Net Stranded Generation Costs” sections of Note 6 for a discussion of net adjustments of stranded costs recorded in the fourth quarter of 2004.

2003 Compared to 2002

Net Income decreased $58 million for 2003. The decrease is primarily due to an increased provision for refunds of $85 million ($55 million after tax) and a decrease in the recognition of noncash earnings related to legislatively-mandated capacity auctions and regulatory assets established in Texas of $29 million net of tax. Additionally, income from transactions with ERCOT increased significantly due mainly to Texas Restructuring Legislation.

Since REPs are the electricity suppliers to retail customers in the ERCOT area, we sell our generation to the REPs and other market participants and provide transmission and distribution services to retail customers of the REPs in our service territory. As a result of the provision of retail electric service by REPs, effective January 1, 2002, we no longer supply electricity directly to retail customers. The implementation of REPs as suppliers to retail customers has caused a shift in our sales as further described below.

In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who assumed the obligations of the affiliated REP including the provision of price-to-beat rates under the Texas Restructuring Legislation. Prior to the sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP Affiliates. Subsequent to the sale, energy transactions and delivery charges with Mutual Energy CPL are classified as Electric Generation, Transmission and Distribution.

Operating Income

Operating Income decreased $72 million primarily due to:

· A $197 million net increase in fuel and purchased power expenses to replace portions of the energy from the non-RMR mothballed plants and the unscheduled forced outage at the STP nuclear unit. KWHs purchased increased 47% while the cost increased 54%. Although the KWHs generated decreased, fuel costs increased 16% due to higher per unit costs attributable mostly to natural gas.

· An $85 million increase in provisions for rate refunds primarily due to 2003 Texas fuel issues (see “TCC Fuel Reconciliation” section of Note 4).

· A $59 million decrease in revenue due to the 2002 interchange cost reconstruction adjustments with an offsetting $51 million decrease in purchased power.

· A $44 million decrease in revenues associated with establishing regulatory assets in Texas in 2003 (see “Texas Restructuring” section of Note 6). These revenues did not continue after 2003.

· A $24 million decrease in retail revenues driven by a 9% decrease in cooling degree-days offset by a slight increase in heating degree days. Average price per KWH decreased 2%.

· An $8 million increase in Maintenance expense primarily due to the STP Unit 2 forced outage in the first quarter of 2003, and the STP Unit 1 scheduled refueling outage and forced outage in the second and third quarters of 2003.

· A $7 million decrease in revenues from ERCOT for various services, including balancing energy.

· A $7 million decrease in off-system sales, including those to REPs, primarily due to a decrease in the overall average price per KWH and higher KWH sales of 2%.

The decrease in Operating Income was partially offset by:

· A $214 million increase in RMR revenues from ERCOT which include both fuel recovery and a fixed cost component of $35 million (see “Texas Plants” in Note 10 for discussion of RMR facilities).

· A $41 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $31 million increase in margins resulting from risk management activities.

· A $25 million increase in other operating revenue comprised primarily of miscellaneous service revenue and fees as a result of the Texas Restructuring Legislation.

· A $24 million decrease in Depreciation and Amortization expense primarily due to decreases resulting from ARO of $16 million (see “Asset Retirement Obligations” in Note 2) and reduced depreciable plant by $6 million due to the mothballing of certain generating units in 2002.

· A $7 million decrease in Other Operation expense primarily due to lower distribution and customer related expenses in 2003, offset in part by $16 million of accretion expense associated with the implementation of SFAS 143, as well as increased costs of $6 million related to 2003 ERCOT transmission charges.

· A $3 million decrease in Taxes Other Than Income Taxes primarily due to reduced gross receipt taxes as a result of the sale of the Texas REPs, partially offset by higher property taxes.

Other Impacts on Earnings

Nonoperating Income increased $1 million. While 2003 gains from risk management activities increased $33 million, they are almost totally offset by lower 2003 revenues of $33 million from third party nonutility energy related construction projects.

Nonoperating Expense decreased $25 million primarily due to lower nonutility expenses associated with energy related construction projects for third parties.

Interest Charges increased $8 million primarily due to the replacement of lower cost short-term floating rate debt with longer-term higher cost fixed rate debt.

Income Taxes

The effective tax rates for 2003 and 2002 were 32.6% and 34.0%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35.0% is due to permanent differences, amortization of investment tax credits, consolidated tax savings, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Cumulative Effect of Accounting Change

This amount represents the one-time after tax effect of the application of EITF 02-3 (see “Accounting for Risk Management Contracts” in Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Our current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	Baa1	BBB	A
Senior Unsecured Debt	Baa2	BBB	A-

Cash Flow

Cash flows for the year ended December 31, 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(in thousands)
Cash and cash equivalents at beginning of period	$	760		$	807		$	10,610
Cash flows from (used for):
Operating activities		274,110			357,378			128,109
Investing activities		216,561			(104,980	)		(216,432	)
Financing activities		(491,431	)		(252,445	)		78,520
Net decrease in cash and cash equivalents		(760	)		(47	)		(9,803	)
Cash and cash equivalents at end of period	$	-		$	760		$	807

Operating Activities

Our net cash flows from operating activities were $274 million in 2004. We produced income of $174 million during the period and noncash items of $123 million for Depreciation and Amortization, $121 million for an Extraordinary Loss on Stranded Cost Recovery and $(302) million for Carrying Costs on Stranded Cost Recovery. See “Results of Operations” for discussions of these items. The change in Other Noncurrent Assets and other liabilities are primarily due to additional pension plan funding during the current year. The 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 working capital relates to a number of items; the most significant is a $117 million change in Taxes Accrued. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extension is filed.

Our net cash flows from operating activities were $357 million in 2003. We produced income of $218 million during the period and noncash items of $198 million for Depreciation and Amortization (see “Results of Operations) and $(218) million for Wholesale Capacity Auction True-up (see “Texas Restructuring” and “Wholesale Capacity Auction True-up” in Note 6). The 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 working capital relates to a number of items; the most significant are a $56 million change in Accounts Payable primarily due to increased payables related to gas purchases and a $42 million change in Taxes Accrued as a result of taxes that were accrued during 2003 in excess of the amount remitted to the government.

Our net cash flows from operating activities were $128 million in 2002. We produced income of $276 million during the period and noncash items of $222 million for Depreciation and Amortization (see “Results of Operations), $114 million for Deferred Income Taxes and $(262) million for Wholesale Capacity Auction True-up (see “Texas Restructuring” and “Wholesale Capacity Auction True-up” section of Note 6). Deferred Income Taxes of $114 million were primarily due to the recording of deferred taxes related to the Wholesale Capacity Auction True-up. The 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 working capital relates to a number of items; the most significant is a $(217) million change in Accounts Receivable, Net primarily due to increased receivables related to the changes associated with the Texas Restructuring Legislation and an adjustment to the interchange cost reconstruction system.

Investing Activities

Our net cash flows from investing activities in 2004 were $217 million primarily due to $430 million in proceeds from the sale of several of our generation plants offset in part by $121 million of construction expenditures focused on improved service reliability projects for transmission and distribution systems.

Our net cash flows used for investing activities in 2003 were $105 million primarily due to construction expenditures focused on improved service reliability projects for transmission and distribution systems.

Our net cash flows used for investing activities in 2002 were $216 million primarily due to construction expenditures.

Financing Activities

Our net cash flows used for financing activities in 2004 were $491 million primarily due to the retirement of long-term debt and payment of dividends on common stock mainly with funds received from the sale of generation plants.

Our net cash flows used for financing activities in 2003 were $252 million primarily due to replacing both short and long-term debt with proceeds from new borrowings.

Our net cash flows from financing activities in 2002 were $79 million primarily due to the issuance of short-term debt. This issuance was partially offset by the retirement of common stock and decreased borrowing from the Utility Money Pool resulting from TCC Transition Funding new debt.

In February 2005, we reissued $162 million Matagorda County Navigation District Installment Purchase Contracts due May 1, 2030 that were put to us in November 2004. These bonds had not been retired as we intended to reissue the bonds at a later date. The original installment purchase contracts were mandatory one-year put bonds with fixed rates of 2.15% for Series A and 2.35% for Series B at the time of the put. The reissued contracts bear interest at 35-day auction rates.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payments Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	365.7	$	205.6	$	122.3	$	1,216.6	$	1,910.2
Advances from Affiliates (b)		0.2		-		-		-		0.2
Capital Lease Obligations (c)		0.5		0.4		0.1		-		1.0
Noncancelable Operating Leases (c)		5.8		7.6		5.1		6.2		24.7
Energy and Capacity Purchase Contracts (d)		22.9		46.1		41.8		96.7		207.5
Total	$	395.1	$	259.7	$	169.3	$	1,319.5	$	2,143.6

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	Represents short-term borrowings from the Utility Money Pool.
(c)	See Note 15.
(d)	Represents contractual cash flows of energy and capacity purchase contracts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2004 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 Years		Total
Standby Letters of Credit (a)	$	-	$	43.4	$	-	$	-	$	43.4
Guarantees of Our Performance (b)		-		129.0		-		-		129.0
Transmission Facilities for Third
Parties (c)		24.4		29.6		14.0		24.8		92.8
Total	$	24.4	$	202.0	$	14.0	$	24.8	$	265.2

(a)	We have issued standby letters of credit to third parties. These letters of credit cover debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $43 million maturing in November 2005. There is no recourse to third parties in the event these letters of credit are drawn.
(b)	See Note 8.
(c)	As construction agent for third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section  for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	11,942
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(5,033	)
Fair Value of New Contracts When Entered During the Period (b)		1,175
Net Option Premiums Paid/(Received) (c)		(123	)
Change in Fair Value Due to Valuation Methodology Changes (d)		110
Changes in Fair Value of Risk Management Contracts (e)		1,630
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		-
Total MTM Risk Management Contract Net Assets		9,701
Net Cash Flow Hedge Contracts (g)		565
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	10,266

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	10,107		$	3,941		$	14,048
Noncurrent Assets		9,504			4			9,508
Total MTM Derivative Contract Assets		19,611			3,945			23,556
Current Liabilities		(5,277	)		(3,117	)		(8,394	)
Noncurrent Liabilities		(4,633	)		(263	)		(4,896	)
Total MTM Derivative Contract Liabilities		(9,910	)		(3,380	)		(13,290	)
Total MTM Derivative Contract Net Assets	$	9,701		$	565		$	10,266

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange  Traded Contracts	$	(1,280	)	$	(46	)	$	644		$	-	$	-	$	-	$	(682	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		6,331			1,862			1,604			781		-		-		10,578
Prices Based on Models and Other  Valuation Methods (b)		(221	)		(1,158	)		(1,217	)		279		862		1,260		(195	)
Total	$	4,830		$	658		$	1,031		$	1,060	$	862	$	1,260	$	9,701

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges

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

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

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power
Beginning Balance December 31, 2003	$	(1,828	)
Changes in Fair Value (a)		866
Reclassifications from AOCI to Net Income (b)		1,619
Ending Balance December 31, 2004	$	657

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $825 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$157	$511	$220	$75	$189	$733	$307	$73

VaR Associated with Debt Outstanding

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 $120 million and $206 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003		2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,128,227		$	1,593,943	$	682,049
Sales to AEP Affiliates		47,039			153,568		1,008,444
TOTAL		1,175,266			1,747,511		1,690,493
OPERATING EXPENSES
Fuel for Electric Generation		59,512			89,389		88,488
Fuel from Affiliates for Electric Generation		101,906			195,527		157,346
Purchased Energy for Resale		206,447			373,388		211,358
Purchased Electricity from AEP Affiliates		6,140			19,097		23,406
Other Operation		301,160			289,232		296,065
Maintenance		63,599			71,361		63,392
Depreciation and Amortization		122,585			197,776		222,191
Taxes Other Than Income Taxes		91,001			92,109		95,500
Income Taxes		26,897			98,092		139,014
TOTAL		979,247			1,425,971		1,296,760
OPERATING INCOME		196,019			321,540		393,733
Carrying Costs on Stranded Cost Recovery		301,644			-		-
Nonoperating Income		45,729			54,172		53,141
Nonoperating Expenses		16,790			17,273		41,910
Nonoperating Income Tax Expense		108,161			7,080		3,152
Interest Charges		123,785			133,812		125,871
Income Before Extraordinary Loss and Cumulative Effect of   Accounting Change		294,656			217,547		275,941
Extraordinary Loss on Stranded Cost Recovery, Net of Tax		(120,534	)		-		-
Cumulative Effect of Accounting Change, Net of Tax		-			122		-
NET INCOME		174,122			217,669		275,941
Gain on Reacquired Preferred Stock		-			-		4
Preferred Stock Dividend Requirements		241			241		241
EARNINGS APPLICABLE TO COMMON STOCK	$	173,881		$	217,428	$	275,704

The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock			Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	168,888		$	405,015		$	826,197		$	-		$	1,400,100
Redemption of Common Stock		(113,596	)		(272,409	)								(386,005	)
Gain on Reacquired Preferred Stock								4						4
Common Stock Dividends								(115,505	)					(115,505	)
Preferred Stock Dividends								(241	)					(241	)
TOTAL														898,353
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $19											(36	)		(36	)
Minimum Pension Liability, Net of Tax of $39,375											(73,124	)		(73,124	)
NET INCOME								275,941						275,941
TOTAL COMPREHENSIVE INCOME														202,781
DECEMBER 31, 2002		55,292			132,606			986,396			(73,160	)		1,101,134
Common Stock Dividends								(120,801	)					(120,801	)
Preferred Stock Dividends								(241	)					(241	)
TOTAL														980,092
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $965											(1,792	)		(1,792	)
Minimum Pension Liability, Net of Tax of $7,043											13,080			13,080
NET INCOME								217,669						217,669
TOTAL COMPREHENSIVE INCOME														228,957
DECEMBER 31, 2003		55,292			132,606			1,083,023			(61,872	)		1,209,049
Common Stock Dividends								(172,000	)					(172,000	)
Preferred Stock Dividends								(241	)					(241	)
TOTAL														1,036,808
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,338											2,485			2,485
Minimum Pension Liability, Net of Tax of $31,790											55,228			55,228
NET INCOME								174,122						174,122
TOTAL COMPREHENSIVE INCOME														231,835
DECEMBER 31, 2004	$	55,292		$	132,606		$	1,084,904		$	(4,159	)	$	1,268,643

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Transmission	$	788,371		$	767,970
Distribution		1,433,380			1,376,761
General		220,435			221,354
Construction Work in Progress		50,612			58,953
Total		2,492,798			2,425,038
Accumulated Depreciation and Amortization		725,225			695,359
TOTAL - NET		1,767,573			1,729,679
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		1,577			1,302
Bond Defeasance Funds		22,110			-
Other Investments		-			4,639
TOTAL		23,687			5,941
CURRENT ASSETS
Cash and Cash Equivalents		-			760
Other Cash Deposits		135,132			65,122
Advances to Affiliates		-			60,699
Accounts Receivable:
Customers		157,431			146,630
Affiliated Companies		67,860			78,484
Accrued Unbilled Revenues		21,589			23,077
Allowance for Uncollectible Accounts		(3,493	)		(1,710	)
Materials and Supplies		12,288			11,707
Risk Management Assets		14,048			22,051
Margin Deposits		1,891			3,230
Prepayments and Other Current Assets		9,151			10,635
TOTAL		415,897			420,685
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		15,236			3,249
Wholesale Capacity Auction True-Up		559,973			480,000
Unamortized Loss on Reacquired Debt		11,842			9,086
Designated for Securitization		1,361,299			1,289,436
Deferred Debt - Restructuring		11,596			12,015
Other		102,032			127,488
Securitized Transition Assets		642,384			689,399
Long-term Risk Management Assets		9,508			7,627
Prepaid Pension Obligations		109,628			-
Deferred Charges		36,986			51,690
TOTAL		2,860,484			2,669,990
Assets Held for Sale - Texas Generation Plants		628,149			1,028,134
TOTAL ASSETS	$	5,695,790		$	5,854,429

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $25 Par Value Per Share:
Authorized - 12,000,000 Shares
Outstanding - 2,211,678 Shares	$	55,292		$	55,292
Paid-in Capital		132,606			132,606
Retained Earnings		1,084,904			1,083,023
Accumulated Other Comprehensive Loss		(4,159	)		(61,872	)
Total Common Shareholder’s Equity		1,268,643			1,209,049
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,940			5,940
Total Shareholders’ Equity		1,274,583			1,214,989
Long-term Debt - Nonaffiliated		1,541,552			2,053,974
TOTAL		2,816,135			3,268,963
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		365,742			237,651
Advances from Affiliates		207			-
Accounts Payable:
General		109,688			90,004
Affiliated Companies		64,045			74,209
Customer Deposits		6,147			1,517
Taxes Accrued		184,014			67,018
Interest Accrued		41,227			43,196
Risk Management Liabilities		8,394			17,888
Obligations Under Capital Leases		412			407
Other		20,115			23,248
TOTAL		799,991			555,138
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		1,247,111			1,244,912
Long-term Risk Management Liabilities		4,896			2,660
Regulatory Liabilities:
Asset Removal Costs		102,624			95,415
Deferred Investment Tax Credits		107,743			112,479
Over-recovery of Fuel Costs		211,526			150,026
Retail Clawback		61,384			45,527
Other		76,653			86,706
Obligations Under Capital Leases		468			636
Deferred Credits and Other		17,276			63,833
TOTAL		1,829,681			1,802,194
Liabilities Held for Sale - Texas Generation Plants		249,983			228,134
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,695,790		$	5,854,429

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	174,122		$	217,669		$	275,941
Adjustments to Reconcile Net Income to Net Cash Flows From   Operating Activities:
Depreciation and Amortization		122,585			197,776			222,191
Deferred Income Taxes		16,490			19,393			113,655
Deferred Investment Tax Credits		(4,736	)		(5,207	)		(5,207	)
Cumulative Effect of Accounting Change		-			(122	)		-
Carrying Costs on Stranded Cost Recovery		(301,644	)		-			-
Extraordinary Loss on Stranded Cost Recovery, Net of Tax		120,534			-			-
Mark-to-Market of Risk Management Contracts		2,241			(6,341	)		(1,558	)
Wholesale Capacity Auction True-up		(79,973	)		(218,000	)		(262,000	)
Pension Contribution		(61,910	)		(86	)		-
Fuel Recovery		61,500			81,000			16,455
Change in Other Noncurrent Assets		88,025			20,014			(83,183	)
Change in Other Noncurrent Liabilities		827			(49,390	)		123,800
Changes in Components of Working Capital:
Accounts Receivable, Net		18,952			15,190			(217,149	)
Fuel, Materials and Supplies		(10,641	)		15,851			(4,899	)
Accounts Payable		9,520			55,772			(6,167	)
Taxes Accrued		116,996			42,227			(58,721	)
Interest Accrued		(1,969	)		(8,009	)		27,490
Customer Deposits		4,630			852			(26,078	)
Other Current Assets		1,689			(8,165	)		402
Other Current Liabilities		(3,128	)		(13,046	)		13,137
Net Cash Flows From Operating Activities		274,110			357,378			128,109
INVESTING ACTIVITIES
Construction Expenditures		(121,313	)		(131,925	)		(132,261	)
Change in Other Cash Deposits, Net		(70,010	)		19,490			(84,314	)
Proceeds from Sale of Assets		429,553			7,455			-
Other		(21,669	)		-			143
Net Cash Flows From (Used For) Investing Activities		216,561			(104,980	)		(216,432	)
FINANCING ACTIVITIES
Change in Short-term Debt, Net - Affiliated		-			(650,000	)		-
Change in Short-term Debt, Net - Nonaffiliated		-			-			650,000
Issuance of Long-term Debt - Nonaffiliated		-			953,136			-
Issuance of Long-term Debt - Affiliated		-			-			797,335
Retirement of Long-term Debt		(380,096	)		(247,127	)		(639,492	)
Change in Advances to/from Affiliates, Net		60,906			(187,410	)		(227,566	)
Retirement of Common Stock		-			-			(386,005	)
Retirement of Preferred Stock		-			(2	)		(6	)
Dividends Paid on Common Stock		(172,000	)		(120,801	)		(115,505	)
Dividends Paid on Cumulative Preferred Stock		(241	)		(241	)		(241	)
Net Cash Flows (Used For) From Financing Activities		(491,431	)		(252,445	)		78,520
Net Decrease in Cash and Cash Equivalents		(760	)		(47	)		(9,803	)
Cash and Cash Equivalents at Beginning of Period		760			807			10,610
Cash and Cash Equivalents at End of Period	$	-		$	760		$	807

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $117,325,000, $129,491,000 and $93,120,000 and for income taxes was $(1,058,000), $49,630,000 and $95,600,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $348,000.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

	2004	2003
	(in thousands)
PREFERRED STOCK:
$100 Par Value Per Share - Authorized 3,035,000 shares

	Call Price	Number of Shares			Shares
	December 31,	Redeemed			Outstanding
Series	2004	Year Ended December 31,			December 31, 2004
		2004	2003	2002
Not Subject to Mandatory Redemption
4.00%	$105.75	5	11	100	41,922	$	4,192	$	4,192
4.20%	103.75	-	-	-	17,476		1,748		1,748
Total						$	5,940	$	5,940

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	84,344		$	117,939
Securitization Bonds		697,193			745,680
Senior Unsecured Notes		797,863			797,532
Installment Purchase Contracts		327,894			489,585
Note Payable to Trust (a)		-			140,889
Less Portion Due Within One Year		(365,742	)		(237,651	)
Long-term Debt Excluding Portion Due Within One Year	$	1,541,552		$	2,053,974

(a) See “Trust Preferred Securities” section of Note 16 for discussion of Note Payable to Trust.

There are certain limitations on establishing liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

		2004		2003
% Rate	Due	(in thousands)
7.250	2004 - October 1	$	-	$	27,400
7.125	2008 - February 1		18,581		18,581
6.625	2005 - July 1		65,763		71,958
Total		$	84,344	$	117,939

First Mortgage Bonds are secured by a first mortgage lien on Electric Utility Plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually. In 2004, the First Mortgage Bonds were defeased in connection with the sale of several generation plants.

Securitization Bonds outstanding were as follows:

			2004			2003
% Rate	Final Payment Date	Maturity Date	(in thousands)
3.54	1/15/2005	1/15/2007	$	29,386		$	77,937
5.01	1/15/2008	1/15/2010		154,507			154,507
5.56	1/15/2010	1/15/2012		107,094			107,094
5.96	7/15/2013	7/15/2015		214,927			214,927
6.25	1/15/2016	1/15/2017		191,857			191,857
Unamortized Discount				(578	)		(642	)
Total			$	697,193		$	745,680

The Securitization Bonds mature at different times through 2017 and have a weighted average interest rate of 5.7 percent at December 31, 2004.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
5.500	2013 - February 15	$	275,000		$	275,000
6.650	2033 - February 15		275,000			275,000
3.000	2005 - February 15		150,000			150,000
(a)	2005 - February 15		100,000			100,000
Unamortized Discount			(2,137	)		(2,468	)
Total		$	797,863		$	797,532

(a) A floating interest rate is determined quarterly. The rate on December 31, 2004 was 3.54%.

Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004			2003
	% Rate	Due	(in thousands)
Matagorda County Navigation District,  Texas	6.000	2028 - July 1	$	120,265		$	120,265
	6.125	2030 - May 1		60,000			60,000
	2.150	2030 - May 1 (a)		-			111,700
	4.550	2029 - November 1 (b)		100,635			100,635
	2.350	2030 - May 1 (a)		-			50,000
Guadalupe-Blanco River Authority  District, Texas	(c)	2015 - November 1		40,890			40,890
Red River Authority of Texas	6.00	2020 - June 1		6,330			6,330
	Unamortized Discount			(226	)		(235	)
	Total		$	327,894		$	489,585

(a)	These bonds were reissued in February 2005.
(b)	Installment Purchase Contract provides for bonds to be tendered in 2006 for 4.55% series. Therefore, this installment purchase contract has been classified for payment in 2006.
(c)	A floating interest rate is determined daily. The rate on December 31, 2004 and 2003 was 2.15% and 1.30%, respectively.

Under the terms of the installment purchase contracts, we are required to pay amounts sufficient to enable the payment of interest on and the principal (at stated maturities and upon mandatory redemptions) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments range from monthly to semi-annually.

Note Payable to Trust was outstanding as follows:

		2004		2003
% Rate	Due	(in thousands)
8.00	2037 - April 30	$	-	$	140,889

See “Trust Preferred Securities” in Note 16 for discussion of Notes Payable to Trust.

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	365,742
2006		152,900
2007		52,730
2008		68,688
2009		53,627
Later Years		1,216,548
Total Principal Amount		1,910,235
Unamortized Discount		(2,941	)
Total	$	1,907,294

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TCC’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to TCC.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Jointly-Owned Electric Utility Plant	Note 18
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

AEP Texas Central Company:

We have audited the accompanying consolidated balance sheets of AEP Texas Central Company and subsidiary as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of AEP Texas Central Company and subsidiary as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003; FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003; and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

AEP TEXAS NORTH COMPANY

AEP TEXAS NORTH COMPANY

SELECTED FINANCIAL DATA

(in thousands)

	2004		2003			2002			2001		2000
STATEMENTS OF OPERATIONS DATA
Operating Revenues	$	492,145	$	465,946		$	450,740		$	556,458	$	571,064
Operating Income		61,246		68,027			7,871			33,390		52,341
Interest Charges		21,985		22,049			20,845			23,275		23,216
Income (Loss) Before Extraordinary Loss and   Cumulative Effect of Accounting Change		47,659		55,663			(13,677	)		12,310		27,450
Extraordinary Loss, Net of Tax		-		(177	)		-			-		-
Cumulative Effect of Accounting Change, Net of Tax		-		3,071			-			-		-
Net Income (Loss)		47,659		58,557			(13,677	)		12,310		27,450
BALANCE SHEETS DATA
Electric Utility Plant	$	1,182,327	$	1,233,427		$	1,201,747		$	1,260,872	$	1,229,339
Accumulated Depreciation and Amortization		405,933		460,513			446,818			475,036		447,802
Net Electric Utility Plant	$	776,394	$	772,914		$	754,929		$	785,836	$	781,537
Total Assets	$	1,051,529	$	989,009		$	952,149		$	936,001	$	1,154,743
Common Shareholder's Equity		310,421		238,275			180,744			245,535		262,153
Cumulative Preferred Stock Not Subject to   Mandatory Redemption		2,357		2,357			2,367			2,367		2,367
Long-term Debt (a)		314,357		356,754			132,500			255,967		255,843
Obligations Under Capital Leases (a)		534		473			-			-		-

(a) Including portion due within one year.

AEP TEXAS NORTH COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

TNC is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power in west and central Texas. As a power pool member with AEP West companies, we share in the revenues and expenses of the power pool’s sales to neighboring utilities and power marketers. We also sell electric power at wholesale to other utilities, municipalities, rural electric cooperatives and retail electric providers (REPs) in Texas.

Power pool members are compensated for energy delivered to other members based upon the delivering members’ incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

2004 Compared to 2003

Net Income decreased $11 million for 2004 primarily driven by lower margins from risk management activities, a provision for potential loss on fuel disputes and a 2003 Cumulative Effect of Accounting Change.

Operating Income

Operating Income decreased $7 million primarily due to:

· A $31 million net increase in fuel and purchased power expenses. KWHs purchased increased 17% while the average cost per KWH purchased decreased 23%. KWH generation increased 1% while the generation cost per KWH increased 20% primarily due to a one-time provision for possible loss in fuel disputes.

· A $5 million decrease in margins from risk management activities.

· A $5 million decrease in other electric revenue, primarily Qualified Scheduling Entity (QSE) fees and miscellaneous service revenue.

· A $3 million increase in Depreciation and Amortization expenses primarily due to the 2003 amortization credit adjustment for excess earnings accruals related to a final court determination (see “Texas Restructuring” and “Unrefunded Excess Earnings” section of Note 6).

· A $2 million increase in Taxes Other Than Income Taxes primarily due to higher accrued property taxes attributable to changes in property values, property tax rates, net fixed asset increases, accrual update adjustments and timing of prior period true-ups.

· A $2 million decrease in Reliability Must Run (RMR) revenues from ERCOT, which include a fuel recovery increase of $2 million and a fixed cost decrease of $4 million. We will no longer have RMR revenues after 2004. In 2004, RMR revenues totaled $51 million of which $9 million was for reimbursement of fixed cost.

· A $2 million increase in Other Operation expenses primarily due to higher ERCOT related transmission expense.

· A $2 million increase in Maintenance expenses primarily due to overhead line and pole inspection expenses.

The decrease in Operating Income was partially offset by:

· A $12 million increase in off-system sales, including those to REPs, primarily due to higher KWH sales of 2%.

· A $10 million increase in revenues due to a decrease in provision for rate refunds primarily due to fuel reconciliation issues (see “TNC Fuel Reconciliations” section of Note 4).

· A $10 million increase in transmission revenue primarily due to prior year adjustments recorded in 2004 for affiliated open access transmission tariff and ancillary services resulting from revised data received from ERCOT for the years 2001-2003.

· A $7 million increase in revenues from ERCOT for various services, including balancing energy and prior year adjustments made by ERCOT.

· A $7 million decrease in Income Taxes. See Income Taxes section below for further discussion.

Other Impacts on Earnings

Nonoperating Income decreased $6 million primarily as a result of a $3 million decrease in nonutility revenue associated with energy-related construction projects for third parties and a decrease of $3 million related to risk management activities.

Nonoperating Expenses decreased $4 million primarily due to lower nonutility expenses associated with energy-related construction projects for third parties.

Income Taxes

The effective tax rates for 2004 and 2003 were 32.1% and 35.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35.0% is due to permanent differences, amortization of investment tax credits, consolidated tax savings, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to an increase in favorable federal income tax adjustments.

Extraordinary Loss

Extraordinary Loss in 2003 resulted from the cessation of SFAS 71 accounting for wholesale generation assets due to the FERC settlement case (see “Extraordinary Item” in Note 2).

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to a one-time after tax impact of adopting SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003 (see “Asset Retirement Obligations” in Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Our current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	A3	BBB	A
Senior Unsecured Debt	Baa1	BBB	A-

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payments due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	37.6	$	8.1	$	-	$	269.4	$	315.1
Capital Lease Obligations (b)		0.2		0.2		0.1		0.1		0.6
Noncancelable Operating Leases (b)		2.2		3.4		2.8		3.0		11.4
Energy and Capacity Purchase Contracts (c)		19.9		39.9		36.2		83.8		179.8
Total	$	59.9	$	51.6	$	39.1	$	356.3	$	506.9

(a)	See Schedule of Long-term Debt. Represents principal only excluding interest.
(b)	See Note 15.
(c)	Represents contractual cash flows of energy and capacity purchase contracts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2004 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Transmission Facilities for Third Parties (a)	$	20.2	$	34.0	$	6.4	$	-	$	60.6

(a) As construction agent for third party owners of transmission facilities, we have committed by contract terms to complete construction by dates specified in the contracts. Should we default on these obligations, financial payments could be required including liquidating damages of up to $8 million and other remedies required by contract terms.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effects on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	4,620
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(1,915	)
Fair Value of New Contracts When Entered During the Period (b)		508
Net Option Premiums Paid/(Received) (c)		(53	)
Change in Fair Value Due to Valuation Methodology Changes (d)		45
Changes in Fair Value of Risk Management Contracts (e)		987
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		-
Total MTM Risk Management Contract Net Assets		4,192
Net Cash Flow Hedge Contracts (g)		245
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	4,437

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	4,368		$	1,703		$	6,071
Noncurrent Assets		4,107			3			4,110
Total MTM Derivative Contract Assets		8,475			1,706			10,181
Current Liabilities		(2,281	)		(1,347	)		(3,628	)
Noncurrent Liabilities		(2,002	)		(114	)		(2,116	)
Total MTM Derivative Contract Liabilities		(4,283	)		(1,461	)		(5,744	)
Total MTM Derivative Contract Net Assets	$	4,192		$	245		$	4,437

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(553	)	$	(20	)	$	278		$	-	$	-	$	-	$	(295	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		2,736			805			693			338		-		-		4,572
Prices Based on Models and Other Valuation Methods (b)		(96	)		(502	)		(526	)		121		373		545		(85	)
Total	$	2,087		$	283		$	445		$	459	$	373	$	545	$	4,192

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges.

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

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

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power
Beginning Balance December 31, 2003	$	(601	)
Changes in Fair Value (a)		373
Reclassifications from AOCI to Net Income (b)		513
Ending Balance December 31, 2004	$	285

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $357 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$68	$221	$95	$33	$76	$294	$123	$29

VaR Associated with Debt Outstanding

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 $13 million and $33 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or financial position.

AEP TEXAS NORTH COMPANY

STATEMENTS OF OPERATIONS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004		2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	440,465	$	410,793		$	210,315
Sales to AEP Affiliates		51,680		55,153			240,425
TOTAL		492,145		465,946			450,740
OPERATING EXPENSES
Fuel for Electric Generation		54,442		39,082			36,081
Fuel from Affiliates for Electric Generation		46,496		44,197			64,385
Purchased Energy for Resale		134,774		87,006			80,391
Purchased Electricity from AEP Affiliates		5,211		39,409			37,582
Other Operation		87,046		85,263			104,960
Asset Impairments		-		-			42,898
Maintenance		20,602		18,961			22,295
Depreciation and Amortization		39,025		36,242			43,620
Taxes Other Than Income Taxes		22,630		20,570			22,471
Income Taxes Expense (Credit)		20,673		27,189			(11,814	)
TOTAL		430,899		397,919			442,869
OPERATING INCOME		61,246		68,027			7,871
Nonoperating Income		62,036		68,451			53,884
Nonoperating Expenses		51,802		55,692			54,876
Nonoperating Income Tax Expense (Credit)		1,836		3,074			(289	)
Interest Charges		21,985		22,049			20,845
Income (Loss) Before Extraordinary Loss and Cumulative Effect of   Accounting Change		47,659		55,663			(13,677	)
Extraordinary Loss, Net of Tax		-		(177	)		-
Cumulative Effect of Accounting Change, Net of Tax		-		3,071			-
NET INCOME (LOSS)		47,659		58,557			(13,677	)
Gain on Reacquired Preferred Stock		-		3			-
Preferred Stock Dividend Requirements		103		104			104
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK	$	47,556	$	58,456		$	(13,781	)

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	137,214	$	2,351	$	105,970		$	-		$	245,535
Common Stock Dividends						(20,247	)					(20,247	)
Preferred Stock Dividends						(104	)					(104	)
TOTAL												225,184
COMPREHENSIVE LOSS
Other Comprehensive Income (Loss),  Net of Taxes:
Cash Flow Hedges, Net of Tax of $8									(15	)		(15	)
Minimum Pension Liability, Net of Tax of $16,557									(30,748	)		(30,748	)
NET LOSS						(13,677	)					(13,677	)
TOTAL COMPREHENSIVE LOSS												(44,440	)
DECEMBER 31, 2002		137,214		2,351		71,942			(30,763	)		180,744
Common Stock Dividends						(4,970	)					(4,970	)
Preferred Stock Dividends						(104	)					(104	)
Gain on Reacquired Preferred Stock						3						3
TOTAL												175,673
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),  Net of Taxes:
Cash Flow Hedges, Net of Tax of $316									(586	)		(586	)
Minimum Pension Liability, Net of Tax of $2,498									4,631			4,631
NET INCOME						58,557						58,557
TOTAL COMPREHENSIVE INCOME												62,602
DECEMBER 31, 2003		137,214		2,351		125,428			(26,718	)		238,275
Common Stock Dividends						(2,000	)					(2,000	)
Preferred Stock Dividends						(103	)					(103	)
TOTAL												236,172
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),
Net of Taxes:
Cash Flow Hedges, Net of Tax of $477									886			886
Minimum Pension Liability, Net of Tax of $13,841									25,704			25,704
NET INCOME						47,659						47,659
TOTAL COMPREHENSIVE INCOME												74,249
DECEMBER 31, 2004	$	137,214	$	2,351	$	170,984		$	(128	)	$	310,421

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	287,212		$	360,463
Transmission		281,359			268,695
Distribution		474,961			456,278
General		115,174			117,792
Construction Work in Progress		23,621			30,199
Total		1,182,327			1,233,427
Accumulated Depreciation and Amortization		405,933			460,513
TOTAL - NET		776,394			772,914
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		1,407			1,286
CURRENT ASSETS
Other Cash Deposits		2,308			2,863
Advances to Affiliates		51,504			41,593
Accounts Receivable:
Customers		90,109			56,670
Affiliated Companies		21,474			28,910
Accrued Unbilled Revenues		3,789			4,871
Miscellaneous		-			3,411
Allowance for Uncollectible Accounts		(787	)		(175	)
Unbilled Construction Costs		22,065			16,943
Fuel Inventory		3,148			10,925
Materials and Supplies		8,273			8,866
Risk Management Assets		6,071			10,340
Margin Deposits		818			1,285
Prepayments and Other		1,053			1,834
TOTAL		209,825			188,336
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Under Recovery of Fuel Costs		-			6,180
Deferred Debt - Restructuring		6,093			6,579
Unamortized Loss on Reacquired Debt		2,147			3,929
Other		3,783			3,332
Long-term Risk Management Assets		4,110			3,106
Prepaid Pension Obligations		44,911			-
Deferred Charges		2,859			3,347
TOTAL		63,903			26,473
TOTAL ASSETS	$	1,051,529		$	989,009

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $25 Par Value per share:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares	$	137,214		$	137,214
Paid-in Capital		2,351			2,351
Retained Earnings		170,984			125,428
Accumulated Other Comprehensive Income (Loss)		(128	)		(26,718	)
Total Common Shareholder’s Equity		310,421			238,275
Cumulative Preferred Stock Not Subject to Mandatory Redemption		2,357			2,357
Total Shareholders’ Equity		312,778			240,632
Long-term Debt - Nonaffiliated		276,748			314,249
TOTAL		589,526			554,881
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		37,609			42,505
Accounts Payable:
General		22,444			28,190
Affiliated Companies		52,801			40,601
Customer Deposits		1,020			161
Taxes Accrued		37,269			22,877
Interest Accrued		5,044			6,038
Risk Management Liabilities		3,628			8,658
Obligations Under Capital Leases		220			203
Other		9,628			9,419
TOTAL		169,663			158,652
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		138,465			113,019
Long-term Risk Management Liabilities		2,116			1,094
Regulatory Liabilities:
Asset Removal Costs		81,143			76,740
Deferred Investment Tax Credits		18,698			19,990
Over-recovery of Fuel Costs		3,920			-
Retail Clawback		13,924			11,804
Excess Earnings		13,270			14,262
SFAS 109 Regulatory Liability, Net		8,500			13,655
Other		1,319			1,826
Obligations Under Capital Leases		314			270
Deferred Credits and Other		10,671			22,816
TOTAL		292,340			275,476
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	1,051,529		$	989,009

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income (Loss)	$	47,659		$	58,557		$	(13,677	)
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows From   Operating Activities:
Depreciation and Amortization		39,025			36,242			43,620
Extraordinary Item		-			177			-
Asset Impairments and Investment Value Losses		-			-			42,898
Deferred Income Taxes		4,236			(3,493	)		(12,275	)
Deferred Investment Tax Credits		(1,292	)		(1,521	)		(1,271	)
Cumulative Effect of Accounting Change		-			(3,071	)		-
Mark-to-Market of Risk Management Contracts		428			(2,558	)		(1,127	)
Over/Under Fuel Recovery		10,100			15,960			14,169
Pension Contribution		(21,172	)		(410	)		-
Change in Other Noncurrent Assets		(8,368	)		6,081			(15,719	)
Change in Other Noncurrent Liabilities		13,521			(5,069	)		14,985
Changes in Components of Working Capital:
Accounts Receivable, Net		(18,779	)		14,393			(80,900	)
Fuel, Materials and Supplies		8,370			2,460			(2,754	)
Accounts Payable		6,454			(40,140	)		63,761
Taxes Accrued		14,392			19,180			(13,661	)
Customer Deposits		859			45			(4,075	)
Interest Accrued		(994	)		3,261			(1,986	)
Other Current Assets		(4,834	)		(15,035	)		(1,209	)
Other Current Liabilities		225			(7,791	)		7,590
Net Cash Flows From Operating Activities		89,830			77,268			38,369
INVESTING ACTIVITIES
Construction Expenditures		(36,375	)		(46,683	)		(43,563	)
Change in Other Cash Deposits, Net		555			(1,706	)		(764	)
Proceeds from Sale of Assets		510			688			-
Other		-			-			150
Net Cash Flows Used For Investing Activities		(35,310	)		(47,701	)		(44,177	)
FINANCING ACTIVITIES
Change in Short-term Debt, Net - Affiliated		-			(125,000	)		125,000
Issuance of Long-term Debt		-			222,455			-
Retirement of Long-term Debt		(42,506	)		-			(130,799	)
Retirement of Preferred Stock		-			(10	)		-
Changes in Advances to/from Affiliates, Net		(9,911	)		(122,000	)		29,959
Dividends Paid on Common Stock		(2,000	)		(4,970	)		(20,247	)
Dividends Paid on Cumulative Preferred Stock		(103	)		(104	)		(104	)
Net Cash Flows From (Used For) Financing Activities		(54,520	)		(29,629	)		3,809
Net Decrease in Cash and Cash Equivalents		-			(62	)		(1,999	)
Cash and Cash Equivalents at Beginning of Period		-			62			2,061
Cash and Cash Equivalents at End of Period	$	-		$	-		$	62

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $20,860,000, $16,384,000 and $19,934,000 and for income taxes was $6,905,000, $16,081,000 and $15,544,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $282,000.

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

						2004		2003
						(in thousands)
PREFERRED STOCK:
$100 Par Value Per Share - Authorized 810,000 shares
	Call Price	Number of Shares			Shares
	December 31,	Redeemed			Outstanding
Series	2004	Year Ended December 31,			December 31, 2004
		2004	2003	2002
Not Subject to Mandatory Redemption:
4.40%	$107	4	102	-	23,566	$	2,357	$	2,357

See Notes to Financial Statements of Registrant Subsidiaries.

AEP TEXAS NORTH COMPANY

SCHEDULE OF LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	45,752		$	88,236
Installment Purchase Contracts		44,310			44,310
Senior Unsecured Notes		224,295			224,208
Less Portion Due Within One Year		(37,609	)		(42,505	)
Long-term Debt Excluding Portion Due Within One Year	$	276,748		$	314,249

There are certain limitations on establishing liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
7.000	2004 - October 1	$	-		$	18,469
6.125	2004 - February 1		-			24,036
6.375	2005 - October 1		37,609			37,609
7.750	2007 - June 1		8,151			8,151
Unamortized Discount			(8	)		(29	)
Total		$	45,752		$	88,236

First Mortgage Bonds are secured by a first mortgage lien on Electric Utility Plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into, in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004		2003
	% Rate	Due	(in thousands)
Red River Authority of Texas	6.000	2020 - June 1
			$	44,310	$	44,310

Under the terms of the Installment Purchase Contracts, we are required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments are made semi-annually.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
5.500	2013 - March 1	$	225,000		$	225,000
Unamortized Discount			(705	)		(792	)
Total		$	224,295		$	224,208

At December 31, 2004, future annual Long-term Debt payments are as follows:

	Amount
	(in thousands)
2005	$	37,609
2006		-
2007		8,151
2008		-
2009		-
Later Years		269,310
Total Principal Amount		315,070
Unamortized Discount		(713	)
Total	$	314,357

AEP TEXAS NORTH COMPANY

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to TNC’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to TNC.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Jointly-Owned Electric Utility Plant	Note 18
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

AEP Texas North Company:

We have audited the accompanying balance sheets of AEP Texas North Company as of December 31, 2004 and 2003, and the related statements of operations, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of AEP Texas North Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

APPALACHIAN POWER COMPANY

AND SUBSIDIARIES

APPALACHIAN POWER COMPANY

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003		2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	1,948,182	$	1,957,358	$	1,814,470	$	1,784,259	$	1,759,253
Operating Income		244,010		318,811		302,063		274,986		201,154
Interest Charges		98,947		115,202		116,677		120,036		148,000
Income Before Extraordinary Item and     Cumulative Effect of Accounting Changes		153,115		202,783		205,492		161,818		64,906
Extraordinary Gain		-		-		-		-		8,938
Cumulative Effect of Accounting Changes,    Net of Tax		-		77,257		-		-		-
Net Income		153,115		280,040		205,492		161,818		73,844
BALANCE SHEETS DATA
Electric Utility Plant	$	6,529,630	$	6,140,931	$	5,895,303	$	5,664,657	$	5,418,278
Accumulated Depreciation and Amortization		2,443,218		2,321,360		2,330,012		2,207,072		2,103,471
Net Electric Utility Plant	$	4,086,412	$	3,819,571	$	3,565,291	$	3,457,585	$	3,314,807
Total Assets	$	5,239,918	$	4,977,011	$	4,722,442	$	4,572,194	$	6,657,920
Common Shareholder's Equity		1,409,718		1,336,987		1,166,057		1,126,701		1,096,260
Cumulative Preferred Stock  Not Subject to Mandatory Redemption
		17,784		17,784		17,790		17,790		17,790
Cumulative Preferred Stock  Subject to Mandatory Redemption (a)		-		5,360		10,860		10,860		10,860
Long-term Debt (a)		1,784,598		1,864,081		1,893,861		1,556,559		1,605,818
Obligations Under Capital Leases (a)		19,878		25,352		33,589		46,285		63,160

(a) Including portion due within one year.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

APCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 934,000 retail customers in our service territory in southwestern Virginia and southern West Virginia. We consolidate Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company, our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs. We had a new all time peak demand in December 2004, therefore we will have an increase in our MLR percentage in 2005.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

On October 1, 2004, our transmission and generation operations, commercial processes and data systems were integrated into those of PJM. While we continue to own our transmission assets, use our low-cost generation fleet to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM via the AEP Power Pool, discussed above.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in the new environment. We are confident in our ability to participate successfully in the PJM market.

To minimize the credit requirements and operating constraints when joining PJM, the AEP East Companies as well as Wheeling Power Company and Kingsport Power Company, have agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

Net Income for 2004 decreased $127 million over the prior year period largely due to the Cumulative Effect of Accounting Changes of $77 million recorded in 2003. See “Cumulative Effect of Accounting Changes” in Note 2 for further information. Net Income was also affected by an increase in expenses in the current year, primarily in Maintenance and Other Operation, coupled with a decrease in revenue. The unfavorable impacts on Net Income were partially offset by decreased Income Taxes.

Net Income for 2003 increased $75 million over the prior year period primarily due to the Cumulative Effect of Accounting Changes of $77 million recorded in 2003. Net Income was also affected by an increase in both Electric Generation, Transmission and Distribution and Sales to AEP Affiliates revenues, offset by an increase in purchased power and Fuel for Electric Generation expenses.

2004 Compared to 2003

Operating Income

Operating Income for 2004 decreased by $75 million from 2003 primarily due to:

· A $40 million increase in Maintenance expense primarily caused by boiler plant maintenance at Amos, Clinch River, Glen Lyn, Mountaineer and Kanawha River plants in 2004.

· A $24 million increase in Other Operation expense due to increased administrative and support expenses, increased insurance premiums and increased removal costs in 2004. These increases were partially offset by reduced labor costs and increased gains recorded on the dispositions of SO₂ emission allowances in 2004.

· An $18 million increase in Depreciation and Amortization related to a greater depreciable base in 2004 including the addition of capitalized software costs partially offset by reduced amortization of Virginia’s transition generation regulatory assets.

· A net $10 million increase in fuel and purchased energy expenses. Purchased energy increased $45 million due to increases in volume and price, offset by a $35 million decrease in Fuel for Electric Generation expense. The decrease in Fuel for Electric Generation expense results from accruing less fuel expense in order to match fuel revenues billed to ratepayers (See “Deferred Fuel Costs” section in Note 1).

· A $6 million decrease in Sales to AEP Affiliates resulting from decreased power available due mainly to planned plant outages.

· A $3 million decrease in Electric Generation, Transmission and Distribution revenues related to a decrease in off-system sales, including PJM transactions, offset by increased retail revenues resulting from a 28% increase in cooling degree days in the current year.

The decrease in Operating Income for 2004 was partially offset by:

· A $29 million decrease in Income Taxes. See Income Taxes section below for further discussion.

Other Impacts on Earnings

Nonoperating Income (Loss) increased $16 million in 2004 compared to 2003 primarily due to favorable results from risk management activities.

Nonoperating Income Tax Credit decreased $8 million in 2004 compared to 2003. See Income Taxes section below for further discussion.

Interest Charges decreased $16 million in 2004 compared to 2003 due to reduced interest rates from refinancing higher cost debt and increased construction-related capitalized interest.

Income Taxes

The effective tax rates for 2004 and 2003 were 35.7% and 34.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, consolidated tax savings from Parent, amortization of investment tax credits, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes of $77 million in 2003 was due to the implementation of SFAS 143 and EITF 02-3 (see “Cumulative Effect” section in Note 2).

2003 Compared to 2002

Operating Income

Operating Income for 2003 increased by $17 million from 2002 primarily due to:

· A $107 million increase in Electric Generation, Transmission and Distribution revenues related to increases in off-system sales and transmission revenues reflecting an increase in the volume of AEP Power Pool transactions as well as our relative share based on a higher MLR due to a new peak demand in January 2003.

· A $36 million increase in Sales to AEP Affiliates due to strong wholesale sales by the AEP Power Pool.

· A $24 million decrease in Other Operation expense primarily related to severance expenses of $13 million incurred in 2002 caused by the SEI initiative (see Note 9). In addition, reduced employee related expenses and insurance premiums occurred in 2003. These decreases were partially offset by an increase in transmission equalization charges due to the increase in APCo’s MLR.

· A $14 million decrease in Depreciation and Amortization expense primarily due to reduced amortization of generation-related regulatory assets due to the return to SFAS 71 for the West Virginia jurisdiction in the first quarter of 2003 (see “West Virginia Restructuring” section of Note 6).

The increase in Operating Income for 2003 was partially offset by:

· A net $150 million increase in purchased power expenses and fuel expense resulted from a $62 million increase in capacity charges caused by the increase in our MLR as described above, the increase in our relative share of the AEP Power Pool expenses and increased generation. The increase in Fuel for Electric Generation expense resulted from accruing more fuel expense in order to match fuel revenues billed to ratepayers (See “Deferred Fuel Costs” section of Note 1).

· A $13 million increase in Maintenance expense primarily due to increased maintenance of overhead lines resulting from severe storm damage in the first quarter of 2003 and increased overhead line maintenance throughout the year.

Other Impacts on Earnings

Nonoperating Income (Loss) decreased $36 million in 2003 compared to 2002 primarily due to unfavorable results from risk management activities.

Nonoperating Income Tax Credit increased $12 million in 2003 compared to 2002. See Income Taxes section below for further discussion.

Income Taxes

The effective tax rates for 2003 and 2002 were 34.2% and 35.1%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes of $77 million in 2003 was due to the implementation of SFAS 143 and EITF 02-3 (see “Cumulative Effect” section in Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	Baa1	BBB	A-
Senior Unsecured Debt	Baa2	BBB	BBB+

Cash Flow

Cash flows for 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(in thousands)
Cash and cash equivalents at beginning of period	$	4,561		$	4,133		$	7,412
Cash flows from (used for):
Operating activities		414,074			461,276			280,709
Investing activities		(408,395	)		(327,776	)		(269,376	)
Financing activities		(9,704	)		(133,072	)		(14,612	)
Net increase (decrease) in cash and cash equivalents		(4,025	)		428			(3,279	)
Cash and cash equivalents at end of period	$	536		$	4,561		$	4,133

Operating Activities

Our net cash flows from operating activities were $414 million in 2004. We produced income of $153 million during the period and noncash expense items of $194 million for Depreciation and Amortization and $48 million for Deferred Taxes. The 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 working capital had one significant item; an increase in Taxes Accrued of $40 million. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extensions are filed.

Our net cash flows from operating activities were $461 million in 2003. We produced income of $280 million during the period and had a noncash expense item of $176 million for Depreciation and Amortization as a result of increased amortization for the net generation-related regulatory assets related to WV jurisdiction that were assigned to the distribution business and are being recovered through rates. Other noncash expense items include $77 million for the Cumulative Effect of Accounting Changes due to the implementation of SFAS 143 & EITF 02-3 and $56 million of Mark-to-Market of Risk Management Contracts as a result of increased gains from risk management activities. The 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 working capital had no significant items in 2003.

Our net cash flows from operating activities were $281 million in 2002. We produced income of $205 million during the period and noncash expense items of $189 million for Depreciation and Amortization and an increase in Other Noncurrent Assets of $50 million related to an increase in regulatory assets and deferred charges. The 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 working capital had one significant item; an increase in Accounts Receivable of $83 million due to timing differences with AEP Energy Services and AEPSC.

Investing Activities

Cash flows used for investing activities during 2004, 2003, and 2002 primarily reflect our construction expenditures of $452 million, $289 million, and $277 million, respectively. Construction expenditures are primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades.In 2004, capital projects for Transmission expenditures are primarily related to the Jackson Ferry-Wyoming 765 KV line. Environmental upgrades include the installation of selective catalytic reduction (SCR) equipment on Amos Unit 2 and the flue gas desulfurization (FGD) project at the Mountaineer Plant.

Financing Activities

In 2004, we issued Senior Unsecured Notes of $125 million with a floating interest rate. We reacquired First Mortgage Bonds, Senior Unsecured Notes, and Installment Purchase Contracts of $116 million, $50 million, and $40 million, respectively, at higher stated interest rates. We also increased borrowings from the Utility Money Pool of $128 million and paid common dividends of $50 million.

In 2003, we issued two series of Senior Unsecured Notes, each in the amount of $200 million that were used to call First Mortgage Bonds, Senior Unsecured Notes and fund maturities. Additionally, we incurred obligations of $188 million in Installment Purchase Contracts to redeem higher cost Installment Purchase Contracts. In addition, we had increased borrowings from the Utility Money Pool of $44 million and paid common dividends of $128 million.

In 2002, we issued two series of Senior Unsecured Notes, one for $450 million at 4.8% and the other for $200 million at 4.3%. We reacquired First Mortgage Bonds and Junior Debentures of $150 million and $165 million, respectively. We also reduced short-term borrowing from the Utility Money Pool by $253 million and paid common dividends of $93 million.

In January 2005, we issued Senior Unsecured Notes in the amount of $200 million at a rate of 4.95%.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payments Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	530.0	$	442.5	$	350.0	$	467.0	$	1,789.5
Advances from Affiliates (b)		211.1		-		-		-		211.1
Capital Lease Obligations (c)		8.0		9.7		4.1		1.1		22.9
Noncancelable Operating Leases (c)		7.1		10.7		6.6		6.4		30.8
Fuel Purchase Contracts (d)		480.2		442.7		101.7		45.0		1,069.6
Energy and Capacity Purchase Contracts (e)		22.4		33.1		-		-		55.5
Total	$	1,258.8	$	938.7	$	462.4	$	519.5	$	3,179.4

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	Represents short-term borrowings from The Utility Money Pool.
(c)	See Note 15.
(d)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(e)	Represents contractual cash flows of energy and capacity purchase contracts.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	68,066
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(34,461	)
Fair Value of New Contracts When Entered During the Period (b)		2,520
Net Option Premiums Paid/(Received) (c)		(452	)
Change in Fair Value Due to Valuation Methodology Changes (d)		835
Changes in Fair Value of Risk Management Contracts (e)		8,492
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		9,124
Total MTM Risk Management Contract Net Assets		54,124
Net Cash Flow and Fair Value Hedge Contracts (g)		(13,817	)
DETM Assignment (h)		(23,736	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	16,571

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(h)	See “AEP East Companies” in Note 17.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	66,911		$	14,900		$	-		$	81,811
Noncurrent Assets		81,226			19			-			81,245
Total MTM Derivative Contract Assets		148,137			14,919			-			163,056
Current Liabilities		(50,214	)		(27,315	)		(11,607	)		(89,136	)
Noncurrent Liabilities		(43,799	)		(1,421	)		(12,129	)		(57,349	)
Total MTM Derivative Contract  Liabilities		(94,013	)		(28,736	)		(23,736	)		(146,485	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	54,124		$	(13,817	)	$	(23,736	)	$	16,571

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “AEP East Companies” in Note 17.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(4,720	)	$	(171	)	$	2,373		$	-	$	-	$	-	$	(2,518	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		22,364			9,087			8,016			2,879		-		-		42,346
Prices Based on Models and Other Valuation Methods (b)		(947	)		(951	)		(992	)		4,377		6,240		6,569		14,296
Total	$	16,697		$	7,965		$	9,397		$	7,256	$	6,240	$	6,569	$	54,124

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow and Fair Value Hedges.

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power			Foreign Currency			Interest Rate			Total
Beginning Balance December 31, 2003	$	359		$	(183	)	$	(1,745	)	$	(1,569	)
Changes in Fair Value (a)		3,894			-			(10,163	)		(6,269	)
Reclassifications from AOCI to Net Income (b)		(1,831	)		7			338			(1,486	)
Ending Balance December 31, 2004	$	2,422		$	(176	)	$	(11,570	)	$	(9,324	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,876 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$577	$1,883	$812	$277	$596	$2,314	$969	$230

VaR Associated with Debt Outstanding

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 $99 million and $102 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004		2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,731,619	$	1,734,565		$	1,627,993
Sales to AEP Affiliates		216,563		222,793			186,477
TOTAL		1,948,182		1,957,358			1,814,470
OPERATING EXPENSES
Fuel for Electric Generation		420,187		454,901			430,963
Purchased Energy for Resale		91,173		66,084			57,091
Purchased Electricity from AEP Affiliates		370,953		351,210			234,597
Other Operation		269,349		245,308			269,426
Maintenance		175,283		135,596			122,209
Depreciation and Amortization		193,525		175,772			189,335
Taxes Other Than Income Taxes		92,624		90,087			95,249
Income Taxes		91,078		119,589			113,537
TOTAL		1,704,172		1,638,547			1,512,407
OPERATING INCOME		244,010		318,811			302,063
Nonoperating Income (Loss)		10,742		(5,661	)		30,020
Nonoperating Expenses		8,657		9,534			12,525
Nonoperating Income Tax Credit		5,967		14,369			2,611
Interest Charges		98,947		115,202			116,677
Income Before Cumulative Effect of Accounting Changes		153,115		202,783			205,492
Cumulative Effect of Accounting Changes, Net of Tax		-		77,257			-
NET INCOME		153,115		280,040			205,492
Preferred Stock Dividend Requirements, Including Capital  Stock Expense		3,215		3,495			2,898
EARNINGS APPLICABLE TO COMMON STOCK	$	149,900	$	276,545		$	202,594

The common stock of APCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	260,458	$	715,786	$	150,797		$	(340	)	$	1,126,701
Common Stock Dividends						(92,952	)					(92,952	)
Preferred Stock Dividends						(1,442	)					(1,442	)
Capital Stock Expense				1,456		(1,456	)					-
TOTAL												1,032,307
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $861									(1,580	)		(1,580	)
Minimum Pension Liability, Net of Tax of $37,779									(70,162	)		(70,162	)
NET INCOME						205,492						205,492
TOTAL COMPREHENSIVE INCOME												133,750
DECEMBER 31, 2002		260,458		717,242		260,439			(72,082	)		1,166,057
Common Stock Dividends						(128,266	)					(128,266	)
Preferred Stock Dividends						(1,001	)					(1,001	)
Capital Stock Expense				2,494		(2,494	)					-
SFAS 71 Capitalization				163								163
TOTAL												1,036,953
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $199									351			351
Minimum Pension Liability, Net of Tax of $10,577									19,643			19,643
NET INCOME						280,040						280,040
TOTAL COMPREHENSIVE INCOME												300,034
DECEMBER 31, 2003		260,458		719,899		408,718			(52,088	)		1,336,987
Common Stock Dividends						(50,000	)					(50,000	)
Preferred Stock Dividends						(800	)					(800	)
Capital Stock Expense				2,415		(2,415	)					-
TOTAL												1,286,187
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $4,176									(7,755	)		(7,755	)
Minimum Pension Liability, Net of Tax of $11,754									(21,829	)		(21,829	)
NET INCOME						153,115						153,115
TOTAL COMPREHENSIVE INCOME												123,531
DECEMBER 31, 2004	$	260,458	$	722,314	$	508,618		$	(81,672	)	$	1,409,718

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	2,502,273		$	2,287,043
Transmission		1,255,390			1,240,889
Distribution		2,070,377			2,006,329
General		302,474			294,786
Construction Work in Progress		399,116			311,884
Total		6,529,630			6,140,931
Accumulated Depreciation and Amortization		2,443,218			2,321,360
TOTAL - NET		4,086,412			3,819,571
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		20,378			20,574
Other Investments		18,775			26,668
TOTAL		39,153			47,242
CURRENT ASSETS
Cash and Cash Equivalents		536			4,561
Other Cash Deposits		1,133			41,320
Accounts Receivable:
Customers		126,422			133,717
Affiliated Companies		140,950			137,281
Accrued Unbilled Revenues		51,427			35,020
Miscellaneous		1,264			3,961
Allowance for Uncollectible Accounts		(5,561	)		(2,085	)
Risk Management Assets		81,811			71,189
Fuel		45,756			42,806
Materials and Supplies		45,644			41,959
Margin Deposits		8,329			11,525
Prepayments and Other		12,192			13,301
TOTAL		509,903			534,555
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		343,415			325,889
Transition Regulatory Assets		25,467			30,855
Unamortized Loss on Reacquired Debt		18,157			19,005
Other		36,368			41,447
Long-term Risk Management Assets		81,245			70,900
Emission Allowances		38,931			30,019
Deferred Property Taxes		37,071			35,343
Deferred Charges and Other		23,796			22,185
TOTAL		604,450			575,643
TOTAL ASSETS	$	5,239,918		$	4,977,011

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares	$	260,458		$	260,458
Paid-in Capital		722,314			719,899
Retained Earnings		508,618			408,718
Accumulated Other Comprehensive Income (Loss)		(81,672	)		(52,088	)
Total Common Shareholder’s Equity		1,409,718			1,336,987
Cumulative Preferred Stock Not Subject to Mandatory Redemption		17,784			17,784
Total Shareholders’ Equity		1,427,502			1,354,771
Cumulative Preferred Stock Subject to Mandatory Redemption		-			5,360
Long-term Debt - Nonaffiliated		1,254,588			1,703,073
TOTAL		2,682,090			3,063,204
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		530,010			161,008
Advances from Affiliates		211,060			82,994
Accounts Payable:
General		130,710			140,497
Affiliated Companies		76,314			81,812
Risk Management Liabilities		89,136			51,430
Taxes Accrued		90,404			50,259
Interest Accrued		21,076			22,113
Customer Deposits		42,822			33,930
Obligations Under Capital Leases		6,742			9,218
Other		56,645			60,289
TOTAL		1,254,919			693,550
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		852,536			803,355
Regulatory Liabilities:
Asset Removal Costs		95,763			92,497
Over-recovery of Fuel Cost		57,843			68,704
Deferred Investment Tax Credits		30,382			30,545
Other		23,270			17,326
Employee Benefits and Pension Obligations		130,530			102,463
Long-term Risk Management Liabilities		57,349			54,327
Asset Retirement Obligations		24,626			21,776
Obligations Under Capital Leases		13,136			16,134
Deferred Credits		17,474			13,130
TOTAL		1,302,909			1,220,257
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,239,918		$	4,977,011

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	153,115		$	280,040		$	205,492
Adjustments to Reconcile Net Income to Net Cash  Flows From   Operating Activities:
Cumulative Effect of Accounting Changes		-			(77,257	)		-
Depreciation and Amortization		193,525			175,772			189,335
Deferred Income Taxes		47,585			24,563			16,777
Deferred Investment Tax Credits		(163	)		(3,146	)		(4,637	)
Deferred Property Taxes		(1,728	)		(20	)		(1,897	)
Over/Under Fuel Recovery		(10,861	)		74,071			6,365
Mark-to-Market of Risk Management Contracts		5,391			56,409			(21,151	)
Change in Other Noncurrent Assets		(16,474	)		(12,333	)		(50,236	)
Change in Other Noncurrent Liabilities		26,026			31,753			(5,233	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(6,608	)		(6,825	)		(83,453	)
Fuel, Materials and Supplies		(6,635	)		4,717			11,016
Accounts Payable		(15,285	)		(17,611	)		27,805
Taxes Accrued		40,145			21,078			(26,402	)
Customer Deposits		8,892			7,744			13,008
Interest Accrued		(1,037	)		(324	)		667
Other Current Assets		4,303			(11,429	)		2,510
Other Current Liabilities		(6,117	)		(10,325	)		743
Rate Stabilization Deferral		-			(75,601	)		-
Net Cash Flows From Operating Activities		414,074			461,276			280,709
INVESTING ACTIVITIES
Construction Expenditures		(452,173	)		(288,800	)		(276,549	)
Change in Other Cash Deposits, Net		40,187			(41,168	)		6,099
Proceeds from Sale of Assets		3,591			2,192			-
Other		-			-			1,074
Net Cash Flows Used For Investing Activities		(408,395	)		(327,776	)		(269,376	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		124,398			580,649			647,401
Issuance of Long-term Debt - Affiliated		-			-			-
Retirement of Long-term Debt		(206,008	)		(622,737	)		(315,007	)
Retirement of Preferred Stock		(5,360	)		(5,506	)		-
Change in Short-term Debt, Net		-			-			-
Change in Advances to/from Affiliates, Net		128,066			43,789			(252,612	)
Dividends Paid on Common Stock		(50,000	)		(128,266	)		(92,952	)
Dividends Paid on Cumulative Preferred Stock		(800	)		(1,001	)		(1,442	)
Net Cash Flows Used For Financing Activities		(9,704	)		(133,072	)		(14,612	)
Net Increase (Decrease) in Cash and Cash Equivalents		(4,025	)		428			(3,279	)
Cash and Cash Equivalents at Beginning of Period		4,561			4,133			7,412
Cash and Cash Equivalents at End of Period	$	536		$	4,561		$	4,133

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $92,773,000, $108,045,000 and $111,528,000 and for income taxes was $(831,000), $62,673,000 and $125,120,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $3,791,000.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

						2004		2003
						(in thousands)
PREFERRED STOCK:
No Par Value - Authorized 8,000,000 shares
	Call Price	Number of Shares			Shares
	December 31,	Redeemed			Outstanding
Series	2004 (a)	Year Ended December 31,			December 31, 2004
		2004	2003	2002
Not Subject to Mandatory Redemption - $100 Par:
4.50%	$110	3	60	6	177,836	$	17,784	$	17,784
Subject to Mandatory Redemption - $100 Par (b):
5.90%		22,100	25,000	-	-		-		2,210
5.92%		31,500	30,000	-	-		-		3,150
Total						$	-	$	5,360

(a)	The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is $100 per share. The aggregate involuntary liquidation price for all shares of cumulative preferred stock may not exceed $300 million. The unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance.
(b)	The sinking fund provisions of each series subject to mandatory redemption have been met by shares purchased in advance of the due date.

See Notes to Financial Statements of Registrant Subsidiaries.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	224,662		$	340,269
Installment Purchase Contracts		236,759			276,477
Senior Unsecured Notes		1,320,663			1,244,813
Other Long-term Debt		2,514			2,522
Less Portion Due Within One Year		(530,010	)		(161,008	)
Long-term Debt Excluding Portion Due Within One Year	$	1,254,588		$	1,703,073

There are certain limitations on establishing liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
7.700	2004 - September 1	$	-		$	21,000
7.850	2004 - November 1		-			50,000
8.000	2005 - May 1		50,000			50,000
6.890	2005 - June 22		30,000			30,000
6.800	2006 - March 1		100,000			100,000
7.125	2024 - May 1		-			45,000
8.000	2025 - June 1		45,000			45,000
Unamortized Discount			(338	)		(731	)
Total		$	224,662		$	340,269

First Mortgage Bonds are secured by a first mortgage lien on Electric Utility Plant. Certain supplemental indentures to the first mortgage lien contain maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.

Installment Purchase Contracts have been entered into, in connection with the issuance of pollution control revenue bonds, by governmental authorities as follows:

			2004			2003
	% Rate	Due	(in thousands)
Industrial Development Authority	(a)	2007 - November 1	$	17,500		$	17,500
of Russell County, Virginia	5.000	2021 - November 1		19,500			19,500
Putnam County, West Virginia	(b)	2019 - June 1		40,000			40,000
	5.450	2019 - June 1		-			40,000
	(c)	2019 - May 1		30,000			30,000
Mason County, West Virginia	6.050	2024 - December 1		30,000			30,000
	5.500	2022 - October 1		100,000			100,000
	Unamortized Discount			(241	)		(523	)
	Total		$	236,759		$	276,477

(a)	Rate is an annual long-term fixed rate of 2.70% through November 1, 2006. After that date the rate may be daily, weekly, commercial paper, auction or other long-term rate as designated by us (fixed rate bonds).
(b)	In December 2003, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The rate on December 31, 2004 was 1.85%.
(c)	Rate is an annual long-term fixed rate of 2.80% through November 1, 2006. After that date the rate may be daily, weekly, commercial paper, auction or other long-term rate as designated by us (fixed rate bonds).

Under the terms of the installment purchase contracts, we are required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
7.450	2004 - November 1	$	-		$	50,000
4.800	2005 - June 15		450,000			450,000
4.320	2007 - November 12		200,000			200,000
3.600	2008 - May 15		200,000			200,000
6.600	2009 - May 1		150,000			150,000
5.950	2033 - May 15		200,000			200,000
(a)	2007 - June 29		125,000			-
Unamortized Discount			(4,337	)		(5,187	)
Total		$	1,320,663		$	1,244,813

(a) Floating rate determined quarterly. The rate at December 31, 2004 was 2.88%.

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	530,010
2006		100,011
2007		342,513
2008		200,014
2009		150,017
Later Years		466,949
Total Principal Amount		1,789,514
Unamortized Discount		(4,916	)
Total	$	1,784,598

APPALACHIAN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to APCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Appalachian Power Company:

We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” and EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

COLUMBUS SOUTHERN POWER COMPANY

AND SUBSIDIARIES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003		2002		2001			2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	1,433,581	$	1,431,851	$	1,400,160	$	1,350,319		$	1,304,409
Operating Income		184,246		225,486		219,779		252,177			195,877
Interest Charges		54,246		50,948		53,869		68,015			80,828
Income Before Extraordinary Item and Cumulative Effect   of Accounting Changes		140,258		173,147		181,173		191,900			120,202
Extraordinary Loss, Net of Tax		-		-		-		(30,024	)		(25,236	)
Cumulative Effect of Accounting Changes, Net of Tax		-		27,283		-		-			-
Net Income		140,258		200,430		181,173		161,876			94,966
BALANCE SHEETS DATA
Electric Utility Plant	$	3,691,246	$	3,570,443	$	3,467,626	$	3,354,320		$	3,266,794
Accumulated Depreciation and Amortization		1,471,950		1,389,586		1,369,153		1,283,712			1,211,728
Net Electric Utility Plant	$	2,219,296	$	2,180,857	$	2,098,473	$	2,070,608		$	2,055,066
TOTAL ASSETS	$	3,029,896	$	2,838,366	$	2,849,261	$	2,815,708		$	3,965,460
Common Shareholder's Equity		898,650		897,881		847,664		791,498			713,449
Cumulative Preferred Stock Subject to   Mandatory Redemption (a)		-		-		-		10,000			15,000
Long-term Debt (a)		987,626		897,564		621,626		791,848			899,615
Obligations Under Capital Leases (a)		12,514		15,618		27,610		34,887			42,932

(a) Including portion due within one year.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

CSPCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 707,000 retail customers in central and southern Ohio. We consolidate Colomet, Inc., Conesville Coal Preparation Company and Simco, Inc., our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

On October 1, 2004, our transmission and generation operations, commercial processes and data systems were integrated into those of PJM. While we continue to own our transmission assets, use our low-cost generation fleet to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM via the AEP Power Pool, discussed above.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in the new environment. We are confident in our ability to participate successfully in the PJM market.

To minimize the credit requirements and operating constraints when joining PJM, the AEP East Companies as well as Wheeling Power Company and Kingsport Power Company, have agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

2004 Compared to 2003

During 2004, Net Income decreased by $60 million primarily due to a $27 million net of tax Cumulative Effect of Accounting Changes recorded in 2003, an $18 million increase in purchased power expenses and $14 million in expenses resulting from a December 2004 ice storm.

Operating Income

Operating Income decreased by $41 million primarily due to:

· A $22 million decrease in nonaffiliated wholesale energy sales and related transmission services due to lower sales volume and the expiration of municipal contracts.

· A $20 million increase in Maintenance expense primarily associated with costs incurred as a result of a major ice storm in late December 2004 and boiler overhaul work from scheduled and forced outages.

· An $18 million increase in purchased power expenses primarily due to increased purchases from the AEP Power Pool and PJM regional transmission authority.

· A $13 million increase in Depreciation and Amortization expense due to a greater depreciable base in 2004, including capitalized software costs and the increased amortization of transition generation regulatory assets due to normal operating adjustments.

· A $9 million increase in Other Operation expense primarily relating to pension plan costs, steam removal costs and administrative and support expenses, partially offset by increased gains on the disposition of emission allowances.

· A $2 million decrease in affiliated wholesale energy sales due to lower sales volume.

The decrease in Operating Income was partially offset by:

· A $21 million increase in retail electric revenues resulting primarily from increased weather-related demand from residential and commercial customers during the second quarter of 2004.

· A $15 million decrease in Income Taxes expense.  See Income Taxes section below for further discussion.

· A $9 million increase in operating revenues related to favorable results from risk management activities.

Other Impacts on Earnings

Nonoperating Income (Loss) increased $18 million primarily due to favorable results from risk management activities.

Nonoperating Income Tax Expense (Credit) increased $9 million. See Income Taxes section below for further discussion.

Income Taxes

The effective tax rates for 2004 and 2003 were 32.5% and 29.8%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to higher state income taxes, lower consolidated tax savings from Parent, and less favorable income tax adjustments.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time, after tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	A3	BBB	A-

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	36.0	$	-	$	112.0	$	842.2	$	990.2
Advances to Affiliates (b)		141.6		-		-		-		141.6
Capital Lease Obligations (c)		4.5		5.3		3.2		1.0		14.0
Noncancelable Operating Leases (c)		5.7		5.9		3.8		3.2		18.6
Fuel Purchase Contracts (d)		135.8		198.1		55.3		-		389.2
Energy and Capacity Purchase Contracts (e)		11.4		17.0		-		-		28.4
Total	$	335.0	$	226.3	$	174.3	$	846.4	$	1,582.0

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	Represents short-term borrowings from the Utility Money Pool.
(c)	See Note 15.
(d)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(e)	Represents contractual cash flows of energy and capacity purchase contracts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2004 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	-	$	44.1	$	-	$	-	$	44.1

(a) We have issued standby letters of credit to third parties. These letters of credit cover debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $44.1 million maturing in April 2007. There is no recourse to third parties in the event these letters of credit are drawn.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	38,337
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(19,805	)
Fair Value of New Contracts When Entered During the Period (b)		2,493
Net Option Premiums Paid/(Received) (c)		(260	)
Change in Fair Value Due to Valuation Methodology Changes (d)		898
Changes in Fair Value of Risk Management Contracts (e)		9,256
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		-
Total MTM Risk Management Contract Net Assets		30,919
Net Cash Flow Hedge Contracts (g)		1,198
DETM Assignment (h)		(13,654	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	18,463

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(h)	See “AEP East Companies” in Note 17.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	38,275		$	8,356		$	-		$	46,631
Noncurrent Assets		46,724			11			-			46,735
Total MTM Derivative Contract Assets		84,999			8,367			-			93,366
Current Liabilities		(28,885	)		(6,610	)		(6,677	)		(42,172	)
Noncurrent Liabilities		(25,195	)		(559	)		(6,977	)		(32,731	)
Total MTM Derivative Contract  Liabilities		(54,080	)		(7,169	)		(13,654	)		(74,903	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	30,919		$	1,198		$	(13,654	)	$	18,463

(a)	Does not include Cash Flow Hedges.
(b)	See “AEP East Companies” in Note 17.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(2,715	)	$	(98	)	$	1,365		$	-	$	-	$	-	$	(1,448	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		12,650			5,227			4,611			1,656		-		-		24,144
Prices Based on Models and Other Valuation Methods (b)		(545	)		(548	)		(571	)		2,518		3,590		3,779		8,223
Total	$	9,390		$	4,581		$	5,405		$	4,174	$	3,590	$	3,779	$	30,919

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges.

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

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

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power
Beginning Balance December 31, 2003	$	202
Changes in Fair Value (a)		2,304
Reclassifications from AOCI to Net Income (b)		(1,113	)
Ending Balance December 31, 2004	$	1,393

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,750 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Energy and Gas Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$332	$1,083	$467	$160	$336	$1,303	$546	$130

VaR Associated with Debt Outstanding

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 $48 million and $98 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,353,466		$	1,347,482		$	1,342,958
Sales to AEP Affiliates		80,115			84,369			57,202
TOTAL		1,433,581			1,431,851			1,400,160
OPERATING EXPENSES
Fuel for Electric Generation		191,578			176,071			157,569
Fuel From Affiliates for Electric Generation		10,603			27,328			27,517
Purchased Energy for Resale		26,267			17,730			15,023
Purchased Electricity from AEP Affiliates		347,002			337,323			310,605
Other Operation		227,112			218,466			237,802
Maintenance		95,036			75,319			60,003
Depreciation and Amortization		148,529			135,964			131,624
Taxes Other Than Income Taxes		133,840			133,754			136,024
Income Taxes		69,368			84,410			104,214
TOTAL		1,249,335			1,206,365			1,180,381
OPERATING INCOME		184,246			225,486			219,779
Nonoperating Income (Loss)		10,341			(7,489	)		28,280
Nonoperating Expenses		1,780			4,650			6,228
Nonoperating Income Tax Expense (Credit)		(1,697	)		(10,748	)		6,789
Interest Charges		54,246			50,948			53,869
Income Before Cumulative Effect of Accounting Changes		140,258			173,147			181,173
Cumulative Effect of Accounting Changes, Net of Tax		-			27,283			-
NET INCOME		140,258			200,430			181,173
Preferred Stock Dividend Requirements including Capital Stock Expense		1,015			1,016			1,365
EARNINGS APPLICABLE TO COMMON STOCK	$	139,243		$	199,414		$	179,808

The common stock of CSPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	41,026	$	574,369	$	176,103		$	-		$	791,498
Common Stock Dividends						(65,300	)					(65,300	)
Preferred Stock Dividends						(350	)					(350	)
Capital Stock Expense				1,015		(1,015	)					-
TOTAL												725,848
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $144									(267	)		(267	)
Minimum Pension Liability, Net of Tax of $31,818									(59,090	)		(59,090	)
NET INCOME						181,173						181,173
TOTAL COMPREHENSIVE INCOME												121,816
DECEMBER 31, 2002		41,026		575,384		290,611			(59,357	)		847,664
Common Stock Dividends						(163,243	)					(163,243	)
Capital Stock Expense				1,016		(1,016	)					-
TOTAL												684,421
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $253									469			469
Minimum Pension Liability, Net of Tax of $6,763									12,561			12,561
NET INCOME						200,430						200,430
TOTAL COMPREHENSIVE INCOME												213,460
DECEMBER 31, 2003		41,026		576,400		326,782			(46,327	)		897,881
Common Stock Dividends						(125,000	)					(125,000	)
Capital Stock Expense				1,015		(1,015	)					-
TOTAL												772,881
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $641									1,191			1,191
Minimum Pension Liability, Net of Tax of $8,443									(15,680	)		(15,680	)
NET INCOME						140,258						140,258
TOTAL COMPREHENSIVE INCOME												125,769
DECEMBER 31, 2004	$	41,026	$	577,415	$	341,025		$	(60,816	)	$	898,650

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	1,658,552		$	1,610,888
Transmission		432,714			425,512
Distribution		1,300,252			1,253,760
General		167,985			166,002
Construction Work in Progress		131,743			114,281
Total		3,691,246			3,570,443
Accumulated Depreciation and Amortization		1,471,950			1,389,586
TOTAL - NET		2,219,296			2,180,857
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		22,322			22,417
Other Investments		5,147			8,663
TOTAL		27,469			31,080
CURRENT ASSETS
Cash and Cash Equivalents		25			3,377
Other Cash Deposits		33			765
Advances to Affiliates		141,550			-
Accounts Receivable:
Customers		41,130			47,099
Affiliated Companies		72,854			68,168
Accrued Unbilled Revenues		19,580			23,723
Miscellaneous		1,145			5,257
Allowance for Uncollectible Accounts		(674	)		(531	)
Fuel		34,026			14,365
Materials and Supplies		37,137			26,102
Risk Management Assets		46,631			40,095
Margin Deposits		4,848			6,636
Prepayments and Other		11,499			12,444
TOTAL		409,784			247,500
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		16,481			16,027
Transition Regulatory Assets		156,676			188,532
Unamortized Loss on Reacquired Debt		13,155			13,659
Other		25,691			24,966
Long-term Risk Management Assets		46,735			39,932
Deferred Property Taxes		64,754			62,262
Deferred Charges and Other		49,855			33,551
TOTAL		373,347			378,929
TOTAL ASSETS	$	3,029,896		$	2,838,366

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares	$	41,026		$	41,026
Paid-in Capital		577,415			576,400
Retained Earnings		341,025			326,782
Accumulated Other Comprehensive Income (Loss)		(60,816	)		(46,327	)
Total Common Shareholder’s Equity		898,650			897,881
Preferred Stock - No Shares Outstanding		-			-
Authorized - 2,500,000 Shares at $100 Par Value
Authorized - 7,000,000 Shares at $25 Par Value
Total Shareholder’s Equity		898,650			897,881
Long-term Debt:
Nonaffiliated		851,626			886,564
Affiliated		100,000			-
Total Long-term Debt		951,626			886,564
TOTAL		1,850,276			1,784,445
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		36,000			11,000
Advances from Affiliates, Net		-			6,517
Accounts Payable:
General		63,606			58,220
Affiliated Companies		45,745			53,572
Customer Deposits		24,890			19,727
Taxes Accrued		195,284			132,853
Interest Accrued		16,320			16,528
Risk Management Liabilities		42,172			28,966
Obligations Under Capital Leases		3,854			4,221
Other		24,338			25,364
TOTAL		452,209			356,968
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		464,545			458,498
Regulatory Liabilities:
Asset Removal Costs		103,104			99,119
Deferred Investment Tax Credits		27,933			30,797
Employee Benefits and Pension Obligations		62,778			40,341
Long-term Risk Management Liabilities		32,731			30,598
Obligations Under Capital Leases		8,660			11,397
Asset Retirement Obligations		11,585			8,740
Deferred Credits and Other		16,075			17,463
TOTAL		727,411			696,953
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	3,029,896		$	2,838,366

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	140,258		$	200,430		$	181,173
Adjustments to Reconcile Net Income to Net Cash Flows From   Operating Activities:
Cumulative Effect of Accounting Changes		-			(27,283	)		-
Depreciation and Amortization		148,529			135,964			131,753
Deferred Income Taxes		13,395			(4,514	)		23,292
Deferred Investment Tax Credits		(2,864	)		(3,110	)		(3,270	)
Deferred Property Tax		(2,492	)		(529	)		(13,732	)
Mark-to-Market of Risk Management Contracts		2,887			41,830			(16,667	)
Change in Other Noncurrent Assets		(18,591	)		(12,162	)		(19,747	)
Change in Other Noncurrent Liabilities		2,351			(21,286	)		(17,303	)
Changes in Components of Working Capital:
Accounts Receivable, Net		9,681			(5,590	)		(9,576	)
Fuel, Materials and Supplies		(30,696	)		9,812			(1,002	)
Accounts Payable		(2,441	)		(59,543	)		26,949
Taxes Accrued		62,431			20,681			(4,192	)
Interest Accrued		(208	)		6,730			(1,108	)
Customer Deposits		5,163			5,009			8,834
Other Current Assets		2,731			(11,770	)		21,426
Other Current Liabilities		(1,394	)		7,514			(9,829	)
Net Cash Flows From Operating Activities		328,740			282,183			297,001
INVESTING ACTIVITIES
Construction Expenditures		(149,788	)		(136,291	)		(136,800	)
Change in Other Cash Deposits, Net		732			16			58
Proceeds from Sale of Assets		3,393			1,644			730
Net Cash Flows Used For Investing Activities		(145,663	)		(134,631	)		(136,012	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Affiliated		100,000			-			160,000
Issuance of Long-term Debt - Nonaffiliated		89,883			643,097			-
Change in Advances to/from Affiliates, Net		(148,067	)		37,774			(212,641	)
Retirement of Long-term Debt - Nonaffiliated		(103,245	)		(212,500	)		(133,343	)
Retirement of Long-term Debt - Affiliated		-			(160,000	)		(200,000	)
Retirement of Cumulative Preferred Stock		-			-			(10,000	)
Change in Short-term Debt - Affiliates		-			(290,000	)		290,000
Dividends Paid on Common Stock		(125,000	)		(163,243	)		(65,300	)
Dividends Paid on Cumulative Preferred Stock		-			-			(525	)
Net Cash Flows Used For Financing Activities		(186,429	)		(144,872	)		(171,809	)
Net Increase (Decrease) in Cash and Cash Equivalents		(3,352	)		2,680			(10,820	)
Cash and Cash Equivalents at Beginning of Period		3,377			697			11,517
Cash and Cash Equivalents at End of Period	$	25		$	3,377		$	697

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $48,461,000, $42,601,000 and $53,514,000 and for income taxes was $(5,281,756), $63,907,000 and $117,591,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $1,302,000. There were no noncash capital lease acquisitions in 2003 or 2002.

See Notes to Financial Statements of Registrant Subsidiaries.

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	-		$	10,944
Installment Purchase Contracts		92,077			91,329
Senior Unsecured Notes		795,549			795,291
Notes Payable - Affiliated		100,000			-
Less Portion Due Within One Year		(36,000	)		(11,000	)
Long-term Debt Excluding Portion Due Within One Year	$	951,626		$	886,564

There are certain limitations on establishing additional liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

			2004		2003
% Rate		Due	(in thousands)
7.60		2024 - May 1	$	-	$	11,000
	Unamortized Discount			-		(56	)
	Total		$	-	$	10,944

Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by the Ohio Air Quality Development Authority:

			2004			2003
% Rate		Due	(in thousands)
6.375		2020 - December 1	$	-		$	48,550
6.250		2020 - December 1		-			43,695
(a)		2038 - December 1		43,695			-
(b)		2038 - December 1		48,550			-
	Unamortized Discount			(168	)		(916	)
	Total		$	92,077		$	91,329

(a)	A floating interest rate is determined weekly and paid monthly. The rate on December 31, 2004 was 2.00%. The bonds would be subject to mandatory tender on April 27, 2007 if the letter of credit backing this issuance were not renewed at that time or if the current letter of credit provider were replaced by a new provider.
(b)	In 2004, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2004 ranged from 1.05% to 1.75% and averaged 1.50%. The rate on December 31, 2004 was 1.75%. Interest payments are made every 35 days.

Under the terms of the Installment Purchase Contracts, we are required to pay amounts sufficient to enable the payment of interest on and the principal of related pollution control revenue bonds (at stated maturities and upon mandatory redemptions) issued to finance the construction of pollution control facilities at the Zimmer Plant.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
6.850	2005 - October 3	$	36,000		$	36,000
6.510	2008 - February 1		52,000			52,000
6.550	2008 - June 26		60,000			60,000
4.400	2010 - December 1		150,000			150,000
5.500	2013 - March 1		250,000			250,000
6.600	2033 - March 1		250,000			250,000
Unamortized Discount			(2,451	)		(2,709	)
Total		$	795,549		$	795,291

Notes Payable to Parent were as follows:

		2004		2003
% Rate	Due	(in thousands)
4.64	2010 - March 15	$	100,000	$	-

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	36,000
2006		-
2007		-
2008		112,000
2009		-
Later Years		842,245
Total Principal Amount		990,245
Unamortized Discount		(2,619	)
Total	$	987,626

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to CSPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Jointly-Owned Electric Utility Plant	Note 18
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Columbus Southern Power Company:

We have audited the accompanying consolidated balance sheets of Columbus Southern Power Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” and EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

INDIANA MICHIGAN POWER COMPANY

AND SUBSIDIARIES

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003			2002		2001		2000
STATEMENTS OF OPERATIONS DATA
Operating Revenues	$	1,661,580	$	1,595,596		$	1,526,764	$	1,526,997	$	1,488,209
Operating Income (Loss)		195,888		186,067			151,189		159,705		(34,702	)
Interest Charges		69,071		83,054			93,923		93,647		107,263
Net Income (Loss) Before Cumulative Effect of   Accounting Change		133,222		89,548			73,992		75,788		(132,032	)
Cumulative Effect of Accounting Change,   Net of Tax		-		(3,160	)		-		-		-
Net Income (Loss)		133,222		86,388			73,992		75,788		(132,032	)
BALANCE SHEETS DATA
Electric Utility Plant	$	5,562,397	$	5,306,182		$	5,029,958	$	4,923,721	$	4,871,473
Accumulated Depreciation and Amortization		2,603,479		2,490,912			2,318,063		2,198,524		2,057,542
Net Electric Utility Plant	$	2,958,918	$	2,815,270		$	2,711,895	$	2,725,197	$	2,813,931
Total Assets	$	4,868,141	$	4,659,071		$	4,837,732	$	4,632,510	$	5,997,087
Common Shareholder’s Equity		1,091,498		1,078,047			1,018,653		860,570		793,099
Cumulative Preferred Stock Not Subject to   Mandatory Redemption		8,084		8,101			8,101		8,736		8,736
Cumulative Preferred Stock Subject to   Mandatory Redemption (a)		61,445		63,445			64,945		64,945		64,945
Long-term Debt (a)		1,312,843		1,339,359			1,617,062		1,652,082		1,388,939
Obligations Under Capital Leases (a)		50,732		37,843			50,848		61,933		163,173

(a) Including portion due within one year.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

We are a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 579,000 retail customers in our service territory in northern and eastern Indiana and a portion of southwestern Michigan. We consolidate Blackhawk Coal Company and Price River Coal Company, our wholly-owned subsidiaries. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities and electric cooperatives.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of each year. In 2002, the capacity based allocation mechanism was not triggered.

On October 1, 2004, our transmission and generation operations, commercial processes and data systems were integrated into those of PJM. While we continue to own our transmission assets, use our low-cost generation fleet to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM via the AEP Power Pool, discussed above.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in the new environment. We are confident in our ability to participate successfully in the PJM market.

To minimize the credit requirements and operating constraints when joining PJM, the AEP East companies as well as Wheeling Power Company and Kingsport Power Company, have agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

During 2004, Net Income increased $47 million as gross margin (revenues less the cost of fuel and purchased energy) increased $26 million and interest charges declined $14 million. The improvement in gross margin reflects increased retail sales and the end of amortization for the Cook Plant outage settlements.

During 2003, Net Income increased $12 million including an unfavorable $3 million Cumulative Effect of Accounting Change (see “Cumulative Effect of Accounting Change” section of Note 2). During 2003, Net Income Before Cumulative Effect of Accounting Change increased $15 million due to reduced financing costs and an improvement in Operating Income resulting from higher margins on wholesale sales and lower Other Operation expenses.

2004 Compared to 2003

Operating Income increased $10 million primarily due to:

· A $54 million increase in Electric Generation, Transmission and Distribution revenues due to an increase in commercial and industrial sales reflecting the economic recovery and the end of amortization of Cook Plant outage settlements and an increase in revenues from coal trading sales.

· A $14 million decrease in Other Operation expenses primarily due to the end of amortization of Cook Plant outage settlements.

· A $12 million increase in Sales to AEP Affiliates reflecting increased availability of the Cook Plant units.

· A $2 million decrease in Purchased Electricity from AEP Affiliates primarily due to an increase in net generation of 11% that reduced our need to purchase power from affiliates.

The increase in Operating Income was partially offset by:

· A $29 million increase in Fuel for Electric Generation expenses reflecting an increase in total generation of 11%.

· A $19 million increase in Income Taxes expense. See Income Taxes section below for further discussion.

· A $14 million increase in Purchased Energy for Resale expenses reflecting new costs related to PJM membership and coal trading purchases under procurement contracts.

· A $10 million increase in Maintenance expenses primarily due to increased maintenance expenses at the Cook Plant and increased costs for distribution right of way, line maintenance and storm damage repair.

Other Impacts on Earnings

Nonoperating Income increased $25 million primarily due to favorable results from risk management activities and increased barging revenues.

Nonoperating Expenses decreased $6 million primarily due to a $10 million write-down in 2003 of western coal lands (see “Blackhawk Coal Company” section of Note 10).

Nonoperating Income Tax Expense increased $11 million. See Income Taxes section below for further discussion.

Interest Charges decreased $14 million primarily due to a reduction in outstanding long-term debt and lower interest rates from refunding higher cost debt.

Income Taxes

The effective tax rates for 2004 and 2003 were 35% and 31.5%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is due primarily to changes in flow-through of book versus tax temporary differences and an increase in state income taxes.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change of $3 million in the prior year is due to the implementation of the requirements of EITF 02-3 related to mark-to-market accounting for risk management contracts that are not derivatives (see “Cumulative Effect of Accounting Change” section of Note 2).

2003 Compared to 2002

Operating Income

Operating Income increased $35 million primarily due to:

· A $69 million increase in wholesale sales including system and power optimization sales, transmission revenues and risk management activities reflecting availability of AEP’s generation and market conditions.

· A $45 million decrease in Other Operation expenses primarily due to the impact of cost reduction efforts instituted in the fourth quarter of 2002 and related employment termination benefits of $15 million recorded in 2002.

· A $35 million increase in Sales to AEP Affiliates due to increased capacity revenue.

The increase in Operating Income was partially offset by:

· A $41 million increase in Purchased Electricity from AEP Affiliates due to purchasing more power from the AEP Power Pool to support wholesale sales to nonaffiliated entities.

· A $37 million decrease in retail revenues primarily due to milder summer weather and economic pressures on industrial customers. Cooling degree days declined approximately 42% this year compared with last year. Industrial revenues declined 3% from prior year.

· A $12 million increase in Income Taxes expense. See Income Taxes section below for further discussion.

· An $11 million increase in Fuel for Electric Generation expense reflecting an increase in the average cost of fuel and increased coal-fired generation in 2003 as Rockport’s availability increased.

Other Impacts on Earnings

Nonoperating Income decreased $30 million primarily due to lower margins for power sold outside of AEP’s traditional market reflecting AEP’s plan to exit those risk management activities.

Nonoperating Expenses increased $16 million primarily due to a $10 million write-down of western coal lands (see “Blackhawk Coal Company” section of Note 10).

Nononperating Income Tax Expense decreased $16 million. See Income Taxes section below for further discussion.

Interest Charges decreased $11 million primarily due to a reduction in outstanding long-term debt of $255 million which was retired in May 2003 using lower rate short-term debt.

Income Taxes

The effective tax rates for 2003 and 2002 were 31.5% and 37.7%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is due primarily to changes in flow-through of book versus tax temporary differences and federal income tax adjustments, offset, in part, by an increase in state income taxes.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change of $3 million in 2003 is due to the implementation of the requirements of EITF 02-3 (see “Cumulative Effect of Accounting Change ” section of Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings, unchanged since first quarter of 2003, are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa2	BBB	BBB

Cash Flow

Cash flows for 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(in thousands)
Cash and cash equivalents at beginning of period	$	3,899		$	3,250		$	6,705
Cash flows from (used for):
Operating activities		412,123			222,821			228,234
Investing activities		(174,038	)		(182,779	)		(155,613	)
Financing activities		(241,519	)		(39,393	)		(76,076	)
Net increase (decrease) in cash and cash equivalents		(3,434	)		649			(3,455	)
Cash and cash equivalents at end of period	$	465		$	3,899		$	3,250

Operating Activities

Our net cash flows from operating activities were $412 million in 2004. We produced Net Income of $133 million during the period and noncash expense items of $172 million for Depreciation and Amortization. The 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 working capital relates to a number of items; the most significant relates to Taxes Accrued. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP Consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extension is filed.

Our net cash flows from operating activities were $223 million in 2003. We produced Net Income of $86 million during the period and noncash expense items of $171 million for Depreciation and Amortization and $78 million for the Cook Plant outage settlement agreements. The other changes in assets and liabilities represents 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 working capital relates to a number of items; the most significant was a $35 million change in net accounts receivable/payable related to the timing of settlements with our affiliates and $29 million related to Taxes Accrued related to the timing of estimated federal income tax payments.

Our net cash flows from operating activities were $228 million in 2002. We produced Net Income of $74 million during the period and noncash expense items of $168 million for Depreciation and Amortization and $78 million for the Cook Plant outage settlement amortization. The other changes in assets and liabilities represents 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 working capital relates to a number of items; the most significant was a $19 million change in net accounts receivable/payable related to the timing of settlements with our affiliates.

Investing Activities

Cash flows used for investing activities during 2004, 2003 and 2002 primarily reflect our construction expenditures of $177 million, $185 million and $167 million, respectively. Construction expenditures for the nuclear plant and transmission and distribution assets are to upgrade or replace equipment and improve reliability. In 2004, we also invested in capital projects to improve air quality and water intake systems.

Financing Activities

Our cash flows used for financing activities were $242 million in 2004. We used cash from operations to repay short-term debt and pay common dividends. In 2004, we issued $175 million in senior unsecured notes and refunded $97 million in fixed rate installment purchase contracts and reissued at variable rate.

Financing activities for 2003 used $39 million of cash from operations primarily to pay common dividends. During 2003, we redeemed $285 million of long-term debt using short-term debt and refinanced $65 million of our installment purchase contracts at a lower fixed rate through October 2006.

During 2002, we redeemed $340 million of long-term debt and $145 million of short-term debt using cash from operations, a $125 million capital contribution from our Parent and proceeds from the issuance of $289 million of long-term debt.

In January 2005, we redeemed $61 million Cumulative Preferred Stock Subject to Mandatory Redemption.

Off-Balance Sheet Arrangements

In prior years, we entered into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading risk of loss to third parties. The following identifies significant off-balance sheet arrangements:

Rockport Plant Unit 2

In 1989, AEGCo and I&M entered into a sale and leaseback transaction with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (Rockport 2). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and certain institutional investors. The future minimum lease payments for each company are $1.3 billion.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns Rockport 2 and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the lease footnote. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell Rockport 2. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of these entities guarantee its debt.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	-	$	415.0	$	95.0	$	805.9	$	1,315.9
Preferred Stock Subject to Mandatory  Redemption (b)		61.4		-		-		-		61.4
Capital Lease Obligations (c)		8.4		11.6		11.1		25.3		56.4
Noncancelable Operating Leases (c)		104.0		195.2		190.2		1,019.6		1,509.0
Fuel Purchase Contracts (d)		212.1		393.8		264.0		336.3		1,206.2
Energy and Capacity Purchase Contracts (e)		12.8		19.0		-		-		31.8
Total	$	398.7	$	1,034.6	$	560.3	$	2,187.1	$	4,180.7

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	See Schedule of Preferred Stock.
(c)	See Note 15. The lease of Rockport 2 is reported in Noncancelable Operating Leases.
(d)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(e)	Represents contractual cash flows of energy and capacity purchase contracts.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	41,995
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(15,476	)
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(291	)
Change in Fair Value Due to Valuation Methodology Changes (d)		-
Changes in Fair Value of Risk Management Contracts (e)		1,668
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		6,677
Total MTM Risk Management Contract Net Assets		34,573
Net Cash Flow and Fair Value Hedge Contracts (g)		1,101
DETM Assignment (h)		(15,266	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	20,408

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(h)	See “AEP East Companies” in Note 17.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	42,797		$	9,344		$	-		$	52,141
Noncurrent Assets		52,245			11			-			52,256
Total MTM Derivative Contract Assets		95,042			9,355			-			104,397
Current Liabilities		(32,297	)		(7,412	)		(7,465	)		(47,174	)
Noncurrent Liabilities		(28,172	)		(842	)		(7,801	)		(36,815	)
Total MTM Derivative Contract  Liabilities		(60,469	)		(8,254	)		(15,266	)		(83,989	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	34,573		$	1,101		$	(15,266	)	$	20,408

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “AEP East Companies” in Note 17.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(3,035	)	$	(110	)	$	1,526		$	-	$	-	$	-	$	(1,619	)
Prices Provided by Other External Sources - OTC  Broker Quotes (a)		14,145			5,845			5,156			1,852		-		-		26,998
Prices Based on Models and Other Valuation Methods (b)		(610	)		(613	)		(638	)		2,816		4,014		4,225		9,194
Total	$	10,500		$	5,122		$	6,044		$	4,668	$	4,014	$	4,225	$	34,573

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow and Fair Value Hedges.

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2003	$	222		$	-		$	222
Changes in Fair Value (a)		2,564			(5,705	)		(3,141	)
Reclassifications from AOCI to Net Income (b)		(1,228	)		71			(1,157	)
Ending Balance December 31, 2004	$	1,558		$	(5,634	)	$	(4,076	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,386 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$371	$1,211	$522	$178	$368	$1,429	$598	$142

VaR Associated with Debt Outstanding

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 $53 million and $79 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004		2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,400,406	$	1,346,393		$	1,312,626
Sales to AEP Affiliates		261,174		249,203			214,138
TOTAL		1,661,580		1,595,596			1,526,764
OPERATING EXPENSES
Fuel for Electric Generation		279,518		250,890			239,455
Purchased Energy for Resale		41,888		28,327			23,443
Purchased Electricity from AEP Affiliates		272,452		274,400			233,724
Other Operation		403,702		417,636			462,707
Maintenance		168,304		158,281			151,602
Depreciation and Amortization		172,099		171,281			168,070
Taxes Other Than Income Taxes		57,344		57,788			57,721
Income Taxes		70,385		50,926			38,853
TOTAL		1,465,692		1,409,529			1,375,575
OPERATING INCOME		195,888		186,067			151,189
Nonoperating Income		79,247		53,928			84,084
Nonoperating Expenses		71,612		77,171			61,374
Nonoperating Income Tax Expense (Credit)		1,230		(9,778	)		5,984
Interest Charges		69,071		83,054			93,923
Net Income Before Cumulative Effect of Accounting Change		133,222		89,548			73,992
Cumulative Effect of Accounting Change, Net of Tax		-		(3,160	)		-
NET INCOME		133,222		86,388			73,992
Preferred Stock Dividend Requirements including Capital Stock Expense		474		2,509			4,601
EARNINGS APPLICABLE TO COMMON STOCK	$	132,748	$	83,879		$	69,391

The common stock of I&M is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	56,584	$	733,216	$	74,605		$	(3,835	)	$	860,570
Capital Contribution from Parent Company				125,000								125,000
Preferred Stock Dividends						(4,467	)					(4,467	)
Capital Stock Expense				344		(134	)					210
TOTAL												981,313
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,911									3,549			3,549
Minimum Pension Liability, Net of Tax of $21,646									(40,201	)		(40,201	)
NET INCOME						73,992						73,992
TOTAL COMPREHENSIVE INCOME												37,340
DECEMBER 31, 2002		56,584		858,560		143,996			(40,487	)		1,018,653
Common Stock Dividends						(40,000	)					(40,000	)
Preferred Stock Dividends						(2,375	)					(2,375	)
Capital Stock Expense				134		(134	)					-
TOTAL												976,278
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $273									508			508
Minimum Pension Liability, Net of Tax of $8,009									14,873			14,873
NET INCOME						86,388						86,388
TOTAL COMPREHENSIVE INCOME												101,769
DECEMBER 31, 2003		56,584		858,694		187,875			(25,106	)		1,078,047
Common Stock Dividends						(99,293	)					(99,293	)
Preferred Stock Dividends						(340	)					(340	)
Capital Stock Expense				141		(134	)					7
TOTAL												978,421
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $2,314									(4,298	)		(4,298	)
Minimum Pension Liability, Net of Tax of $8,533									(15,847	)		(15,847	)
NET INCOME						133,222						133,222
TOTAL COMPREHENSIVE INCOME												113,077
DECEMBER 31, 2004	$	56,584	$	858,835	$	221,330		$	(45,251	)	$	1,091,498

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	3,122,883		$	2,878,051
Transmission		1,009,551			1,000,926
Distribution		990,826			958,966
General (including nuclear fuel)		275,622			274,283
Construction Work in Progress		163,515			193,956
Total		5,562,397			5,306,182
Accumulated Depreciation and Amortization		2,603,479			2,490,912
TOTAL - NET		2,958,918			2,815,270
OTHER PROPERTY AND INVESTMENTS
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds		1,053,439			982,394
Nonutility Property, Net		50,440			52,303
Other Investments		21,848			43,797
TOTAL		1,125,727			1,078,494
CURRENT ASSETS
Cash and Cash Equivalents		465			3,899
Other Cash Deposits		46			15
Advances to Affiliates		5,093			-
Accounts Receivable:
Customers		62,608			63,084
Affiliated Companies		124,134			124,826
Miscellaneous		4,339			4,498
Allowance for Uncollectible Accounts		(187	)		(531	)
Fuel		27,218			33,968
Materials and Supplies		103,342			85,615
Risk Management Assets		52,141			44,071
Margin Deposits		5,400			7,245
Prepayments and Other		10,541			10,673
TOTAL		395,140			377,363
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		147,167			151,973
Incremental Nuclear Refueling Outage Expenses, Net		44,244			57,326
Unamortized Loss on Reacquired Debt		21,039			18,424
DOE Decontamination Fund		14,215			18,863
Other		31,015			29,691
Long-term Risk Management Assets		52,256			43,768
Emission Allowances		27,093			19,713
Deferred Property Taxes		22,372			21,916
Deferred Charges and Other Assets		28,955			26,270
TOTAL		388,356			387,944
TOTAL ASSETS	$	4,868,141		$	4,659,071

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares	$	56,584		$	56,584
Paid-in Capital		858,835			858,694
Retained Earnings		221,330			187,875
Accumulated Other Comprehensive Income (Loss)		(45,251	)		(25,106	)
Total Common Shareholder’s Equity		1,091,498			1,078,047
Cumulative Preferred Stock Not Subject to Mandatory Redemption		8,084			8,101
Total Shareholders’ Equity		1,099,582			1,086,148
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption		-			63,445
Long-term Debt		1,312,843			1,134,359
TOTAL		2,412,425			2,283,952
CURRENT LIABILITIES
Cumulative Preferred Stock Due Within One Year		61,445			-
Long-term Debt Due Within One Year		-			205,000
Advances from Affiliates		-			98,822
Accounts Payable:
General		91,472			101,776
Affiliated Companies		51,066			47,484
Customer Deposits		29,366			21,955
Taxes Accrued		123,159			42,189
Interest Accrued		12,465			17,963
Risk Management Liabilities		47,174			31,898
Obligations Under Capital Leases		6,124			6,528
Other		70,237			57,675
TOTAL		492,508			631,290
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		315,730			337,376
Regulatory Liabilities:
Asset Removal Costs		280,054			263,015
Deferred Investment Tax Credits		82,802			90,278
Excess ARO for Nuclear Decommissioning		245,175			215,715
Unrealized Gain on Forward Commitments		35,534			25,010
Other		33,695			36,258
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2		66,472			70,179
Long-term Risk Management Liabilities		36,815			33,537
Obligations Under Capital Leases		44,608			31,315
Asset Retirement Obligations		711,769			553,219
Employee Benefits and Pension Obligations		70,027			45,751
Deferred Credits and Other		40,527			42,176
TOTAL		1,963,208			1,743,829
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	4,868,141		$	4,659,071

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	133,222		$	86,388		$	73,992
Adjustments to Reconcile Net Income to Net Cash Flows   From Operating Activities:
Asset Impairments		-			10,300			-
Cumulative Effect of Accounting Change		-			3,160			-
Depreciation and Amortization		172,099			171,281			168,070
Accretion Expense		39,825			37,150			-
Amortization (Deferral) of Incremental Nuclear    Refueling Outage Expenses, Net		13,082			(27,754	)		(26,577	)
Unrecovered Fuel and Purchased Power Costs		(1,689	)		37,501			37,501
Amortization of Nuclear Outage Costs		-			40,000			40,000
Deferred Income Taxes		(5,548	)		(14,894	)		(16,921	)
Deferred Investment Tax Credits		(7,476	)		(7,431	)		(7,740	)
Deferred Property Taxes		(456	)		355			1,997
Mark-to-Market of Risk Management Contracts		2,756			43,938			(9,517	)
Change in Other Noncurrent Assets		(4,799	)		(22,283	)		(30,397	)
Change in Other Noncurrent Liabilities		(9,194	)		(38,720	)		9,196
Changes in Components of Working Capital:
Accounts Receivable, Net		983			34,346			(106,683	)
Fuel, Materials and Supplies		(10,977	)		(7,320	)		(2,084	)
Accounts Payable		(6,722	)		(69,396	)		87,934
Taxes Accrued		80,970			(29,370	)		1,798
Customer Deposits		7,411			5,294			7,391
Interest Accrued		(5,498	)		(3,518	)		790
Other Current Assets		1,977			(6,019	)		(5,403	)
Other Current Liabilities		12,157			(20,187	)		4,887
Net Cash Flows From Operating Activities		412,123			222,821			228,234
INVESTING ACTIVITIES
Construction Expenditures		(176,795	)		(184,587	)		(167,484	)
Changes in Other Cash Deposits, Net		(31	)		(28	)		10,112
Proceeds from Sale of Assets		2,788			1,836			-
Other		-			-			1,759
Net Cash Flows Used For Investing Activities		(174,038	)		(182,779	)		(155,613	)
FINANCING ACTIVITIES
Capital Contributions from Parent		-			-			125,000
Issuance of Long-term Debt - Nonaffiliated		268,057			64,434			288,732
Retirement of Cumulative Preferred Stock		(2,011	)		(1,500	)		(424	)
Retirement of Long-term Debt		(304,017	)		(350,000	)		(340,000	)
Changes in Advances to/from Affiliates, Net		(103,915	)		290,048			(144,917	)
Dividends Paid on Common Stock		(99,293	)		(40,000	)		-
Dividends Paid on Cumulative Preferred Stock		(340	)		(2,375	)		(4,467	)
Net Cash Flows Used For Financing Activities		(241,519	)		(39,393	)		(76,076	)
Net Increase (Decrease) in Cash and Cash Equivalents		(3,434	)		649			(3,455	)
Cash and Cash Equivalents at Beginning of Period		3,899			3,250			6,705
Cash and Cash Equivalents at End of Period	$	465		$	3,899		$	3,250

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $70,988,000, $82,593,000 and $89,984,000 and for income taxes was $(2,244,000), $94,440,000 and $60,523,000 in 2004, 2003 and 2002, respectively. Noncash acquisitions under capital leases were $20,557,000, $0 and $1,023,000 in 2004, 2003 and 2002, respectively.

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

								2004		2003
								(in thousands)
PREFERRED STOCK:
$100 Par Value Per Share - Authorized 2,250,000 shares
$25 Par Value Per Share - Authorized 11,200,000 shares
		Call Price		Number of Shares			Shares
		December 31,		Redeemed			Outstanding
Series		2004 (a)		Year Ended December 31,			December 31, 2004
				2004	2003	2002
Not Subject to Mandatory Redemption - $100 Par:
4.125	%	$	106.125	-	-	20	55,369	$	5,537	$	5,537
4.560	%		102.000	-	-	-	14,412		1,441		1,441
4.120	%		102.728	175	-	6,326	11,055		1,106		1,123
Total								$	8,084	$	8,101
Subject to Mandatory Redemption - $100 Par (b):
5.900	%			20,000	-	-	132,000	$	13,200	$	15,200
6.250	%			-	-	-	192,500		19,250		19,250
6.300	%			-	-	-	132,450		13,245		13,245
6.875	%			-	15,000	-	157,500		15,750		15,750
Total								$	61,445	$	63,445

(a)	The cumulative preferred stock is callable at the price indicated plus accrued dividends.
(b)	All shares of each series subject to mandatory redemption were reacquired in January 2005.

See Notes to Financial Statements of Registrant Subsidiaries.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004		2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	-	$	54,725
Installment Purchase Contracts		311,230		310,676
Senior Unsecured Notes		772,712		747,873
Other Long-term Debt (a)		228,901		226,085
Less Portion Due Within One Year		-		(205,000	)
Long-term Debt Excluding Portion Due Within One Year	$	1,312,843	$	1,134,359

(a) Represents a liability for SNF disposal including interest payable to the DOE. See “SNF Disposal” section of Note 7.

There are certain limitations on establishing additional liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of our affiliates.

First Mortgage Bonds outstanding were as follows:

		2004		2003
% Rate	Due	(in thousands)
7.200	2024 - February 1	$	-	$	30,000
7.500	2024 - March 1		-		25,000
Unamortized Discount			-		(275	)
Total		$	-	$	54,725

Installment Purchase Contracts have been entered in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004			2003
	% Rate	Due	(in thousands)
City of Lawrenceburg, Indiana	(a)	2019 - October 1	$	25,000		$	25,000
	5.900	2019 - November 1		-			52,000
	(b)	2021 - November 1		52,000			-
City of Rockport, Indiana	(a)	2025 - April 1		40,000			40,000
	6.550	2025 - June 1		50,000			50,000
	(c)	2025 - June 1		50,000			50,000
	4.900 (d)	2025 - June 1		50,000			50,000
City of Sullivan, Indiana	5.950	2009 - May 1		-			45,000
	(e)	2009 - May 1		45,000			-
Unamortized Discount				(770	)		(1,324	)
Total			$	311,230		$	310,676

(a)	Rate is an annual long-term fixed rate of 2.625% through October 1, 2006. After that date the rate may be a daily or weekly reset rate, commercial paper, auction or other long-term rate as designated by I&M (fixed rate bonds).
(b)	In October 2004, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate on December 31, 2004 was 1.815%. The auction rate for 2004 ranged from 1.70% to 1.815% and averaged 1.73%.
(c)	In 2001, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for 2004 ranged from 0.93% to 1.70% and averaged 1.26%. The auction rate for 2003 ranged from 0.85% to 1.35% and averaged 1.05%.
(d)	Rate is fixed until June 1, 2007 (term rate bonds).
(e)	In October 2004, an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate on December 31, 2004 was 1.75%. The auction rate for 2004 ranged from 1.45% to 1.75% and averaged 1.59%.

The terms of the installment purchase contracts require I&M to pay amounts sufficient for the cities to pay interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants. The fixed rate bonds due 2019 and 2025 are subject to mandatory tender for purchase on October 1, 2006. Consequently, the fixed rate bonds have been classified for repayment purposes in 2006. The term rate bonds due 2025 are subject to mandatory tender for purchase on the term maturity date (June 1, 2007). Accordingly, the term rate bonds have been classified for repayment purposes in 2007 (the term end date). Interest payments range from every 35 days to semi-annually.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
6.875	2004 - July 1	$	-		$	150,000
6.125	2006 - December 15		300,000			300,000
6.450	2008 - November 10		50,000			50,000
6.375	2012 - November 1		100,000			100,000
5.050	2014 - November 15		175,000			-
6.000	2032 - December 31		150,000			150,000
Unamortized Discount			(2,288	)		(2,127	)
Total		$	772,712		$	747,873

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	-
2006		365,000
2007		50,000
2008		50,000
2009		45,000
Later Years		805,901
Total Principal Amount		1,315,901
Unamortized Discount		(3,058	)
Total	$	1,312,843

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to I&M’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” and EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

KENTUCKY POWER COMPANY

KENTUCKY POWER COMPANY

SELECTED FINANCIAL DATA

(in thousands)

	2004		2003			2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	450,613	$	416,470		$	378,683	$	379,025	$	389,875
Operating Income		55,321		64,744			42,197		47,678		49,738
Interest Charges		29,470		28,620			26,836		27,361		31,045
Income Before Cumulative Effect of Accounting Change		25,905		33,464			20,567		21,565		20,763
Cumulative Effect of Accounting Change, Net of Tax		-		(1,134	)		-		-		-
Net Income		25,905		32,330			20,567		21,565		20,763
BALANCE SHEETS DATA
Electric Utility Plant	$	1,361,547	$	1,349,746		$	1,295,619	$	1,128,415	$	1,103,064
Accumulated Depreciation and Amortization		398,455		381,876			373,638		360,319		338,270
Net Electric Utility Plant	$	963,092	$	967,870		$	921,981	$	768,096	$	764,794
Total Assets	$	1,243,247	$	1,221,634		$	1,188,342	$	1,022,833	$	1,516,921
Common Shareholder’s Equity		320,980		317,138			298,018		256,130		266,713
Long-term Debt (a)		508,310		487,602			466,632		346,093		330,880
Obligations Under Capital Leases (a)		4,363		5,292			7,248		9,583		14,184

(a) Including portion due within one year.

KENTUCKY POWER COMPANY

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

KPCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 175,000 retail customers in our service territory in eastern Kentucky. As a member of the AEP Power Pool, we share the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers. We also sell power at wholesale to municipalities.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

On October 1, 2004, our transmission and generation operations, commercial processes and data systems were integrated into those of PJM. While we continue to own our transmission assets, use our low-cost generation plant to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM via the AEP Power Pool, discussed above.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in the new environment. We are confident in our ability to participate successfully in the PJM market.

To minimize the credit requirements and operating constraints when joining PJM, the AEP East Companies as well as Wheeling Power Company and Kingsport Power Company, have agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

Net Income for 2004 decreased $6 million over the prior year primarily due to increases in planned boiler overhaul outages and administrative and support expenses.

2004 Compared to 2003

Operating Income

Operating Income for 2004 decreased by $9 million from 2003 primarily due to:

· A $25 million increase in Fuel for Electric Generation expenses resulting from an increase in the cost of coal consumed and a 6% increase in electric generation.

· An $8 million increase in Purchased Energy for Resale expenses primarily related to coal trading purchases from procurement contracts.

· A $5 million increase in Maintenance expense caused by planned boiler overhaul outages in the first and second quarters of 2004 as well as a turbine repair outage in the fourth quarter of 2004.

· A $5 million increase in Depreciation and Amortization expense primarily related to the installation of emission control equipment at the Big Sandy plant in mid-2003.

· A $4 million increase in Other Operation expense resulting from increased administrative and support expenses in 2004.

The decrease in Operating Income for 2004 was partially offset by:

· A $32 million increase in Electric Generation, Transmission and Distribution revenues due primarily to an improvement in commercial and industrial sales, the rate increase in mid-2003 to recover the cost of emission control equipment, increased fuel recoveries related to increased fuel costs, and increased revenues related to coal trading sales.

· A $3 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $2 million increase in Sales to AEP Affiliates reflecting recovery of increased generation expenses.

Other Impacts on Earnings

Nonoperating Income increased $5 million in 2004 compared to 2003 primarily due to favorable results from risk management activities.

Nonoperating Income Tax Credit decreased $2 million in 2004 compared to 2003. See Income Taxes section below for further discussion.

Income Taxes

The effective tax rates for 2004 and 2003 were 25.1% and 22.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, amortization of investment tax credits, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to less favorable federal income tax adjustments.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	Baa2	BBB	BBB

Summary Obligation Information

Our contractual obligations include amounts reported on the Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	-	$	383.0	$	30.0	$	95.0	$	508.0
Capital Lease Obligations (b)		1.9		2.2		0.7		0.1		4.9
Noncancelable Operating Leases (b)		1.5		2.1		1.3		1.8		6.7
Fuel Purchase Contracts (c)		84.7		159.6		3.9		-		248.2
Energy and Capacity Purchase Contracts (d)		5.1		7.6		-		-		12.7
Total	$	93.2	$	554.5	$	35.9	$	96.9	$	780.5

(a)	See Schedule of Long-term Debt. Represents principal only excluding interest.
(b)	See Note 15.
(c)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(d)	Represents contractual cash flows of energy and capacity purchase contracts.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	15,490
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(5,611	)
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(106	)
Change in Fair Value Due to Valuation Methodology Changes (d)		-
Changes in Fair Value of Risk Management Contracts (e)		496
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		2,422
Total MTM Risk Management Contract Net Assets		12,691
Net Cash Flow and Fair Value Hedge Contracts (g)		1,102
DETM Assignment (h)		(5,570	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	8,223

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow and Fair Value Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(h)	See “AEP East Companies” in Note 17.

Reconciliation of MTM Risk Management Contracts to

Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	15,691		$	4,154		$	-		$	19,845
Noncurrent Assets		19,063			4			-			19,067
Total MTM Derivative Contract Assets		34,754			4,158			-			38,912
Current Liabilities		(11,784	)		(2,697	)		(2,724	)		(17,205	)
Noncurrent Liabilities		(10,279	)		(359	)		(2,846	)		(13,484	)
Total MTM Derivative Contract Liabilities		(22,063	)		(3,056	)		(5,570	)		(30,689	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	12,691		$	1,102		$	(5,570	)	$	8,223

(a)	Does not include Cash Flow and Fair Value Hedges.
(b)	See “AEP East Companies” in Note 17.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,107	)	$	(40	)	$	557		$	-	$	-	$	-	$	(590	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		5,236			2,133			1,882			676		-		-		9,927
Prices Based on Models and Other Valuation Methods (b)		(222	)		(223	)		(233	)		1,027		1,464		1,541		3,354
Total	$	3,907		$	1,870		$	2,206		$	1,703	$	1,464	$	1,541	$	12,691

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow and Fair Value Hedges.

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2003	$	82		$	338		$	420
Changes in Fair Value (a)		918			-			918
Reclassifications from AOCI to Net Income (b)		(431	)		(94	)		(525	)
Ending Balance December 31, 2004	$	569		$	244		$	813

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $800 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$135	$442	$191	$65	$136	$527	$220	$52

VaR Associated with Debt Outstanding

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 $16 million and $29 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or financial position.

KENTUCKY POWER COMPANY

STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	409,023		$	376,662		$	350,719
Sales to AEP Affiliates		41,590			39,808			27,964
TOTAL		450,613			416,470			378,683
OPERATING EXPENSES
Fuel for Electric Generation		99,456			74,148			65,043
Purchased Energy for Resale		8,532			963			29
Purchased Electricity from AEP Affiliates		140,758			141,690			133,002
Other Operation		51,757			47,325			52,892
Maintenance		32,802			27,328			35,089
Depreciation and Amortization		43,847			39,309			33,233
Taxes Other Than Income Taxes		9,145			8,788			8,240
Income Taxes		8,995			12,175			8,958
TOTAL		395,292			351,726			336,486
OPERATING INCOME		55,321			64,744			42,197
Nonoperating Income (Loss)		1,298			(4,036	)		7,950
Nonoperating Expenses		1,568			1,124			840
Nonoperating Income Tax Expense (Credit)		(324	)		(2,500	)		1,904
Interest Charges		29,470			28,620			26,836
Income Before Cumulative Effect of Accounting Change		25,905			33,464			20,567
Cumulative Effect of Accounting Change, Net of Tax		-			(1,134	)		-
NET INCOME	$	25,905		$	32,330		$	20,567

The common stock of KPCo is wholly-owned by AEP

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	50,450	$	158,750	$	48,833		$	(1,903	)	$	256,130
Capital Contribution from Parent				50,000								50,000
Common Stock Dividends						(21,131	)					(21,131	)
TOTAL												284,999
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),   Net of Taxes:
Cash Flow Hedges, Net of Tax of $1,198									2,225			2,225
Minimum Pension Liability, Net of Tax
of $5,262									(9,773	)		(9,773	)
NET INCOME						20,567						20,567
TOTAL COMPREHENSIVE INCOME												13,019
DECEMBER 31, 2002		50,450		208,750		48,269			(9,451	)		298,018
Common Stock Dividends						(16,448	)					(16,448	)
TOTAL												281,570
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),   Net of Taxes:
Cash Flow Hedges, Net of Tax of $53									98			98
Minimum Pension Liability, Net of Tax
of $1,691									3,140			3,140
NET INCOME						32,330						32,330
TOTAL COMPREHENSIVE INCOME												35,568
DECEMBER 31, 2003		50,450		208,750		64,151			(6,213	)		317,138
Common Stock Dividends						(19,501	)					(19,501	)
TOTAL												297,637
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),    Net of Taxes:
Cash Flow Hedges, Net of Tax of $212									393			393
Minimum Pension Liability, Net of Tax
of $1,592									(2,955	)		(2,955	)
NET INCOME						25,905						25,905
TOTAL COMPREHENSIVE INCOME												23,343
DECEMBER 31, 2004	$	50,450	$	208,750	$	70,555		$	(8,775	)	$	320,980

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	462,641		$	457,341
Transmission		385,667			381,354
Distribution		438,766			425,688
General		57,929			68,041
Construction Work in Progress		16,544			17,322
Total		1,361,547			1,349,746
Accumulated Depreciation and Amortization		398,455			381,876
TOTAL - NET		963,092			967,870
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		5,438			5,423
Other Investments		422			1,022
TOTAL		5,860			6,445
CURRENT ASSETS
Cash and Cash Equivalents		127			863
Other Cash Deposits		5			23
Advances to Affiliates		16,127			-
Accounts Receivable:
Customers		22,130			21,177
Affiliated Companies		23,046			25,327
Accrued Unbilled Revenues		7,340			5,534
Miscellaneous		94			97
Allowance for Uncollectible Accounts		(34	)		(736	)
Fuel		6,551			9,481
Materials and Supplies		9,385			8,831
Risk Management Assets		19,845			16,200
Margin Deposits		1,960			2,660
Prepayments and Other		1,782			1,696
TOTAL		108,358			91,153
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		103,849			99,828
Other		14,558			13,971
Long-term Risk Management Assets		19,067			16,134
Emission Allowances		9,666			7,754
Deferred Property Taxes		7,036			6,847
Deferred Charges and Other		11,761			11,632
TOTAL		165,937			156,166
TOTAL ASSETS	$	1,243,247		$	1,221,634

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $50 Par Value Per Share:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares	$	50,450		$	50,450
Paid-in Capital		208,750			208,750
Retained Earnings		70,555			64,151
Accumulated Other Comprehensive Income (Loss)		(8,775	)		(6,213	)
Total Common Shareholder’s Equity		320,980			317,138
Long-term Debt:
Nonaffiliated		428,310			427,602
Affiliated		80,000			60,000
Total Long-term Debt		508,310			487,602
TOTAL		829,290			804,740
CURRENT LIABILITIES
Accounts Payable:
General		20,080			22,802
Affiliated Companies		24,899			22,648
Advances from Affiliates		-			38,096
Risk Management Liabilities		17,205			11,704
Taxes Accrued		9,248			7,329
Interest Accrued		6,754			6,915
Customer Deposits		12,309			9,894
Obligations Under Capital Leases		1,561			1,743
Other		9,038			8,628
TOTAL		101,094			129,759
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		227,536			212,121
Regulatory Liabilities:
Asset Removal Costs		28,232			26,140
Deferred Investment Tax Credits		6,722			7,955
Other Regulatory Liabilities		15,622			10,591
Employee Benefits and Pension Obligations		17,729			13,999
Long-term Risk Management Liabilities		13,484			12,363
Obligations Under Capital Leases		2,802			3,549
Deferred Credits		736			417
TOTAL		312,863			287,135
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	1,243,247		$	1,221,634

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	25,905		$	32,330		$	20,567
Adjustments to Reconcile Net Income to   Net Cash Flows From Operating Activities:
Cumulative Effect of Accounting Changes		-			1,134			-
Depreciation and Amortization		43,847			39,309			33,233
Deferred Income Taxes		12,774			20,107			9,839
Deferred Investment Tax Credits		(1,233	)		(1,210	)		(1,240	)
Deferred Property Taxes		(189	)		(547	)		(338	)
Deferred Fuel Costs, Net		1,164			233			2,998
Mark-to-Market of Risk Management Contracts		1,020			15,112			(12,267	)
Change in Other Noncurrent Assets		(7,269	)		(15,184	)		(22,187	)
Change in Other Noncurrent Liabilities		8,147			6,224			(5,898	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(1,177	)		2,445			(9,332	)
Fuel, Materials and Supplies		2,376			2,250			3,170
Accounts Payable		(471	)		(45,100	)		44,529
Taxes Accrued		1,919			8,582			(11,558	)
Customer Deposits		2,415			1,846			3,588
Interest Accrued		(161	)		444			1,202
Other Current Assets		614			(2,229	)		(812	)
Other Current Liabilities		226			(3,949	)		16,827
Net Cash Flows From Operating Activities		89,907			61,797			72,321
INVESTING ACTIVITIES
Construction Expenditures		(38,475	)		(81,707	)		(178,700	)
Change in Other Cash Deposits, Net		18			(4	)		17
Proceeds from Sale of Assets		1,538			967			-
Other		-			-			217
Net Cash Flows Used For Investing Activities		(36,919	)		(80,744	)		(178,466	)
FINANCING ACTIVITIES
Capital Contributions from Parent		-			-			50,000
Issuance of Long-term Debt - Nonaffiliated		-			74,263			-
Issuance of Long-term Debt - Affiliated		20,000			-			274,964
Retirement of Long-term Debt - Nonaffiliated		-			(40,000	)		(154,500	)
Retirement of Long-term Debt - Affiliated		-			(15,000	)
Change in Advances to/from Affiliates, Net		(54,223	)		14,710			(42,814	)
Dividends Paid		(19,501	)		(16,448	)		(21,131	)
Net Cash Flows From (Used For) Financing Activities		(53,724	)		17,525			106,519
Net Increase (Decrease) in Cash and Cash Equivalents		(736	)		(1,422	)		374
Cash and Cash Equivalents at Beginning of Period		863			2,285			1,911
Cash and Cash Equivalents at End of Period	$	127		$	863		$	2,285

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $28,367,000, $26,988,000 and $25,176,000 in 2004, 2003 and 2002, respectively. Cash paid (received) for income taxes was $(3,233,000), $(17,574,000) and $13,041,000 in 2004, 2003 and 2002, respectively. Noncash acquisitions under capital leases were $925,000, $0 and $22,000 in 2004, 2003 and 2002, respectively.

See Notes to Financial Statements of Registrant Subsidiaries.

KENTUCKY POWER COMPANY

SCHEDULE OF LONG-TERM DEBT

December 31, 2004 and 2003

	2004		2003
LONG-TERM DEBT:	(in thousands)
Senior Unsecured Notes	$	428,310	$	427,602
Notes Payable - Affiliated		80,000		60,000
Long-term Debt Excluding Portion Due Within One Year	$	508,310	$	487,602

There are certain limitations on establishing liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
6.910	2007 - October 1	$	48,000		$	48,000
6.450	2008 - November 10		30,000			30,000
5.500	2007 - July 1		125,000			125,000
4.310	2007 - November 12		80,400			80,400
4.370	2007 - December 12		69,564			69,564
5.625	2032 - December 31		75,000			75,000
Unamortized Discount			(268	)		(362	)
Interest Rate Hedge			614			-
Total		$	428,310		$	427,602

Notes Payable to Parent were as follows:

		2004		2003
% Rate	Due	(in thousands)
6.501	2006 - May 15	$	60,000	$	60,000
5.250	2015 - June 1		20,000		-
Total		$	80,000	$	60,000

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	-
2006		60,000
2007		322,964
2008		30,000
2009		-
Later Years		95,000
Total Principal Amount		507,964
Unamortized Discount		(268	)
Interest Rate Hedge		614
Total	$	508,310

KENTUCKY POWER COMPANY

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to KPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to KPCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Kentucky Power Company:

We have audited the accompanying balance sheets of Kentucky Power Company as of December 31, 2004 and 2003, and the related statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Kentucky Power Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

OHIO POWER COMPANY CONSOLIDATED

OHIO POWER COMPANY CONSOLIDATED

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003		2002		2001			2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	2,236,396	$	2,244,653	$	2,113,125	$	2,098,105		$	2,140,331
Operating Income		312,372		359,667		298,329		240,710			226,827
Interest Charges		118,685		106,464		83,682		93,603			119,210
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		210,116		251,031		220,023		165,793			102,613
Extraordinary Loss, Net of Tax		-		-		-		(18,348	)		(18,876	)
Cumulative Effect of Accounting Changes, Net of Tax		-		124,632		-		-			-
Net Income		210,116		375,663		220,023		147,445			83,737
BALANCE SHEETS DATA
Electric Utility Plant	$	6,798,032	$	6,513,591	$	5,685,826	$	5,390,576		$	5,577,631
Accumulated Depreciation and Amortization		2,617,238		2,485,947		2,469,837		2,360,857			2,678,606
Net Electric Utility Plant	$	4,180,794	$	4,027,644	$	3,215,989	$	3,029,719		$	2,899,025
TOTAL ASSETS (b)	$	5,593,265	$	5,374,518	$	4,554,023	$	4,485,787		$	6,279,499
Common Shareholder’s Equity		1,473,838		1,464,025		1,233,114		1,184,785			1,181,770
Cumulative Preferred Stock Not Subject to   Mandatory Redemption		16,641		16,645		16,648		16,648			16,648
Cumulative Preferred Stock Subject to .   Mandatory Redemption (a)		5,000		7,250		8,850		8,850			8,850
Long-term Debt (a)(b)		2,011,060		2,039,940		1,067,314		1,203,841			1,195,493
Obligations Under Capital Leases (a)		40,733		34,688		65,626		80,666			116,581

(a)	Including portion due within one year.
(b)	Due to the implementation of FIN 46, OPCo was required to consolidate JMG during the third quarter of 2003.

OHIO POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

OPCo is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 707,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio. We consolidate JMG Funding LP, a variable interest entity. As a member of the AEP Power Pool, we share in the revenues and the costs of the AEP Power Pool’s sales to neighboring utilities and power marketers.

The cost of the AEP Power Pool’s generating capacity is allocated among its members based on their relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity credits. AEP Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The AEP Power Pool calculates each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the member load ratio (MLR), which determines each member’s percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

On October 1, 2004, our transmission and generation operations, commercial processes and data systems were integrated into those of PJM. While we continue to own our transmission assets, use our low-cost generation fleet to serve the needs of our native-load customers, and sell available generation to other parties, we are performing those functions through PJM via the AEP Power Pool, discussed above.

During the fourth quarter of 2004, our PJM-related operating results came in as expected, in spite of having to overcome the initial learning curve of operating in the new environment. We are confident in our ability to participate successfully in the PJM market.

To minimize the credit requirements and operating constraints when joining PJM, the AEP East companies as well as Wheeling Power Company and Kingsport Power Company, have agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Effective July 1, 2003, we consolidated JMG as a result of the implementation of FIN 46. OPCo records the depreciation, interest and other operating expenses of JMG and eliminates JMG’s revenues against OPCo’s operating lease expenses. While there was no effect to net income as a result of consolidation, some individual income statement captions were affected. See “FIN 46 Consolidation of Variable Interest Entities” section of Note 2 and “Gavin Scrubber Financing Arrangement” section of Note 15.

Results of Operations

During 2004, Net Income decreased by $166 million primarily due to a $125 million Cumulative Effect of Accounting Changes recorded in the first quarter of 2003. Income Before Cumulative Effect decreased $41 million primarily due to an increase in fuel cost for electric generation.

During 2003, Net Income increased $156 million including a $125 million Cumulative Effect of Accounting Changes in the first quarter of 2003 (see “Cumulative Effect of Accounting Change” section of Note 2). Income Before Cumulative Effect of Accounting Changes increased $31 million primarily due to increased revenues which were allocated to us from sales made to third parties by the AEP Power Pool.

2004 Compared to 2003

Operating Income

Operating Income decreased by $47 million primarily due to:

· A $29 million increase in fuel expense related to a 7% increase in the cost of coal consumed. The effect of this increase in price was partially offset by a 2.5% decrease in net generation.

· A $29 million increase in Depreciation and Amortization expense primarily associated with the consolidation of JMG (there was no change in Net Income due to the consolidation of JMG). In addition, the increase is a result of a greater depreciable asset base in 2004, including capitalized software costs and the increased amortization of transition generation regulatory assets due to normal operating adjustments.

· A $23 million decrease in nonaffiliated wholesale energy sales and related transmission services due to lower sales volume.

· An $18 million increase in Other Operation expense primarily related to increased employee benefit expense including pension plan costs and workers' compensation and administrative and support expenses.

· An $11 million increase in Maintenance expense primarily associated with costs incurred as a result of a major ice storm in December 2004.

· A $3 million decrease in Sales to AEP Affiliates due to lower sales volume.

The decrease in Operating Income was partially offset by:

· A $49 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $15 million increase in operating revenues related to favorable results from risk management activities.

· A $7 million increase in retail electric revenues resulting from increased demand of industrial customers due to the recovering economy.

Other Impacts on Earnings

Nonoperating Income increased $146 million primarily due to sales of excess energy purchased from the Dow Chemical Company (Dow) at the Plaquemine, Louisiana plant (see “Power Generation Facility” section below) including the effects of a related affiliate agreement which eliminates our market exposure related to the purchases from Dow. There was no change in Net Income due to the agreement with Dow. In addition, income from nonoperating risk management activities contributed to this increase.

Nonoperating Expenses increased $120 million primarily due to the agreement to purchase excess energy from Dow at the Plaquemine, Louisiana plant (see “Power Generation Facility” section below). There was no change in Net Income due to the agreement with Dow.

Interest Charges increased $12 million due to the consolidation of JMG in July 2003 and its associated debt. There was no change in Net Income due to the consolidation of JMG.

Income Taxes

The effective tax rates for 2004 and 2003 were 31.4% and 35.5%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes, and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to lower state income taxes and more favorable federal income tax adjustments.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes during 2003 of $125 million is due to the one-time after tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Note 2).

2003 Compared to 2002

Operating Income

Operating Income increased $61 million due to:

· A $47 million decrease in Other Operation expense. This decrease was primarily due to a $23 million decrease in rent expense associated with the OPCo consolidation of JMG. OPCo now records the depreciation, interest and other expenses of JMG and eliminates operating lease expense against JMG’s lease revenues. There was no change in Net Income due to the consolidation of JMG. In addition, operating expenses decreased due to a $7 million pretax adjustment to the workers’ compensation reserve related to coal companies sold in July 2001, a $9 million decrease in expense related to post-employment benefits and an $8 million reduction in employee salary expenses.

· A $22 million increase in revenues from nonaffiliated off-system sales and a $119 million increase in Sales to AEP Affiliates. The increase in nonaffiliated off-system sales is primarily the result of an 8.9% increase in the price per MWH in 2003. The increase in affiliated sales is the result of optimizing our generation capacity and selling our excess power to the AEP Power Pool.

The increase in Operating Income was partially offset by:

· A $32 million increase in Fuel for Electric Generation as a result of a 9.7% increase in MWH generated.

· A $32 million increase in Income Taxes. See Income Taxes section below for further discussion.

· A $30 million increase in Maintenance expenses. The increase in 2003 is primarily due to increased boiler overhaul costs for planned and forced outages coupled with increased expense in maintaining overhead lines due to storm damage in southern Ohio.

· A $20 million increase in Purchased Electricity from AEP Affiliates resulting from a 31% volume increase in MWHs purchased from the AEP Power Pool.

· An increase in Depreciation and Amortization associated with the OPCo consolidation of JMG. Effective July 1, 2003, depreciation expense related to the assets owned by JMG is consolidated with OPCo.

Other Impacts on Earnings

Nonoperating Income decreased $34 million for the year 2003 compared to 2002 primarily due to unfavorable results from risk management activities.

Nonoperating Income Tax Expense decreased $26 million as a result of a decrease in pretax nonoperating book income and changes related to consolidated tax savings.

Interest charges increased $23 million due primarily to the consolidation of JMG and its associated debt along with replacement of lower cost floating-rate short-term debt with higher cost fixed-rate longer-term debt.

Income Taxes

The effective tax rates for 2003 and 2002 were 35.5% and 37.4%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to flow-through of book versus tax temporary differences, permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes, and federal income tax adjustments. The effective tax rates remained relatively flat for the comparative period.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time after tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see Note 2).

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
Senior Unsecured Debt	A3	BBB	BBB+

Cash Flow

Cash flows for the years ended December 31, 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(in thousands)
Cash and cash equivalents at beginning of period	$	7,233		$	5,275		$	6,727
Cash flows from (used for):
Operating activities		563,107			373,443			478,973
Investing activities		(291,589	)		(288,018	)		(346,187	)
Financing activities		(269,451	)		(83,467	)		(134,238	)
Net increase (decrease) in cash and cash equivalents		2,067			1,958			(1,452	)
Cash and cash equivalents at end of period	$	9,300		$	7,233		$	5,275

Operating Activities

Our net cash flows from operating activities were $563 million in 2004. We produced income of $210 million during the period and a noncash expense item of $286 million for Depreciation and Amortization. The 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 working capital relates to a number of items; the most significant is a $100 million change in Taxes Accrued. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extension is filed.

Our net cash flows from operating activities were $373 million in 2003. We produced income of $376 million during the period and noncash expense items of $257 million for Depreciation and Amortization and $(125) million for Cumulative Effect of Accounting Changes. The 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 working capital relates to a number of items; the most significant is a $(173) million change in Accounts Payable, net. The change is a result of significant reductions of accounts payable balances partially associated with a wind down of risk management activities during 2003.

Our net cash flows from operating activities were $479 million in 2002. We produced income of $220 million during the period and noncash expense items of $249 million for Depreciation and Amortization. The 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 working capital relates to a number of items; none of which were significant.

Investing Activities

Our net cash flows used for investing activities in 2004 were $292 million primarily due to Construction Expenditures of $345 million. Current year construction expenditures were focused primarily on projects to improve service reliability for transmission and distribution, as well as environmental upgrades.

Our net cash flows used for investing activities in 2003 were $288 million primarily due to Construction Expenditures of $250 million. The construction expenditures are primarily due to improving the service reliability for transmission and distribution, as well as environmental upgrades.

Our net cash flows used for investing activities in 2002 were $346 million primarily due to Construction Expenditures of $355 million.

Financing Activities

Our net cash flows used for financing activities in 2004 were $269 million primarily due to retirement of long-term debt and payment of dividends on common stock offset by a long-term debt issuance from AEP.

Our net cash flows used for financing activities in 2003 were $83 million due to replacing both short and long-term debt with proceeds from new borrowings.

Our net cash flows used for financing activities in 2002 were $134 million due to decreased borrowings from the Utility Money Pool, retirement of long-term debt and payment of dividends on common stock offset by short-term debt borrowings.

In January 2005, we refinanced $218 million of JMG’s Installment Purchase Contracts. The new bonds bear interest at a 35-day auction rate.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	12.4	$	230.2	$	132.7	$	1,642.1	$	2,017.4
Short-term Debt		23.5		-		-		-		23.5
Cumulative Preferred Stock Subject to  Mandatory Redemption (b)		5.0		-		-		-		5.0
Capital Lease Obligations (c)		9.8		16.4		8.5		20.3		55.0
Noncancelable Operating Leases (c)		16.2		29.5		27.3		71.9		144.9
Fuel Purchase Contracts (d)		585.3		881.2		396.2		431.3		2,294.0
Energy and Capacity Purchase Contracts (e)		16.0		23.7		-		-		39.7
Total	$	668.2	$	1,181.0	$	564.7	$	2,165.6	$	4,579.5

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	See Schedule of Preferred Stock.
(c)	See Note 15.
(d)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(e)	Represents contractual cash flows of energy and capacity purchase contracts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2004 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millions)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	-	$	50.6	$	-	$	-	$	50.6

(a) We have issued standby letters of credit to third parties. These letters of credit cover debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $50.6 million maturing in December 2006. There is no recourse to third parties in the event these letters of credit are drawn.

Other

Power Generation Facility

AEP has 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 AEP. AEP has subleased the Facility to the Dow Chemical Company (Dow) under a 5-year term with three 5-year renewal terms for a total term of up to 20 years. The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has 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 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) 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.

On September 5, 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleges that TEM has breached the PPA, and is seeking a determination of OPCo’s rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of OPCo’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, OPCo could be adversely affected to the extent it is unable to find other purchasers of the power with similar contractual terms and to the extent OPCo does not fully recover claimed termination value damages from TEM. However, OPCo has entered into an agreement with an affiliate that eliminates OPCo’s market exposure related to the PPA. The corporate parent of TEM (Tractebel SA) has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there were no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted OPCo partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA. The litigation is now in the discovery phase, with trial scheduled to begin on March 23, 2005.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for them under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the District Court that the PPA has been terminated and (iii) would be pursuing against TEM, and Tractebel SA under the guaranty, damages and the full termination payment value of the PPA.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

Roll-Forward of MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	53,938
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(27,453	)
Fair Value of New Contracts When Entered During the Period (b)		3,481
Net Option Premiums Paid/(Received) (c)		(363	)
Change in Fair Value Due to Valuation Methodology Changes (d)		1,189
Changes in Fair Value of Risk Management Contracts (e)		16,985
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		-
Total MTM Risk Management Contract Net Assets		47,777
Net Cash Flow Hedge Contracts (g)		984
DETM Assignment (h)		(19,065	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	29,696

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).
(h)	See “AEP East Companies” in Note 17.

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			DETM Assignment (b)			Total (c)
Current Assets	$	66,053		$	13,488		$	-		$	79,541
Noncurrent Assets		66,712			15			-			66,727
Total MTM Derivative Contract Assets		132,765			13,503			-			146,268
Current Liabilities		(49,249	)		(11,739	)		(9,323	)		(70,311	)
Noncurrent Liabilities		(35,739	)		(780	)		(9,742	)		(46,261	)
Total MTM Derivative Contract  Liabilities		(84,988	)		(12,519	)		(19,065	)		(116,572	)
Total MTM Derivative Contract Net  Assets (Liabilities)	$	47,777		$	984		$	(19,065	)	$	29,696

(a)	Does not include Cash Flow Hedges.
(b)	See “AEP East Companies” in Note 17.
(c)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(3,790	)	$	(137	)	$	1,906		$	-	$	-	$	-	$	(2,021	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		21,296			7,499			7,133			2,313		-		-		38,241
Prices Based on Models and Other Valuation Methods (b)		(702	)		(735	)		(810	)		3,515		5,013		5,276		11,557
Total	$	16,804		$	6,627		$	8,229		$	5,828	$	5,013	$	5,276	$	47,777

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges.

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

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

We employ forward contracts as cash flow hedges to lock-in prices on certain transactions which have been denominated in foreign currencies where deemed necessary. We do not hedge all foreign currency exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power			Foreign Currency			Total
Beginning Balance December 31, 2003	$	268		$	(371	)	$	(103	)
Changes in Fair Value (a)		2,830			-			2,830
Reclassifications from AOCI to Net Income (b)		(1,499	)		13			(1,486	)
Ending Balance December 31, 2004	$	1,599		$	(358	)	$	1,241

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $2,083 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$464	$1,513	$652	$223	$444	$1,724	$722	$172

VaR Associated with Debt Outstanding

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 $146 million and $214 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,654,881		$	1,660,375		$	1,647,923
Sales to AEP Affiliates		581,515			584,278			465,202
TOTAL		2,236,396			2,244,653			2,113,125
OPERATING EXPENSES
Fuel for Electric Generation		645,292			616,680			584,730
Purchased Energy for Resale		64,229			63,486			67,385
Purchased Electricity from AEP Affiliates		89,355			90,821			71,154
Other Operation		386,732			369,087			416,533
Maintenance		177,584			166,438			136,609
Depreciation and Amortization		286,300			257,417			248,557
Taxes Other Than Income Taxes		177,374			175,043			176,247
Income Taxes		97,158			146,014			113,581
TOTAL		1,924,024			1,884,986			1,814,796
OPERATING INCOME		312,372			359,667			298,329
Nonoperating Income		170,128			24,495			58,289
Nonoperating Expenses		154,747			34,282			34,903
Nonoperating Income Tax Expense (Credit)		(1,048	)		(7,615	)		18,010
Interest Charges		118,685			106,464			83,682
Income Before Cumulative Effect of Accounting Changes		210,116			251,031			220,023
Cumulative Effect of Accounting Changes, Net of Tax		-			124,632			-
NET INCOME		210,116			375,663			220,023
Preferred Stock Dividend Requirements		733			1,098			1,258
EARNINGS APPLICABLE TO COMMON STOCK	$	209,383		$	374,565		$	218,765

The common stock of OPCo is wholly-owned by AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

		Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001		$	321,201	$	462,483	$	401,297		$	(196	)	$	1,184,785
Common Stock Dividends							(97,746	)					(97,746	)
Preferred Stock Dividends							(1,258	)					(1,258	)
TOTAL													1,085,781
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
	Cash Flow Hedges, Net of Tax of $292									(542	)		(542	)
	Minimum Pension Liability, Net of Tax of $38,849									(72,148	)		(72,148	)
NET INCOME							220,023						220,023
TOTAL COMPREHENSIVE INCOME													147,333
DECEMBER 31, 2002			321,201		462,483		522,316			(72,886	)		1,233,114
Common Stock Dividends							(167,734	)					(167,734	)
Preferred Stock Dividends							(1,098	)					(1,098	)
Capital Stock Gains					1								1
TOTAL													1,064,283
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
	Cash Flow Hedges, Net of Tax of $342									635			635
	Minimum Pension Liability, Net of Tax of $13,495									23,444			23,444
NET INCOME							375,663						375,663
TOTAL COMPREHENSIVE INCOME													399,742
DECEMBER 31, 2003			321,201		462,484		729,147			(48,807	)		1,464,025
Common Stock Dividends							(174,114	)					(174,114	)
Preferred Stock Dividends							(733	)					(733	)
Capital Stock Gains					1								1
TOTAL													1,289,179
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $723										1,344			1,344
Minimum Pension Liability, Net of Tax of $14,432										(26,801	)		(26,801	)
NET INCOME							210,116						210,116
TOTAL COMPREHENSIVE INCOME													184,659
DECEMBER 31, 2004		$	321,201	$	462,485	$	764,416		$	(74,264	)	$	1,473,838

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	4,127,284		$	4,029,515
Transmission		978,492			938,805
Distribution		1,202,550			1,156,886
General		248,749			245,434
Construction Work in Progress		240,957			142,951
Total		6,798,032			6,513,591
Accumulated Depreciation and Amortization		2,617,238			2,485,947
TOTAL - NET		4,180,794			4,027,644
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		44,774			47,015
Other		13,409			22,179
TOTAL		58,183			69,194
CURRENT ASSETS
Cash and Cash Equivalents		9,300			7,233
Other Cash Deposits		37			51,017
Advances to Affiliates		125,971			67,918
Accounts Receivable:
Customers		98,951			100,960
Affiliated Companies		144,175			120,532
Accrued Unbilled Revenues		10,641			17,221
Miscellaneous		7,626			736
Allowance for Uncollectible Accounts		(93	)		(789	)
Fuel		70,309			77,725
Materials and Supplies		55,569			65,768
Emissions Allowances		95,303			2,085
Risk Management Assets		79,541			56,265
Margin Deposits		7,056			9,296
Prepayments and Other		10,492			15,883
TOTAL		714,878			591,850
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		169,866			169,605
Transition Regulatory Assets		225,273			310,035
Unamortized Loss on Reacquired Debt		11,046			10,172
Other		22,189			22,506
Long-term Risk Management Assets		66,727			52,825
Deferred Property Taxes		70,214			67,469
Deferred Charges and Other Assets		74,095			53,218
TOTAL		639,410			685,830
TOTAL ASSETS	$	5,593,265		$	5,374,518

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares	$	321,201		$	321,201
Paid-in Capital		462,485			462,484
Retained Earnings		764,416			729,147
Accumulated Other Comprehensive Income (Loss)		(74,264	)		(48,807	)
Total Common Shareholder’s Equity		1,473,838			1,464,025
Cumulative Preferred Stock Not Subject to Mandatory Redemption		16,641			16,645
Total Shareholders’ Equity		1,490,479			1,480,670
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption		-			7,250
Long-term Debt:
Nonaffiliated		1,598,706			1,608,086
Affiliated		400,000			-
Total Long-term Debt		1,998,706			1,608,086
TOTAL		3,489,185			3,096,006
Minority Interest		14,083			16,314
CURRENT LIABILITIES
Short-term Debt - Nonaffiliated		23,498			25,941
Long-term Debt Due Within One Year - Nonaffiliated		12,354			431,854
Cumulative Preferred Stock Subject to Mandatory Redemption		5,000			-
Accounts Payable:
General		143,247			104,874
Affiliated Companies		116,615			101,758
Customer Deposits		22,620			17,308
Taxes Accrued		233,026			132,793
Interest Accrued		39,254			45,679
Risk Management Liabilities		70,311			38,318
Obligations Under Capital Leases		9,081			9,624
Other		74,977			71,642
TOTAL		749,983			979,791
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		943,465			933,582
Regulatory Liabilities:
Asset Removal Costs		102,875			101,160
Deferred Investment Tax Credits		12,539			15,641
Other		-			3
Long-term Risk Management Liabilities		46,261			40,477
Deferred Credits		24,377			23,222
Employee Benefits and Pension Obligations		126,825			90,260
Obligations Under Capital Leases		31,652			25,064
Asset Retirement Obligations		45,606			42,656
Other		6,414			10,342
TOTAL		1,340,014			1,282,407
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	5,593,265		$	5,374,518

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	210,116		$	375,663		$	220,023
Adjustments to Reconcile Net Income to Net Cash  Flows   From Operating Activities:
Cumulative Effect of Accounting Changes		-			(124,632	)		-
Depreciation and Amortization		286,300			257,417			248,557
Pension and Postemployment Benefits Reserves		32,637			(75,822	)		110,298
Deferred Income Taxes		23,329			24,482			46,010
Deferred Investment Tax Credits		(3,102	)		(3,107	)		(3,177	)
Deferred Property Tax		(2,745	)		(848	)		(1,803	)
Mark-to-Market of Risk Management Contracts		1,171			60,064			(28,693	)
Change in Other Noncurrent Assets		(8,077	)		(23,241	)		(12,963	)
Change in Other Noncurrent Liabilities		(41,055	)		40,048			(120,864	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(22,640	)		(3,966	)		17,652
Fuel, Materials and Supplies		(4,766	)		7,271			7,740
Accounts Payable, Net		53,230			(173,218	)		8,704
Taxes Accrued		100,233			21,015			(14,992	)
Interest Accrued		(6,425	)		21,533			1,130
Customer Deposits		5,312			4,339			7,517
Other Current Assets		(63,203	)		(13,096	)		8,783
Other Current Liabilities		2,792			(20,459	)		(14,949	)
Net Cash Flows From Operating Activities		563,107			373,443			478,973
INVESTING ACTIVITIES
Construction Expenditures		(345,489	)		(249,688	)		(354,797	)
Change in Other Cash Deposits, Net		50,980			(51,007	)		2,111
Proceeds from Sale of Assets		2,920			12,671			-
Other		-			6			6,499
Net Cash Flows Used For Investing Activities		(291,589	)		(288,018	)		(346,187	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		-			988,914			-
Issuance of Long-term Debt - Affiliated		400,000			-			-
Change in Advances to/from Affiliates, Net		(58,053	)		(197,897	)		(170,234	)
Change in Short-term Debt - Nonaffiliated, Net		(2,443	)		(671	)		-
Change in Short-term Debt - Affiliated, Net		-			(275,000	)		275,000
Retirement of Long-term Debt - Nonaffiliated		(431,854	)		(128,378	)		(140,000	)
Retirement of Long-term Debt - Affiliated		-			(300,000	)		-
Retirement of Cumulative Preferred Stock		(2,254	)		(1,603	)		-
Dividends Paid on Common Stock		(174,114	)		(167,734	)		(97,746	)
Dividends Paid on Cumulative Preferred Stock		(733	)		(1,098	)		(1,258	)
Net Cash Flows Used For Financing Activities		(269,451	)		(83,467	)		(134,238	)
Net Increase (Decrease) in Cash and Cash Equivalents		2,067			1,958			(1,452	)
Cash and Cash Equivalents at Beginning of Period		7,233			5,275			6,727
Cash and Cash Equivalents at End of Period	$	9,300		$	7,233		$	5,275

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $119,562,000, $77,170,000 and $81,041,000 and for income taxes was $(21,600,000), $98,923,000 and $105,058,000 in 2004, 2003 and 2002, respectively. Noncash acquisitions under capital leases were $14,727,000, $0 and $106,000 in 2004, 2003 and 2002, respectively. Noncash activity in 2003 included an increase in assets and liabilities of $469.6 million resulting from the consolidation of JMG (see Note 2).

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

							2004		2003
							(in thousands)
PREFERRED STOCK:
$100 Par Value per share - Authorized 3,762,403 shares
$25 Par Value per share - Authorized 4,000,000 shares
		Call Price	Number of Shares			Shares
		December 31,	Redeemed			Outstanding
Series		2004 (a)	Year Ended December 31,			December 31, 2004
			2004	2003	2002
Not Subject to Mandatory Redemption - $100 Par:
4.08%	$103.0		-	-	-	14,595	$	1,460	$	1,460
4.20%		103.2	-	-	-	22,824		2,282		2,282
4.40%		104.0	-	-	-	31,512		3,151		3,151
4.50%		110.0	41	23	-	97,482		9,748		9,752
Total							$	16,641	$	16,645
Subject to Mandatory Redemption - $100 Par:
5.90%		$100.0	22,500	-	-	50,000 (b)	$	5,000	$	7,250

(a)	The cumulative preferred stock is callable at the price indicated plus accrued dividends.
(b)	All outstanding shares were redeemed on January 3, 2005.

See Notes to Financial Statements of Registrant Subsidiaries.

OHIO POWER COMPANY CONSOLIDATED

SCHEDULE OF CONSOLDIATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
	(in thousands)
LONG-TERM DEBT:
First Mortgage Bonds	$	-		$	9,950
Installment Purchase Contracts		490,028			539,406
Senior Unsecured Notes		983,008			1,343,706
Notes Payable - Affiliated		400,000			-
Notes Payable - Nonaffiliated		138,024			146,878
Less Portion Due Within One Year		(12,354	)		(431,854	)
Long-term Debt Excluding Portion Due Within One Year	$	1,998,706		$	1,608,086

There are certain limitations on establishing additional liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

		2004		2003
% Rate	Due	(in thousands)
7.30	2024 - April 1	$	-	$	10,000
Unamortized Discount			-		(50	)
Total		$	-	$	9,950

Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004			2003
	% Rate	Due	(in thousands)
Mason County, West Virginia	5.4500	2016 - December 1	$	50,000		$	50,000
Marshall County, West Virginia	5.4500	2014 - July 1		50,000			50,000
	5.9000	2022 - April 1		35,000			35,000
	6.8500	2022 - June 1		-			50,000
	(a)	2022 - June 1		50,000			50,000
Ohio Air Quality Development Authority	5.1500	2026 - May 1		50,000			50,000
	5.5625	2022 - October 1		19,565			19,565
	5.5625	2023 - January 1		19,565			19,565
	(b)	2028 - April 1		40,000			40,000
	(c)	2028 - April 1		40,000			40,000
	6.3750	2029 - January 1 (d)		51,000			51,000
	6.3750	2029 - April 1 (d)		51,000			51,000
	(b)	2029 - April 1		18,000			18,000
	(c)	2029 - April 1		18,000			18,000
	Unamortized Discount			(2,102	)		(2,724	)
	Total		$	490,028		$	539,406

(a)	A floating interest rate is determined daily. The rate was 2.19% and 1.29% on December 31, 2004 and 2003, respectively.
(b)	A floating interest rate is determined weekly. The rate was 2.10% and 1.13% on December 31, 2004 and 2003, respectively. These bonds will be redeemed in March 2005 with proceeds from an issuance in January 2005.
(c)	A floating interest rate is determined weekly. The rate was 2.10% and 1.20% on December 31, 2004 and 2003, respectively. These bonds will be redeemed in March 2005 with proceeds from an issuance in January 2005.
(d)	These bonds were redeemed in February 2005 with proceeds from an issuance in January 2005.

Under the terms of the installment purchase contracts, OPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments range from monthly to semi-annually.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
6.750	2004 - July 1	$	-		$	100,000
7.000	2004 - July 1		-			75,000
6.730	2004 - November 1		-			48,000
6.240	2008 - December 4		37,225			37,225
7.375	2038 - June 30		-			140,000
5.500	2013 - February 15		250,000			250,000
4.850	2014 - January 15		225,000			225,000
6.600	2033 - February 15		250,000			250,000
6.375	2033 - July 15		225,000			225,000
Unamortized Discount			(4,217	)		(6,519	)
Total		$	983,008		$	1,343,706

Notes Payable to Parent were as follows:

		2004		2003
% Rate	Due	(in thousands)
3.32	2006 - May 15	$	200,000	$	-
5.25	2015 - June 1		200,000		-
Total		$	400,000	$	-

Notes Payable to third parties outstanding were as follows:

		2004		2003
% Rate	Due	(in thousands)
6.810	2008 - March 31	$	19,024	$	24,878
6.270	2009 - March 31		38,000		41,000
7.490	2009 - April 15		70,000		70,000
7.210	2009 - June 15		11,000		11,000
Total		$	138,024	$	146,878

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	12,354
2006		212,354
2007		17,853
2008		55,188
2009		77,500
Later Years		1,642,130
Total Principal Amount		2,017,379
Unamortized Discount		(6,319	)
Total	$	2,011,060

OHIO POWER COMPANY CONSOLIDATED

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to OPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Dispositions, Impairments, Assets Held for Sale and Assets Held and Used	Note 10
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Ohio Power Company:

We have audited the accompanying consolidated balance sheets of Ohio Power Company Consolidated as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company Consolidated as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” and EITF 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” effective January 1, 2003; FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003; and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

PUBLIC SERVICE COMPANY OF OKLAHOMA

PUBLIC SERVICE COMPANY OF OKLAHOMA

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003		2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	1,047,521	$	1,102,822	$	793,647	$	957,000	$	956,398
Operating Income		75,076		92,863		84,721		96,988		96,669
Interest Charges		37,957		44,784		40,422		39,249		38,980
Net Income		37,542		53,891		41,060		57,759		66,663
BALANCE SHEETS DATA
Electric Utility Plant	$	2,871,016	$	2,813,681	$	2,766,328	$	2,695,099	$	2,604,670
Accumulated Depreciation and Amortization		1,117,113		1,069,216		1,037,222		989,426		963,176
Net Electric Utility Plant	$	1,753,903	$	1,744,465	$	1,729,106	$	1,705,673	$	1,641,494
Total Assets	$	2,068,818	$	1,977,317	$	1,986,147	$	1,943,928	$	2,325,500
Common Shareholder's Equity		529,256		483,008		399,247		480,240		474,934
Cumulative Preferred Stock Not Subject to   Mandatory Redemption		5,262		5,267		5,267		5,267		5,267
Trust Preferred Securities (a)		-		-		75,000		75,000		75,000
Long-term Debt (b)		546,092		574,298		545,437		451,129		470,822
Obligations Under Capital Leases (b)		1,284		1,010		-		-		-

(a)	See “Trust Preferred Securities” section of Note 16.
(b)	Including portion due within one year.

PUBLIC SERVICE COMPANY OF OKLAHOMA

MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS

Public Service Company of Oklahoma (PSO) is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 509,000 retail customers in eastern and southwestern Oklahoma. As a power pool member with AEP West companies, we share in the revenues and expenses of the power pool’s sales to neighboring utilities and power marketers. PSO also sells electric power at wholesale to other utilities, municipalities and rural electric cooperatives.

Power pool members are compensated for energy delivered to other members based upon the delivering members’ incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

2004 Compared to 2003

Net Income decreased $16 million from the prior year primarily due to increased operations and maintenance expenses for power plant maintenance and transmission and distribution expenses.

Fluctuations occurring in the retail portion of fuel and purchased power expense generally do not impact operating income, as they are offset in revenues due to the functioning of the fuel clause adjustment in Oklahoma.

Operating Income

Operating Income for the year decreased $18 million primarily due to:

· A $24 million increase in Other Operation expenses. Transmission expense increased $11 million primarily related to prior years true-up for OATT transmission recorded in 2004 resulting from revised data from ERCOT for the years 2001-2003. Distribution expenses increased $7 million resulting mainly from a labor settlement and various inventory and tracking system upgrades. General and Administrative expense increased $8 million primarily due to outside services, mostly legal, and pension expense partially offset by the Medicare subsidy.

· A $10 million increase in Maintenance expenses primarily due to increased power plant maintenance and increased storm damage costs.

· A $4 million decrease in transmission revenues primarily due to a 2003 adjustment of nonaffiliated transactions.

· A $6 million increase in Taxes Other Than Income Taxes primarily due to increased property taxes of $4 million attributable to changes in property values. Also, state and local franchise taxes increased $2 million primarily due to a true-up of prior years recorded in 2003.

· A $3 million increase in Depreciation and Amortization expense primarily due to increases in depreciable plant.

· A $3 million decrease in miscellaneous revenue categories due to items such as reduced rental revenues, reduced miscellaneous service charges, and reduced wholesale base revenues as a result of the loss of one customer.

The decrease was partially offset by:

· A $28 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $7 million increase in off-system sales margins primarily due to the end of merger related mitigation sales losses in 2003.

Fuel and Purchased Power

Fuel expense decreased 18% due to lower KWH generated of 16%, offset by slightly higher cost per KWH of 3%. In addition, Fuel expenses were affected by a decrease in deferred fuel expense of $28 million. Purchased Power expense increased 26% due to a 15% increase of KWH purchased and higher cost per KWH of 18%.

Other Impacts on Earnings

Nonoperating Income decreased $7 million compared to the prior year period in large part due to a gain on the disposition of land recorded in 2003.

Nonoperating Income Tax Expense (Credit) decreased $2 million also due to the gain mentioned above. See Income Taxes section below for further discussion.

Interest Charges decreased $7 million compared to the prior year due the retirement of higher rate First Mortgage Bonds replaced by lower rate Senior Unsecured Notes and the retirement of $77 million of Trust Preferred Securities.

Income Taxes

The effective tax rates for 2004 and 2003 were 17.2% and 41.2%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is due primarily to an increase in favorable federal income tax adjustments and a decrease in state income taxes.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	A3	A-	A
Senior Unsecured Debt	Baa1	BBB	A-

In July 2004, Standard and Poor’s upgraded the credit rating of our First Mortgage Bonds from BBB to A- due to a change in rating methodology. The principal amount of First Mortgage Bonds currently outstanding is $50 million.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	50.0	$	50.0	$	50.0	$	396.4	$	546.4
Advances from Affiliates (b)		55.0		-		-		-		55.0
Capital Lease Obligations (c)		0.6		0.6		0.1		0.1		1.4
Noncancelable Operating Leases (c)		5.8		9.3		4.5		6.7		26.3
Fuel Purchase Contracts (d)		251.3		159.8		56.9		82.1		550.1
Energy and Capacity Purchase Contracts (e)		49.4		99.3		90.1		208.6		447.4
Total	$	412.1	$	319.0	$	201.6	$	693.9	$	1,626.6

(a)	See Schedule of Long-term Debt. Represents principal only excluding interest.
(b)	Represents short-term borrowings from the Utility Money Pool.
(c)	See Note 15.
(d)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(e)	Represents contractual cash flows of energy and capacity purchase contracts.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	14,057
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(1,007	)
Fair Value of New Contracts When Entered During the Period (b)		-
Net Option Premiums Paid/(Received) (c)		(187	)
Change in Fair Value Due to Valuation Methodology Changes (d)		-
Changes in Fair Value of Risk Management Contracts (e)		-
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		1,908
Total MTM Risk Management Contract Net Assets		14,771
Net Cash Flow Hedge Contracts (g)		(66	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	14,705

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	15,389		$	5,999		$	21,388
Noncurrent Assets		14,470			7			14,477
Total MTM Derivative Contract Assets		29,859			6,006			35,865
Current Liabilities		(8,034	)		(5,671	)		(13,705	)
Noncurrent Liabilities		(7,054	)		(401	)		(7,455	)
Total MTM Derivative Contract Liabilities		(15,088	)		(6,072	)		(21,160	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	14,771		$	(66	)	$	14,705

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(1,949	)	$	(70	)	$	980		$	-	$	-	$	-	$	(1,039	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		9,639			2,835			2,442			1,189		-		-		16,105
Prices Based on Models and Other Valuation Methods (b)		(335	)		(1,764	)		(1,853	)		425		1,313		1,919		(295	)
Total	$	7,355		$	1,001		$	1,569		$	1,614	$	1,313	$	1,919	$	14,771

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges.

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Year Ended December 31, 2004

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2003	$	156		$	-		$	156
Changes in Fair Value (a)		1,313			(600	)		713
Reclassifications from AOCI to Net Income (b)		(469	)		-			(469	)
Ending Balance December 31, 2004	$	1,000		$	(600	)	$	400

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,182 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$238	$778	$335	$115	$258	$1,004	$420	$100

VaR Associated with Debt Outstanding

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 $35 million and $66 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or financial position.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003		2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,036,831		$	1,079,692	$	784,208
Sales to AEP Affiliates		10,690			23,130		9,439
TOTAL		1,047,521			1,102,822		793,647
OPERATING EXPENSES
Fuel for Electric Generation		434,396			526,563		246,199
Purchased Energy for Resale		79,612			35,685		47,507
Purchased Electricity from AEP Affiliates		104,001			109,639		89,454
Other Operation		153,489			129,246		133,538
Maintenance		63,529			53,076		48,060
Depreciation and Amortization		89,711			86,455		85,896
Taxes Other Than Income Taxes		38,587			32,287		34,077
Income Taxes		9,120			37,008		24,195
TOTAL		972,445			1,009,959		708,926
OPERATING INCOME		75,076			92,863		84,721
Nonoperating Income		1,296			8,026		1,920
Nonoperating Expenses		2,184			1,385		6,971
Nonoperating Income Tax Expense (Credit)		(1,311	)		829		(1,812	)
Interest Charges		37,957			44,784		40,422
NET INCOME		37,542			53,891		41,060
Gain on Reacquired Preferred Stock		2			-		1
Preferred Stock Dividend Requirements		213			213		213
EARNINGS APPLICABLE TO COMMON STOCK	$	37,331		$	53,678	$	40,848

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	157,230	$	180,016	$	142,994		$	-		$	480,240
Gain on Reacquired Preferred Stock						1						1
Common Stock Dividends						(67,368	)					(67,368	)
Preferred Stock Dividends						(213	)					(213	)
TOTAL												412,660
COMPREHENSIVE LOSS
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $22									(42	)		(42	)
Minimum Pension Liability, Net of Tax of $29,309									(54,431	)		(54,431	)
NET INCOME						41,060						41,060
TOTAL COMPREHENSIVE LOSS												(13,413	)
DECEMBER 31, 2002		157,230		180,016		116,474			(54,473	)		399,247
Capital Contribution from Parent Company				50,000								50,000
Common Stock Dividends						(30,000	)					(30,000	)
Preferred Stock Dividends						(213	)					(213	)
Distribution of Investment in AEMT, Inc.   Preferred Shares to Parent Company						(548	)					(548	)
TOTAL												418,486
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $106									198			198
Minimum Pension Liability, Net of Tax of $5,649									10,433			10,433
NET INCOME						53,891						53,891
TOTAL COMPREHENSIVE INCOME												64,522
DECEMBER 31, 2003		157,230		230,016		139,604			(43,842	)		483,008
Gain on Reacquired Preferred Stock						2						2
Common Stock Dividends						(35,000	)					(35,000	)
Preferred Stock Dividends						(213	)					(213	)
TOTAL												447,797
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $131									244			244
Minimum Pension Liability, Net of Tax of $23,516									43,673			43,673
NET INCOME						37,542						37,542
TOTAL COMPREHENSIVE INCOME												81,459
DECEMBER 31, 2004	$	157,230	$	230,016	$	141,935		$	75		$	529,256

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

	2004			2003
ELECTRIC UTILITY PLANT	(in thousands)
Production	$	1,072,022		$	1,065,408
Transmission		468,735			458,577
Distribution		1,089,187			1,031,229
General		200,044			203,756
Construction Work in Progress		41,028			54,711
Total		2,871,016			2,813,681
Accumulated Depreciation and Amortization		1,117,113			1,069,216
TOTAL - NET		1,753,903			1,744,465
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		4,401			4,631
Other Investments		81			2,320
TOTAL		4,482			6,951
CURRENT ASSETS
Cash and Cash Equivalents		91			3,738
Other Cash Deposits		188			10,520
Accounts Receivable:
Customers		34,002			28,515
Affiliated Companies		46,399			19,852
Miscellaneous		6,984			-
Allowance for Uncollectible Accounts		(76	)		(37	)
Fuel Inventory		14,268			18,331
Materials and Supplies		35,485			38,118
Risk Management Assets		21,388			18,586
Regulatory Asset for Under-Recovered Fuel Costs		366			24,170
Margin Deposits		2,881			4,351
Prepayments and Other		1,378			2,655
TOTAL		163,354			168,799
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
Unamortized Loss on Reacquired Debt		14,705			14,357
Other		17,246			14,342
Long-term Risk Management Assets		14,477			10,379
Prepaid Pension Obligations		82,419			-
Deferred Charges and Other Assets		18,232			18,024
TOTAL		147,079			57,102
TOTAL ASSETS	$	2,068,818		$	1,977,317

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004		2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $15 Par Value Per Share:	$	157,230	$	157,230
Authorized - 11,000,000 Shares
Issued - 10,482,000 Shares
Outstanding - 9,013,000 Shares
Paid-in Capital		230,016		230,016
Retained Earnings		141,935		139,604
Accumulated Other Comprehensive Income (Loss)		75		(43,842	)
Total Common Shareholder’s Equity		529,256		483,008
Cumulative Preferred Stock Not Subject to Mandatory Redemption		5,262		5,267
Total Shareholders’ Equity		534,518		488,275
Long-term Debt:
Nonaffiliated		446,092		490,598
Affiliated		50,000		-
Total Long-term Debt		496,092		490,598
TOTAL		1,030,610		978,873
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		50,000		83,700
Advances from Affiliates		55,002		32,864
Accounts Payable:
General		71,442		48,808
Affiliated Companies		58,632		57,206
Customer Deposits		33,757		26,547
Taxes Accrued		18,835		27,157
Interest Accrued		4,023		3,706
Risk Management Liabilities		13,705		11,067
Obligations Under Capital Leases		537		452
Other		30,477		35,234
TOTAL		336,410		326,741
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		384,090		335,434
Long-term Risk Management Liabilities		7,455		3,602
Regulatory Liabilities:
Asset Removal Costs		220,298		214,033
Deferred Investment Tax Credits		28,620		30,411
SFAS 109 Regulatory Liability, Net		21,963		24,937
Other		19,676		15,406
Obligations Under Capital Leases		747		558
Deferred Credits and Other		18,949		47,322
TOTAL		701,798		671,703
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	2,068,818	$	1,977,317

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	37,542		$	53,891		$	41,060
Adjustments to Reconcile Net Income to Net Cash  Flows From   Operating Activities:
Depreciation and Amortization		89,711			86,455			85,896
Deferred Income Taxes		22,034			(14,641	)		75,659
Deferred Investment Tax Credits		(1,791	)		(1,791	)		(1,791	)
Mark-to-Market of Risk Management Contracts		(714	)		(10,511	)		(1,111	)
Fuel Recovery		23,804			52,300			(85,190	)
Pension Contribution		(48,701	)		(88	)		-
Change in Other Noncurrent Assets		(26,325	)		(9,646	)		3,273
Change in Other Noncurrent Liabilities		26,113			16,862			(20,097	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(38,979	)		(2,588	)		(3,737	)
Fuel, Materials and Supplies		6,696			899			996
Accounts Payable		24,060			(33,231	)		25,629
Taxes Accrued		(8,322	)		20,303			(11,296	)
Customer Deposits		7,210			4,758			748
Interest Accrued		317			(3,273	)		(319	)
Other Current Assets		2,746			(4,271	)		(366	)
Other Current Liabilities		(4,670	)		10,729			12,740
Net Cash Flows From Operating Activities		110,731			166,157			122,094
INVESTING ACTIVITIES
Construction Expenditures		(82,326	)		(86,815	)		(89,365	)
Change in Other Cash Deposits, Net		10,332			(3,289	)		(4,284	)
Proceeds from Sale of Assets		458			2,862			-
Other		-			-			963
Net Cash Flows Used For Investing Activities		(71,536	)		(87,242	)		(92,686	)
FINANCING ACTIVITIES
Capital Contributions from Parent Company		-			50,000			-
Issuance of Long-term Debt - Nonaffiliated		82,255			148,734			-
Issuance of Long-term Debt - Affiliated		50,000			-			187,850
Retirement of Long-term Debt - Nonaffiliated		(162,020	)		(200,000	)		(106,000	)
Retirement of Cumulative Preferred Stock		(2	)		-			-
Change in Advances to/from Affiliates, Net		22,138			(53,241	)		(36,982	)
Dividends Paid on Common Stock		(35,000	)		(30,000	)		(67,368	)
Dividends Paid on Cumulative Preferred Stock		(213	)		(213	)		(213	)
Net Cash Flows Used For Financing Activities		(42,842	)		(84,720	)		(22,713	)
Net Increase (Decrease) in Cash and Cash Equivalents		(3,647	)		(5,805	)		6,695
Cash and Cash Equivalents at Beginning of Period		3,738			9,543			2,848
Cash and Cash Equivalents at End of Period	$	91		$	3,738		$	9,543

SUPPLEMENTAL DISCLOSURE:

Cash paid (received) for interest net of capitalized amounts was $32,961,000, $44,703,000 and $38,620,000 and for income taxes was $2,387,000, $36,470,000 and $(38,943,000) in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $796,000. There was a noncash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO’s Parent Company in 2003.

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

						2004		2003
						(in thousands)
PREFERRED STOCK:
Cumulative $100 par value per share - authorized shares 700,000, redeemable at our option upon 30 days notice.
	Call Price	Number of Shares			Shares
	December 31,	Redeemed			Outstanding
Series	2004	Year Ended December 31,			December 31, 2004
		2004	2003	2002
Not subject to Mandatory Redemption:
4.00%	$105.75	50	2	6	44,548	$	4,455	$	4,460
4.24%	103.19	-	-	1	8,069		807		807
Total						$	5,262	$	5,267

See Notes to Financial Statements of Registrant Subsidiaries.

PUBLIC SERVICE COMPANY OF OKLAHOMA

SCHEDULE OF LONG-TERM DEBT

December 31, 2004 and 2003

(in thousands)

	2004			2003
	(in thousands)
LONG-TERM DEBT:
First Mortgage Bonds	$	49,970		$	99,864
Installment Purchase Contracts		46,360			47,358
Senior Unsecured Notes		399,762			349,756
Notes Payable to Trust (a)		-			77,320
Notes Payable - Affiliated		50,000			-
Less Portion Due Within One Year		(50,000	)		(83,700	)
Long-term Debt Excluding Portion Due Within One Year	$	496,092		$	490,598

(a) See “Trust Preferred Securities” section of Note 16 for discussion of Notes Payable to Trust.

There are certain limitations on establishing additional liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of our affiliates.

First Mortgage Bonds outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
7.375	2004 - December 1	$	-		$	50,000
6.500	2005 - June 1		50,000			50,000
Unamortized Discount			(30	)		(136	)
Total		$	49,970		$	99,864

First Mortgage Bonds are secured by a first mortgage lien on Electric Utility Plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with trustee, or in lieu thereof, certification of unfunded property additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004		2003
	% Rate	Due	(in thousands)
Oklahoma Environmental Finance  Authority (OEFA)	5.900	2007 - December 1	$	-	$	1,000
Oklahoma Development Finance  Authority (ODFA)	4.875	2014 - June 1		-		33,700
	Variable	2014 - June 1 (a)		33,700		-
Red River Authority of Texas	6.000	2020 - June 1		12,660		12,660
	Unamortized Discount			-		(2	)
	Total		$	46,360	$	47,358

(a) The interest rate on December 31, 2004 was 1.750%.

Under the terms of the installment purchase contracts, PSO is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants. Interest payments are made semi-annually.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
4.700	2009 - June 15	$	50,000		$	-
4.850	2010 - September 15		150,000			150,000
6.000	2032 - December 31		200,000			200,000
Unamortized Discount			(238	)		(244	)
Total		$	399,762		$	349,756

Notes Payable to Trust was outstanding as follows:

		2004		2003
% Rate	Due	(in thousands)
8.000	2037 - April 30	$	-	$	77,320

See “Trust Preferred Securities” section of Note 16 for discussion of Notes Payable to Trust.

Notes Payable to parent company was as follows:

		2004		2003
% Rate	Due	(in thousands)
3.350	2006 - May 15	$	50,000	$	-

At December 31, 2004, future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	50,000
2006		50,000
2007		-
2008		-
2009		50,000
Later Years		396,360
Total Principal Amount		546,360
Unamortized Discount		(268	)
Total	$	546,092

PUBLIC SERVICE COMPANY OF OKLAHOMA

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to PSO’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Rate Matters	Note 4
Effects of Regulation	Note 5
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Jointly-Owned Electric Utility Plant	Note 18
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Public Service Company of Oklahoma:

We have audited the accompanying balance sheets of Public Service Company of Oklahoma as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003 and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands)

	2004		2003		2002		2001		2000
STATEMENTS OF INCOME DATA
Operating Revenues	$	1,087,346	$	1,146,842	$	1,084,720	$	1,101,326	$	1,118,274
Operating Income		143,178		150,136		142,469		146,207		128,278
Interest Charges		53,529		63,779		59,168		57,581		59,457
Income Before Cumulative Effect of  Accounting Changes		89,457		89,624		82,992		89,367		72,672
Cumulative Effect of Accounting  Changes, Net of Tax		-		8,517		-		-		-
Net Income		89,457		98,141		82,992		89,367		72,672
BALANCE SHEETS DATA
Electric Utility Plant	$	3,887,367	$	3,799,460	$	3,596,174	$	3,460,764	$	3,319,024
Accumulated Depreciation and  Amortization		1,709,758		1,617,846		1,477,875		1,342,003		1,259,509
Net Electric Utility Plant	$	2,177,609	$	2,181,614	$	2,118,299	$	2,118,761	$	2,059,515
Total Assets	$	2,646,309	$	2,581,963	$	2,428,138	$	2,509,291	$	2,855,885
Common Shareholder's Equity		768,618		696,660		661,769		689,578		674,652
Cumulative Preferred Stock Not Subject to   Mandatory Redemption		4,700		4,700		4,701		4,701		4,701
Trust Preferred Securities (a)		-		-		110,000		110,000		110,000
Long-term Debt (b)		805,369		884,308		693,448		645,283		645,963
Obligations Under Capital Leases (b)		34,546		21,542		-		-		-

(a)	See “Trust Preferred Securities” section of Note 16.
(b)	Including portion due within one year.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 444,000 retail customers in our service territory in northeastern Texas, northwestern Louisiana and western Arkansas. We consolidate Southwest Arkansas Utilities Corporation and Dolet Hills Lignite Company, LLC, our wholly-owned subsidiaries. We also consolidate Sabine Mining Company, a variable interest entity. As a power pool member with AEP West companies, we share in the revenues and expenses of the power pool’s sales to neighboring utilities and power marketers. We also sell electric power at wholesale to other utilities, municipalities and electric cooperatives.

Power pool members are compensated for energy delivered to other members based upon the delivering members’ incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. The revenue and costs for sales to neighboring utilities and power marketers made by AEPSC on behalf of the AEP West companies are shared among the members based upon the relative magnitude of the energy each member provides to make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC. We share in the revenues and expenses associated with these risk management activities with other Registrant Subsidiaries excluding AEGCo under existing power pool and system integration agreements. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas. The electricity and gas contracts include physical transactions, over-the-counter options and financially-settled swaps and exchange-traded futures and options. The majority of the physical forward contracts are typically settled by entering into offsetting contracts.

Under our system integration agreement, revenues and expenses from the sales to neighboring utilities, power marketers and other power and gas risk management entities are shared among AEP East and West companies. Sharing in a calendar year is based upon the level of such activities experienced for the twelve months ended June 30, 2000, which immediately preceded the merger of AEP and CSW. This resulted in an AEP East and West companies’ allocation of approximately 91% and 9%, respectively, for revenues and expenses. Allocation percentages in any given calendar year may also be based upon the relative generating capacity of the AEP East and West companies in the event the pre-merger activity level is exceeded. The capacity based allocation mechanism was triggered in July 2004 and June 2003, resulting in an allocation factor of approximately 70% and 30% for the AEP East and West companies, respectively, for the remainder of the respective year. In 2002, the capacity based allocation mechanism was not triggered.

We are jointly and severally liable for activity conducted by AEPSC on the behalf of AEP East and West companies and activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Results of Operations

Net Income decreased $9 million for 2004. The decrease is primarily due to the $9 million (net of tax) Cumulative Effect of Accounting Changes recorded in 2003.

Net Income increased $15 million for 2003 primarily due to an $8 million increase in Operating Income and the adoption of SFAS 143, which resulted in Cumulative Effect of Accounting Changes of $9 million in the first quarter of 2003. Significant fluctuations occurred in revenues, fuel and purchased power due to certain Interchange Cost Reconstruction (ICR) adjustments in 2002; however, income is generally not affected due to the functioning of fuel adjustment clauses in the retail jurisdictions.

Fluctuations occurring in the retail portion of fuel and purchased power expense, except for capacity related items, generally do not impact operating income, as they are offset in revenues and/or operations expense due to the functioning of the fuel adjustment clauses in the states in which we serve.

2004 Compared to 2003

Operating Income

Operating Income decreased by $7 million primarily due to:

· A $14 million increase in Other Operation expenses primarily related to a prior year true-up for OATT transmission recorded in 2004 resulting from revised data from ERCOT for the years 2001-2003 offset in part by the sale of emission allowances.

· A $10 million increase in Taxes Other Than Income Taxes primarily due to higher franchise taxes of $8 million resulting from a true-up of prior years recorded in 2003 and higher property related taxes.

· An $8 million increase in Depreciation and Amortization expenses primarily due to the amortization of a regulatory asset for the recovery of fuel related costs in Arkansas established in 2003 by a credit to amortization and adjustments to excess earnings accruals per the Texas Restructuring Legislation (see “Texas Restructuring” and “Unrefunded Excess Earnings” in Note 6). Also, depreciation increased due to increases in depreciable plant.

· A $5 million decrease in margins from risk management activities.

· A $4 million increase in Maintenance expenses primarily due to scheduled power plant maintenance, as well as increased overhead line maintenance.

· A $4 million decrease in the portion of margin the company retains from off-system sales primarily due to decreased realization on off-system sales.

· A $2 million decrease in retail base revenues due to a decline of 5% in heating and cooling degree-days.

The decrease in Operating Income was partially offset by:

· An $18 million decrease in Income Taxes. See Income Taxes section below for further discussion.

· A $2 million decrease in provision for rate refund primarily due to a wholesale fuel refund in 2003.

Fuel and Purchased Power

Fuel expense decreased 12% primarily due to lower KWH generation of 2% and lower cost per KWH of 8%. Purchased power expense decreased 22% in large part due to decreased capacity purchases reflecting a $9 million refund received for prior year purchased capacity amounts. Capacity related transactions are not included in the fuel adjustment clauses, and therefore, changes impact operating income.

Other Impacts on Earnings

Interest Charges decreased $10 million as a result of refinancing higher interest rate debt with lower interest rate debt.

The increase in Minority Interest expense of $2 million is a result of consolidating Sabine Mining Company (Sabine), effective July 1, 2003, due to implementation of FIN 46. We now record the depreciation, interest and other operating expenses of Sabine and eliminate Sabine’s revenues against our fuel expenses. While there was no effect to net income as a result of consolidation, some individual income statement lines were affected.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to a one-time after tax impact of adopting SFAS 143 and EITF 02-3 in 2003 (see Note 2).

Income Taxes

The effective tax rates for 2004 and 2003 were 28% and 36.3%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The decrease in the effective tax rate for the comparative period is primarily due to federal income tax adjustments, a decrease in state income taxes and permanent differences relating primarily to a Medicare subsidy credit.

2003 Compared to 2002

Operating Income

Operating Income increased by $8 million primarily due to:

· A $12 million increase in retail base revenues due to increased customers and their average usage, offset in part by milder weather. Heating cooling degree-days declined 6%.

· A $12 million increase in wholesale margins due to an increase in our allocation of overall AEP off-system sales percentages resulting from increased amounts of off-system sales.

· An $11 million decrease in Other Operation expenses primarily due to decreases in customer services, outside services and other administrative expenses.

· A $7 million increase in income from risk management activities.

The increase in Operating Income was partially offset by:

· A $21 million increase in Income Taxes. See Income Taxes section below for further discussion.

· A $9 million decrease in wholesale base margins primarily due to decreased demand from wholesale customers.

· A $4 million decrease in capacity revenues due to the elimination of the requirement under the Texas Restructuring Legislation to sell capacity (see Note 6).

Other Impacts on Earnings

Nonoperating Income Tax Expense (Credit) increased by $5 million due to changes in certain book/tax timing differences accounted for on a flow-through basis, changes in consolidated tax savings and tax return and tax accrual adjustments.

Interest Charges increased $5 million primarily due to higher levels of outstanding debt, consolidation of Sabine and increased financing activity at Dolet Hills.

The increase in Minority Interest expense of $2 million is a result of consolidating Sabine effective July 1, 2003, due to implementation of FIN 46. We now record the depreciation, interest and other operating expenses of Sabine and eliminate Sabine’s revenues against our fuel expenses. While there was no effect to net income as a result of consolidation, some individual income statement lines were affected.

Cumulative Effect of Accounting Changes

The Cumulative Effect of Accounting Changes is due to the one-time, after tax impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 in 2003 (see Note 2).

Income Taxes

The effective tax rates for 2003 and 2002 were 36.3% and 29.9%, respectively. The difference in the effective income tax rate and the federal statutory rate of 35% is due to permanent differences, amortization of investment tax credits, consolidated tax savings from Parent, state income taxes and federal income tax adjustments. The increase in the effective tax rate for the comparative period is primarily due to an increase in state income taxes and permanent differences relating primarily to book depletion.

Financial Condition

Credit Ratings

The rating agencies currently have us on stable outlook. Current ratings are as follows:

	Moody’s	S&P	Fitch
First Mortgage Bonds	A3	A-	A
Senior Unsecured Debt	Baa1	BBB	A-

In July 2004, Standard and Poor’s upgraded the credit rating of the First Mortgage Bonds from BBB to A- due to a change in rating methodology. The principal amount of First Mortgage Bonds currently outstanding is $96 million.

Cash Flow

Cash flows for the years ended December 31, 2004, 2003 and 2002 were as follows:

	2004			2003			2002
	(in thousands)
Cash and cash equivalents at beginning of period	$	5,676		$	-		$	5,023
Cash flows from (used for):
Operating activities		209,734			248,094			210,563
Investing activities		(97,933	)		(114,828	)		(112,318	)
Financing activities		(115,169	)		(127,590	)		(103,268	)
Net increase (decrease) in cash and cash equivalents		(3,368	)		5,676			(5,023	)
Cash and cash equivalents at end of period	$	2,308		$	5,676		$	-

Operating Activities

Our net cash flows from operating activities were $210 million in 2004. We produced income of $89 million during the period and noncash expense items of $129 million for Depreciation and Amortization. Change in Pension Contribution of $46 million is due to the pension plan funding. The 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 working capital relates to a number of items; the most significant are Accounts Receivable, Net, Fuel, Materials and Supplies and Taxes Accrued. Accounts Receivable, Net increased related to increased affiliated energy purchases. The decrease in Fuel, Materials and Supplies is primarily due to lower purchases of fuel. During 2004, we did not make any federal income tax payments for our 2004 federal income tax liability since the AEP Consolidated tax group was not required to make any 2004 quarterly estimated federal income tax payments. Payment will be made in March 2005 when the 2004 federal income tax return extension is filed.

Our net cash flows from operating activities were $248 million in 2003. We produced income of $98 million during the period and noncash expense items of $121 million for Depreciation and Amortization and $9 million for Cumulative Effect of Accounting Changes. The 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 working capital relates to a number of items; the most significant were Accounts Receivable, Net and Accounts Payable. Accounts Receivable, Net decreased primarily due to prior year adjustments to the interchange cost reconstruction system and lower affiliated energy purchases. The decrease in Accounts Payable was related to lower fuel purchases.

Our net cash flows from operating activities were $211 million in 2002. We produced income of $83 million during the period and noncash expense items of $123 million for Depreciation and Amortization. The 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 working capital relates to a number of items; the most significant were Accounts Receivable, Net, Fuel, Materials and Supplies and Taxes Accrued. Accounts Receivable, Net decreased primarily due to an adjustment to the interchange cost reconstruction system. Fuel, Materials and Supplies increased due to higher coal purchases. Taxes accrued increased due to higher income taxes offset in part by state and local franchise taxes.

Investing Activities

Cash flows used for investing activities during 2004, 2003 and 2002 were $98 million, $115 million and $112 million, respectively. They were comprised primarily of Construction Expenditures related to projects for improved transmission and distribution service reliability.

Financing Activities

Cash flows used for financing activities were $115 million during 2004. During the first and second quarter, we retired $80 million and $40 million of First Mortgage Bonds, respectively. Three Installment Purchase Contracts were retired for Titus County with fixed interest rates in the second quarter totaling $41 million which were replaced by one Installment Purchase Contract with a variable interest rate for $41 million. During the third quarter of 2004, we issued a Note Payable to AEP for $50 million. Common Stock Dividends were $60 million.

Cash flows used for financing activities were $128 million during 2003. During the first quarter of 2003, we retired $55 million of First Mortgage Bonds at maturity. In April 2003, we issued $100 million of Senior Unsecured Notes due 2015 at a coupon of 5.375%. In May 2003, one of our mining subsidiaries issued $44 million of notes due in 2011 at a coupon of 4.47%. The loan was used primarily to reduce a note to us with an interest rate of 8.06%. During the fourth quarter of 2003, we had an early redemption of $45 million of First Mortgage Bonds due in 2023. Common Stock dividends were $73 million.

Cash flows used for financing activities were $103 million for 2002. During the first quarter of 2002, we retired Senior Unsecured Notes of $150 million. We issued $200 million of Senior Unsecured Notes in the second quarter of 2002. Common stock dividends were $57 million.

Summary Obligation Information

Our contractual obligations include amounts reported on the Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes our contractual cash obligations at December 31, 2004:

Payment Due by Period

(in millions)

Contractual Cash Obligations	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Long-term Debt (a)	$	210.0	$	118.1	$	11.0	$	465.6	$	804.7
Capital Lease Obligations (b)		6.2		11.9		11.3		20.5		49.9
Noncancelable Operating Leases (b)		6.8		14.8		17.1		10.6		49.3
Fuel Purchase Contracts (c)		198.4		355.7		232.8		472.3		1,259.2
Energy and Capacity Purchase Contracts (d)		27.9		56.1		50.9		117.9		252.8
Total	$	449.3	$	556.6	$	323.1	$	1,086.9	$	2,415.9

(a)	See Schedule of Consolidated Long-term Debt. Represents principal only excluding interest.
(b)	See Note 15.
(c)	Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.
(d)	Represents contractual cash flows of energy and capacity purchase contracts.

In addition to the amounts disclosed in the contractual cash obligations table above, we make additional commitments in the normal course of business. Our commitments outstanding at December 31, 2004 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period

(in millons)

Other Commercial Commitments	Less Than 1 year		2-3 years		4-5 years		After 5 years		Total
Standby Letters of Credit (a)	$	4.0	$	-	$	-	$	-	$	4.0
Guarantees of the Performance of
Outside Parties (b)		10.5		-		22.0		105.0		137.5
Total	$	14.5	$	-	$	22.0	$	105.0	$	141.5

(a)

We have issued standby letters of credit to third parties. These letters of credit cover insurance programs, security deposits, debt service reserves and credit enhancements for issued bonds. All of these letters of credit were issued in our ordinary course of business. The maximum future payments of these letters of credit are $4.0 million maturing in December 2005. There is no recourse to third parties in the event these letters of credit are drawn.

(b)

See Note 8.

Other

On July 1, 2003, we consolidated Sabine due to the application of FIN 46 (see Note 2). Upon consolidation, we recorded the assets and liabilities of Sabine ($78 million). Also, after consolidation, we currently record all expenses (depreciation, interest and other operation expense) of Sabine and eliminate Sabine’s revenues against our fuel expenses. There is no cumulative effect of an accounting change recorded as a result of the requirement to consolidate, and there is no change in net income due to the consolidation of Sabine.

Significant Factors

See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of factors relevant to us.

Critical Accounting Estimates

See “Critical Accounting Estimates” section in “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” for a discussion of the estimates and judgments required for revenue recognition, the valuation of long-lived assets, pension benefits, income taxes, and the impact of new accounting pronouncements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

Our risk management policies and procedures are instituted and administered at the AEP Consolidated level. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on us.

MTM Risk Management Contract Net Assets

This table provides detail on changes in our MTM net asset or liability balance sheet position from one period to the next.

MTM Risk Management Contract Net Assets

Year Ended December 31, 2004

(in thousands)

Total MTM Risk Management Contract Net Assets at December 31, 2003	$	16,606
(Gain) Loss from Contracts Realized/Settled During the Period (a)		(4,481	)
Fair Value of New Contracts When Entered During the Period (b)		743
Net Option Premiums Paid/(Received) (c)		(221	)
Change in Fair Value Due to Valuation Methodology Changes (d)		62
Changes in Fair Value of Risk Management Contracts (e)		3,008
Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)		1,810
Total MTM Risk Management Contract Net Assets		17,527
Net Cash Flow Hedge Contracts (g)		(2,704	)
Total MTM Risk Management Contract Net Assets at December 31, 2004	$	14,823

(a)	“(Gain) Loss from Contracts Realized/Settled During the Period” includes realized risk management contracts and related derivatives that settled during 2004 where we entered into the contract prior to 2004.
(b)	“Fair Value of New Contracts When Entered During the Period” represents the fair value at inception of long-term contracts entered into with customers during 2004. 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.
(c)	“Net Option Premiums Paid/(Received)” reflects the net option premiums paid/(received) as they relate to unexercised and unexpired option contracts that were entered in 2004.
(d)	“Change in Fair Value Due to Valuation Methodology Changes” represents the impact of AEP changes in methodology in regards to credit reserves on forward contracts.
(e)	“Changes in Fair Value of Risk Management Contracts” represents the fair value change in the risk management portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(f)	“Change in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets for those subsidiaries that operate in regulated jurisdictions.
(g)	“Net Cash Flow Hedge Contracts” (pretax) are discussed below in Accumulated Other Comprehensive Income (Loss).

Reconciliation of MTM Risk Management Contracts to

Consolidated Balance Sheets

As of December 31, 2004

(in thousands)

	MTM Risk Management Contracts (a)			Cash Flow Hedges			Total (b)
Current Assets	$	18,260		$	7,119		$	25,379
Noncurrent Assets		17,170			9			17,179
Total MTM Derivative Contract Assets		35,430			7,128			42,558
Current Liabilities		(9,533	)		(9,074	)		(18,607	)
Noncurrent Liabilities		(8,370	)		(758	)		(9,128	)
Total MTM Derivative Contract Liabilities		(17,903	)		(9,832	)		(27,735	)
Total MTM Derivative Contract Net Assets (Liabilities)	$	17,527		$	(2,704	)	$	14,823

(a)	Does not include Cash Flow Hedges.
(b)	Represents amount of total MTM derivative contracts recorded within Risk Management Assets, Long-term Risk Management Assets, Risk Management Liabilities and Long-term Risk Management Liabilities on our Consolidated Balance Sheets.

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

The table presenting maturity and source of fair value of MTM risk management contract net assets provides two fundamental pieces of information:

· The source of 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

Fair Value of Contracts as of December 31, 2004

(in thousands)

	2005			2006			2007			2008		2009		After 2009		Total (c)
Prices Actively Quoted - Exchange Traded Contracts	$	(2,313	)	$	(84	)	$	1,163		$	-	$	-	$	-	$	(1,234	)
Prices Provided by Other External  Sources - OTC Broker Quotes (a)		11,438			3,364			2,898			1,411		-		-		19,111
Prices Based on Models and Other Valuation Methods (b)		(398	)		(2,092	)		(2,199	)		504		1,558		2,277		(350	)
Total	$	8,727		$	1,188		$	1,862		$	1,915	$	1,558	$	2,277	$	17,527

(a)	“Prices Provided by Other External Sources - OTC Broker Quotes” reflects information obtained from over-the-counter brokers, industry services, or multiple-party on-line platforms.
(b)	“Prices Based on Models and Other Valuation Methods” is used in 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 are 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 varies by market.
(c)	Amounts exclude Cash Flow Hedges.

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

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

We employ cash flow hedges to mitigate changes in interest rates or fair values on short-term and long-term debt when management deems it necessary. We do not hedge all interest rate risk.

The table provides detail on effective cash flow hedges under SFAS 133 included in the Consolidated Balance Sheets. The data in the table will indicate the magnitude of SFAS 133 hedges we have in place. Under SFAS 133, only contracts designated as cash flow hedges are recorded in AOCI; therefore, economic hedge contracts which are not designated as cash flow hedges are required to be marked-to-market and are included in the previous risk management tables. In accordance with GAAP, all amounts are presented net of related income taxes.

Total Accumulated Other Comprehensive Income (Loss) Activity

Years Ended December 31, 2004

(in thousands)

	Power			Interest Rate			Total
Beginning Balance December 31, 2003	$	184		$	-		$	184
Changes in Fair Value (a)		1,558			(2,008	)		(450	)
Reclassifications from AOCI to Net Income (b)		(554	)		-			(554	)
Ending Balance December 31, 2004	$	1,188		$	(2,008	)	$	(820	)

(a)	“Changes in Fair Value” shows changes in the fair value of derivatives designated as cash flow hedges during the reporting period that are not yet settled at December 31, 2004. Amounts are reported net of related income taxes.
(b)	“Reclassifications from AOCI to Net Income” represents gains or losses from derivatives used as hedging instruments in cash flow hedges that were reclassified into net income during the reporting period. Amounts are reported net of related income taxes.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1,413 thousand gain.

Credit Risk

Our counterparty credit quality and exposure is generally consistent with that of AEP.

VaR Associated with Risk Management Contracts

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

December 31, 2004				December 31, 2003
(in thousands)				(in thousands)
End	High	Average	Low	End	High	Average	Low
$283	$923	$398	$136	$304	$1,182	$495	$118

VaR Associated with Debt Outstanding

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 $31 million and $57 million at December 31, 2004 and 2003, respectively. 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 negatively affect our results of operations or consolidated financial position.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF INCOME

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING REVENUES
Electric Generation, Transmission and Distribution	$	1,016,156		$	1,077,988		$	1,012,391
Sales to AEP Affiliates		71,190			68,854			72,329
TOTAL		1,087,346			1,146,842			1,084,720
OPERATING EXPENSES
Fuel for Electric Generation		387,554			440,080			391,355
Purchased Energy for Resale		35,521			34,850			44,119
Purchased Electricity from AEP Affiliates		29,054			47,914			42,022
Other Operation		188,601			174,714			186,003
Maintenance		74,091			70,443			66,855
Depreciation and Amortization		129,329			121,072			122,969
Taxes Other Than Income Taxes		63,560			53,165			55,232
Income Taxes		36,458			54,468			33,696
TOTAL		944,168			996,706			942,251
OPERATING INCOME		143,178			150,136			142,469
Nonoperating Income		4,337			3,978			3,260
Nonoperating Expenses		3,030			2,607			1,797
Nonoperating Income Tax Expense (Credit)		(1,731	)		(3,396	)		1,772
Interest Charges		53,529			63,779			59,168
Minority Interest		(3,230	)		(1,500	)		-
Income Before Cumulative Effect of Accounting Changes		89,457			89,624			82,992
Cumulative Effect of Accounting Changes, Net of Tax		-			8,517			-
NET INCOME		89,457			98,141			82,992
Preferred Stock Dividend Requirements		229			229			229
EARNINGS APPLICABLE TO COMMON STOCK	$	89,228		$	97,912		$	82,763

The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S

EQUITY AND COMPREHENSIVE INCOME (LOSS)

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	Common Stock		Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2001	$	135,660	$	245,003	$	308,915		$	-		$	689,578
Common Stock Dividends						(56,889	)					(56,889	)
Preferred Stock Dividends						(229	)					(229	)
TOTAL												632,460
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $26									(48	)		(48	)
Minimum Pension Liability, Net of Tax of $28,880									(53,635	)		(53,635	)
NET INCOME						82,992						82,992
TOTAL COMPREHENSIVE INCOME												29,309
DECEMBER 31, 2002		135,660		245,003		334,789			(53,683	)		661,769
Common Stock Dividends						(72,794	)					(72,794	)
Preferred Stock Dividends						(229	)					(229	)
TOTAL												588,746
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $125									232			232
Minimum Pension Liability, Net of Tax of $5,138									9,541			9,541
NET INCOME						98,141						98,141
TOTAL COMPREHENSIVE INCOME												107,914
DECEMBER 31, 2003		135,660		245,003		359,907			(43,910	)		696,660
Common Stock Dividends						(60,000	)					(60,000	)
Preferred Stock Dividends						(229	)					(229	)
TOTAL												636,431
COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax of $541									(1,004	)		(1,004	)
Minimum Pension Liability, Net of Tax of $23,550									43,734			43,734
NET INCOME						89,457						89,457
TOTAL COMPREHENSIVE INCOME												132,187
DECEMBER 31, 2004	$	135,660	$	245,003	$	389,135		$	(1,180	)	$	768,618

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

ASSETS

December 31, 2004 and 2003

(in thousands)

	2004			2003
ELECTRIC UTILITY PLANT
Production	$	1,663,161		$	1,622,498
Transmission		632,964			615,158
Distribution		1,114,480			1,078,368
General		427,910			423,427
Construction Work in Progress		48,852			60,009
Total		3,887,367			3,799,460
Accumulated Depreciation and Amortization		1,709,758			1,617,846
TOTAL - NET		2,177,609			2,181,614
OTHER PROPERTY AND INVESTMENTS
Nonutility Property, Net		4,049			3,808
Other Investments		4,628			4,710
TOTAL		8,677			8,518
CURRENT ASSETS
Cash and Cash Equivalents		2,308			5,676
Other Cash Deposits		6,292			6,048
Advances to Affiliates		39,106			66,476
Accounts Receivable:
Customers		39,042			41,474
Affiliated Companies		28,817			10,394
Miscellaneous		5,856			4,682
Allowance for Uncollectible Accounts		(45	)		(2,093	)
Fuel Inventory		45,793			63,881
Materials and Supplies		36,051			33,772
Risk Management Assets		25,379			19,715
Regulatory Asset for Under-Recovered Fuel Costs		4,687			11,394
Margin Deposits		3,419			5,123
Prepayments and Other		18,331			19,078
TOTAL		255,036			285,620
DEFERRED DEBITS AND OTHER ASSETS
Regulatory Assets:
SFAS 109 Regulatory Asset, Net		18,000			3,235
Unamortized Loss on Reacquired Debt		20,765			19,331
Other		16,350			15,859
Long-term Risk Management Assets		17,179			12,178
Prepaid Pension Obligations		81,132			-
Deferred Charges		51,561			55,608
TOTAL		204,987			106,211
TOTAL ASSETS	$	2,646,309		$	2,581,963

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

December 31, 2004 and 2003

	2004			2003
CAPITALIZATION	(in thousands)
Common Shareholder’s Equity:
Common Stock - $18 Par Value per share
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares	$	135,660		$	135,660
Paid-in Capital		245,003			245,003
Retained Earnings		389,135			359,907
Accumulated Other Comprehensive Loss		(1,180	)		(43,910	)
Total Common Shareholder’s Equity		768,618			696,660
Cumulative Preferred Stock Not Subject to Mandatory Redemption		4,700			4,700
Total Shareholders’ Equity		773,318			701,360
Long-term Debt:
Nonaffiliated		545,395			741,594
Affiliated		50,000			-
Total Long-term Debt		595,395			741,594
TOTAL		1,368,713			1,442,954
Minority Interest		1,125			1,367
CURRENT LIABILITIES
Long-term Debt Due Within One Year - Nonaffiliated		209,974			142,714
Accounts Payable:
General		40,001			37,646
Affiliated Companies		33,285			35,138
Customer Deposits		30,550			24,260
Taxes Accrued		45,474			28,691
Interest Accrued		12,509			16,852
Risk Management Liabilities		18,607			11,361
Obligations Under Capital Leases		3,692			3,159
Regulatory Liability for Over-Recovered Fuel		9,891			4,178
Other		33,417			53,753
TOTAL		437,400			357,752
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred Income Taxes		399,756			349,064
Long-term Risk Management Liabilities		9,128			4,667
Reclamation Reserve		7,624			16,512
Regulatory Liabilities:
Asset Removal Costs		249,892			236,409
Deferred Investment Tax Credits		35,539			39,864
Excess Earnings		3,167			2,600
Other		21,320			18,779
Asset Retirement Obligations		27,361			8,429
Obligations Under Capital Leases		30,854			18,383
Deferred Credits and Other		54,430			85,183
TOTAL		839,071			779,890
Commitments and Contingencies (Note 7)
TOTAL CAPITALIZATION AND LIABILITIES	$	2,646,309		$	2,581,963

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31, 2004, 2003 and 2002

(in thousands)

	2004			2003			2002
OPERATING ACTIVITIES
Net Income	$	89,457		$	98,141		$	82,992
Adjustments to Reconcile Net Income to Net Cash Flows From   Operating Activities:
Depreciation and Amortization		129,329			121,072			122,969
Deferred Income Taxes		12,782			9,942			(3,134	)
Deferred Investment Tax Credits		(4,326	)		(4,326	)		(4,524	)
Cumulative Effect of Accounting Changes		-			(8,517	)		-
Mark-to-Market of Risk Management Contracts		(921	)		(12,403	)		(1,151	)
Fuel Recovery		12,420			(21,577	)		17,713
Pension Contribution		(45,688	)		(805	)		-
Change in Other Noncurrent Assets		(21,251	)		22,507			23,570
Change in Other Noncurrent Liabilities		37,014			47,834			(762	)
Changes in Components of Working Capital:
Accounts Receivable, Net		(19,213	)		27,527			(24,371	)
Fuel, Materials and Supplies		15,809			4,168			(10,541	)
Accounts Payable		502			(51,687	)		11,633
Taxes Accrued		16,783			8,446			(17,441	)
Customer Deposits		6,290			4,150			230
Interest Accrued		(4,343	)		(761	)		4,024
Other Current Assets		2,452			(6,242	)		865
Other Current Liabilities		(17,362	)		10,625			8,491
Net Cash Flows From Operating Activities		209,734			248,094			210,563
INVESTING ACTIVITIES
Construction Expenditures		(103,124	)		(121,124	)		(111,775	)
Change in Other Cash Deposits, Net		(244	)		(3,979	)		(1,677	)
Proceeds from Sale of Assets		5,435			3,800			-
Other		-			6,475			1,134
Net Cash Flows Used For Investing Activities		(97,933	)		(114,828	)		(112,318	)
FINANCING ACTIVITIES
Issuance of Long-term Debt - Nonaffiliated		91,999			254,630			198,573
Issuance of Long-term Debt - Affiliated		50,000			-			-
Retirement of Long-term Debt		(224,309	)		(219,482	)		(150,595	)
Change in Advances to/from Affiliates, Net		27,370			(89,715	)		(94,128	)
Dividends Paid on Common Stock		(60,000	)		(72,794	)		(56,889	)
Dividends Paid on Cumulative Preferred Stock		(229	)		(229	)		(229	)
Net Cash Flows Used For Financing Activities		(115,169	)		(127,590	)		(103,268	)
Net Increase (Decrease) in Cash and Cash Equivalents		(3,368	)		5,676			(5,023	)
Cash and Cash Equivalents at Beginning of Period		5,676			-			5,023
Cash and Cash Equivalents at End of Period	$	2,308		$	5,676		$	-

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $49,739,000, $57,775,000 and $49,008,000 and for income taxes was $11,326,000, $33,616,000 and $60,451,000 in 2004, 2003 and 2002, respectively. Noncash capital lease acquisitions in 2004 were $16,549,000. Noncash activity in 2003 included an increase in assets and liabilities of $78 million resulting from the consolidation of Sabine Mining Company (see “Consolidation of Variable Interest Entities” section of Note 2).

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SCHEDULE OF PREFERRED STOCK

December 31, 2004 and 2003

						2004		2003
						(in thousands)
PREFERRED STOCK:
$100 Par Value per share - Authorized 1,860,000 shares
	Call Price	Number of Shares			Shares
	December 31,	Redeemed			Outstanding
Series	2004	Year Ended December 31,			December 31, 2004
		2004	2003	2002
Not Subject to Mandatory Redemption - $100 Par:
4.28%	$103.90	-	-	-	7,386	$	740	$	740
4.65%	102.75	-	-	-	1,907		190		190
5.00%	109.00	-	12	-	37,703		3,770		3,770
Total						$	4,700	$	4,700

See Notes to Financial Statements of Registrant Subsidiaries.

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

SCHEDULE OF CONSOLIDATED LONG-TERM DEBT

December 31, 2004 and 2003

	2004			2003
LONG-TERM DEBT:	(in thousands)
First Mortgage Bonds	$	96,024		$	215,712
Installment Purchase Contracts		177,879			178,531
Senior Unsecured Notes		299,686			299,216
Notes Payable to Trust (a)		113,019			113,009
Notes Payable - Nonaffiliated		68,761			77,840
Notes Payable - Affiliated		50,000			-
Less Portion Due Within One Year		(209,974	)		(142,714	)
Long-term Debt Excluding Portion Due Within One Year	$	595,395		$	741,594

(a) See “Trust Preferred Securities” section of Note 16 for discussion of Notes Payable to Trust.

There are certain limitations on establishing additional liens against our assets under our indenture. None of our long-term debt obligations have been guaranteed or secured by AEP or any of its affiliates.

First Mortgage Bonds outstanding were as follows:

		2004				2003
% Rate	Due	(in thousands)
7.750	2004 - June 1	$	-		$		40,000
6.200	2006 - November 1		5,215				5,360
6.200	2006 - November 1		1,000				1,000
7.000	2007 - September 1		90,000				90,000
6.875	2025 - October 1		-				80,000
Unamortized Discount			(191	)			(648	)
Total		$	96,024		$		215,712

First Mortgage Bonds are secured by a first mortgage lien on Electric Utility Plant. The indenture, as supplemented, relating to the first mortgage bonds contains maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.

Installment Purchase Contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

			2004		2003
	% Rate	Due	(in thousands)
Desoto County	7.600	2019 - January 1	$	-	$	53,500
	Variable (a)	2019 - January 1		53,500		-
Sabine River Authority of Texas	6.100	2018 - April 1		81,700		81,700
Titus County	Variable (b)	2011 - July 1		41,135		-
	6.900	2004 - November 1		-		12,290
	6.000	2008 - January 1		-		12,170
	8.200	2011 - August 1		-		17,125
	Unamortized Discount			1,544		1,746
	Total		$	177,879	$	178,531

(a) The rate on December 31, 2004 was 1.700%.

(b) The rate on December 31, 2004 was 1.850%.

Under the terms of the installment purchase contracts, SWEPCo is required to pay amounts sufficient to enable the payment of interest on and the principal of (at stated maturities and upon mandatory redemptions) related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain plants.

Senior Unsecured Notes outstanding were as follows:

		2004			2003
% Rate	Due	(in thousands)
4.500	2005 - July 1	$	200,000		$	200,000
5.375	2015 - April 15		100,000			100,000
Unamortized Discount			(314	)		(784	)
Total		$	299,686		$	299,216

Notes Payable to Trust was outstanding as follows:

		2004			2003
% Rate	Due	(in thousands)
5.250 (a)	2043 - October 1	$	113,403		$	113,403
Unamortized Discount			(384	)		(394	)
Total		$	113,019		$	113,009

(a) The 5.25% interest rate is fixed through September 10, 2008 after which they will become floating rate bonds if the notes are not remarketed.

See “Trust Preferred Securities” section of Note 16 for discussion of Notes Payable to Trust.

Notes Payable outstanding were as follows:

				2004		2003
		% Rate	Due	(in thousands)
Sabine Mining Company (a)		6.360	2007 - February 22	$	4,000	$	4,000
		Variable (b)	2008 - June 30		11,250		13,500
		7.030	2012 - February 22		20,000		20,000
Dolet Hills Lignite Company		4.470	2011 - May 16		33,511		40,340
		Total		$	68,761	$	77,840
(a)	Sabine Mining Company was consolidated during the third quarter of 2003 due to the implementation of FIN 46.
(b)	A floating interest rate is determined quarterly. The rate on December 31, 2004 was 2.325%.

Notes Payable to parent company was as follows:

		2004		2003
% Rate	Due	(in thousands)
4.450	2010 - March 15	$	50,000	$	-

At December 31, 2004 future annual long-term debt payments are as follows:

	Amount
	(in thousands)
2005	$	209,974
2006		15,754
2007		102,312
2008		5,906
2009		5,156
Later Years		465,612
Total Principal Amount		804,714
Unamortized Discount		655
Total	$	805,369

SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED

INDEX TO NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to SWEPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.

	Footnote Reference
Organization and Summary of Significant Accounting Policies	Note 1
New Accounting Pronouncements, Extraordinary Item and Cumulative Effect of Accounting Changes	Note 2
Goodwill and Other Intangible Assets	Note 3
Rate Matters	Note 4
Effects of Regulation	Note 5
Customer Choice and Industry Restructuring	Note 6
Commitments and Contingencies	Note 7
Guarantees	Note 8
Sustained Earnings Improvement Initiative	Note 9
Benefit Plans	Note 11
Business Segments	Note 12
Derivatives, Hedging and Financial Instruments	Note 13
Income Taxes	Note 14
Leases	Note 15
Financing Activities	Note 16
Related Party Transactions	Note 17
Jointly-Owned Electric Utility Plant	Note 18
Unaudited Quarterly Financial Information	Note 19

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company Consolidated as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2004.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company Consolidated as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003; FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003; and FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003,” effective April 1, 2004.

/s/ Deloitte & Touche LLP

Columbus, Ohio

February 28, 2005

NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES

The notes to financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply:
1.	Organization and   Summary of Significant    Accounting Policies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
2.	New Accounting      Pronouncements,    Extraordinary Item   and Cumulative   Effect of      Accounting Changes	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
3.	Goodwill and Other   Intangible Assets	SWEPCo
4.	Rate Matters	APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
5.	Effects of Regulation	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
6.	Customer Choice and   Industry Restructuring	APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
7.	Commitments and Contingencies	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
8.	Guarantees	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
9.	Sustained Earnings   Improvement Initiative	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
10.	Dispositions, Impairments,   Assets Held for Sale and   Assets Held and Used	APCo, CSPCo, I&M, KPCo, OPCo, TCC, TNC
11.	Benefit Plans	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
12.	Business Segments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
13.	Derivatives, Hedging and    Financial Instruments	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
14.	Income Taxes	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
15.	Leases	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
16.	Financing Activities	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
17.	Related Party Transactions	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
18.	Jointly Owned Electric   Utility Plant	CSPCo, PSO, SWEPCo, TCC, TNC
19.	Unaudited Quarterly   Financial Information	AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

1.ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION

The principal business conducted by AEP’s ten domestic electric utility operating companies is the generation, transmission and distribution of electric power. These companies are subject to regulation by the FERC under the Federal Power Act and maintain accounts in accordance with FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.

With the exception of AEGCo, Registrant Subsidiaries engage in wholesale electricity marketing and risk management activities in the United States. In addition, I&M provides barging services to both affiliated and nonaffiliated companies.

See Note 10 for additional information regarding asset impairments and assets and liabilities held for sale related to our Texas generation plants.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Rate Regulation

AEP and its subsidiaries are subject to regulation by the SEC under the PUHCA. The rates charged by the utility subsidiaries are approved by the FERC and the state utility commissions. The FERC regulates wholesale electricity operations. Wholesale power markets are generally market-based and are not cost-based regulated unless a generator/seller of wholesale power is determined by the FERC to have “market power.” The FERC also regulates transmission service and rates particularly in states that have restructured and unbundled their rates. The state commissions regulate all or portions of our retail operations and retail rates dependent on the status of customer choice in each state jurisdiction (see Note 6).

Principles of Consolidation

The consolidated financial statements for APCo, CSPCo, I&M, OPCo, SWEPCo and TCC include the registrant and its wholly-owned subsidiaries and/or substantially controlled variable interest entities. Intercompany items are eliminated in consolidation. Equity investments not substantially controlled that are 50% or less owned are accounted for using the equity method of accounting; equity earnings are included in Nonoperating Income. OPCo and SWEPCo also consolidate variable interest entities in accordance with FASB Interpretation Number (FIN) 46 (revised December 2003) “Consolidation of Variable Interest Entities” (FIN 46R) (seeNote 2). CSPCo, PSO, SWEPCo, TCC and TNC also have generating units that are jointly-owned with nonaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in the financial statements and the investments are reflected in the balance sheets.

Accounting for the Effects of Cost-Based Regulation

As cost-based rate-regulated electric public utility companies, the Registrant Subsidiaries’ financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with SFAS 71, “Accounting for the Effects of Certain Types of Regulation”, regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. The following Registrant Subsidiaries discontinued the application of SFAS 71 for the generation portion of their business as follows: in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by TCC, TNC, and SWEPCo in September 1999, in Arkansas by SWEPCo in September 1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo reapplied SFAS 71 for its West Virginia generation operations and SWEPCo reapplied SFAS 71 for its Arkansas generation operations. SFAS 101, “Regulated Enterprises - Accounting for the Discontinuance of Application of FASB Statement No. 71” requires the recognition of an impairment of a regulatory asset arising from the discontinuance of SFAS 71 be classified as an extraordinary item.

Use of Estimates

The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include but are not limited to inventory valuation, allowance for doubtful accounts, goodwill and intangible asset impairment, unbilled electricity revenue, values of long-term energy contracts, the effects of regulation, long-lived asset recovery, the effects of contingencies and certain assumptions made in accounting for pension benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could differ from those estimates.

Property, Plant and Equipment and Equity Investments

Electric utility property, plant and equipment are stated at original purchase cost. Property, plant and equipment of the nonregulated operations and other investments are stated at their fair market value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. For cost-based rate-regulated operations, retirements from the plant accounts and associated removal costs, net of salvage, are charged to accumulated depreciation. For nonregulated operations, retirements from the plant accounts, net of salvage, are charged to accumulated depreciation and removal costs are charged to expense. The costs of labor, materials and overhead incurred to operate and maintain plant are included in operating expenses.

The Registrant Subsidiaries implemented SFAS 143 effective January 1, 2003 (see “Accounting for Asset Retirement Obligations” section of this note).

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets is no longer recoverable or when the assets meet the held for sale criteria under SFAS 144, “Accounting for the Impairment or Disposal of Long-lived Assets.” Equity investments are required to be tested for impairment when it is determined that an other than temporary loss in value has occurred.

The fair value of an asset and investment is the amount at which that asset and investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

Depreciation, Depletion and Amortization

We provide for depreciation of property, plant and equipment on a straight-line basis over the estimated useful lives of property, excluding coal-mining properties, generally using composite rates by functional class. The following table provides the annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries for the year 2004:

	Nuclear		Steam		Hydro		Transmission		Distribution		General
	(in percentages)
AEGCo		-		3.5		-		-		-		16.4
APCo		-		3.1		2.6		2.2		3.3		9.4
CSPCo		-		2.9		-		2.3		3.6		10.3
I&M		3.1		4.5		3.3		1.9		4.1		11.2
KPCo		-		3.8		-		1.7		3.5		9.2
OPCo		-		2.8		2.7		2.3		4.0		10.1
PSO		-		2.7		-		2.3		3.3		7.9
SWEPCo		-		3.3		-		2.8		3.6		6.9
TCC		-		-		-		2.3		3.4		6.5
TNC		-		2.6		-		3.0		3.2		8.4

The annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries for the year 2003 were as follows:

	Nuclear		Steam		Hydro		Transmission		Distribution		General
	(in percentages)
AEGCo		-		3.5		-		-		-		16.7
APCo		-		3.3		2.7		2.2		3.3		9.3
CSPCo		-		3.0		-		2.3		3.6		9.9
I&M		3.4		4.6		3.4		1.9		4.2		11.8
KPCo		-		3.8		-		1.7		3.5		7.1
OPCo		-		2.8		2.7		2.3		4.0		10.5
PSO		-		2.7		-		2.3		3.4		9.7
SWEPCo		-		3.3		-		2.8		3.6		8.0
TCC		2.5		2.3		1.9		2.3		3.5		8.1
TNC		-		2.6		-		3.1		3.3		10.2

The annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries for the year 2002 were as follows:

	Nuclear		Steam		Hydro		Transmission		Distribution		General
	(in percentages)
AEGCo		-		3.5		-		-		-		2.8
APCo		-		3.4		2.9		2.2		3.3		3.1
CSPCo		-		3.2		-		2.3		3.6		3.2
I&M		3.4		4.5		3.4		1.9		4.2		3.8
KPCo		-		3.8		-		1.7		3.5		2.5
OPCo		-		3.4		2.7		2.3		4.0		2.7
PSO		-		2.7		-		2.3		3.4		6.3
SWEPCo		-		3.4		-		2.7		3.6		4.7
TCC		2.5		2.6		1.9		2.3		3.5		4.0
TNC		-		2.8		-		3.1		3.3		6.8

We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. Average amortization rates for coal rights and mine development costs related to SWEPCo were $0.65 per ton in 2004 and $0.41 in 2003 and 2002. In 2004, average amortizations rates increased from 2003 due to a lower tonnage nomination from the power plant yielding a higher cost per ton.

For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to accumulated depreciation. Actual removal costs incurred are debited to accumulated depreciation. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from accumulated depreciation and reflected as a regulatory liability. For nonregulated operations, non-ARO removal cost is expensed as incurred (see “Accounting for Asset Retirement Obligations” section of this note).

Accounting for Asset Retirement Obligations

The following is a reconciliation of 2003 and 2004 aggregate carrying amounts of asset retirement obligations by Registrant Subsidiary:

	Balance at January 1, 2003		Accretion		Liabilities Incurred		Liabilities Settled		Revisions in Cash Flow Estimates		Balance at December 31, 2003
	(in millions)
AEGCo (a)	$	1.1	$	-	$	-	$	-	$	-	$	1.1
APCo (a)		20.1		1.6		-		-		-		21.7
CSPCo (a)		8.1		0.6		-		-		-		8.7
I&M (b)		516.1		37.1		-		-		-		553.2
OPCo (a)		39.5		3.2		-		-		-		42.7
SWEPCo (c)		-		0.3		8.1		-		-		8.4
TCC (d)		203.2		15.6		-		-		-		218.8

	Balance at January 1, 2004		Accretion		Liabilities Incurred		Liabilities Settled			Revisions in Cash Flow Estimates			Balance at December 31, 2004
	(in millions)
AEGCo (a)	$	1.1	$	0.1	$	-	$	-		$	-		$	1.2
APCo (a)		21.7		1.7		-		(0.4	)		1.6			24.6
CSPCo (a)		8.7		0.7		-		-			2.2			11.6
I&M (b)		553.2		39.8		-		-			118.8			711.8
OPCo (a)		42.7		3.4		-		-			(0.5	)		45.6
SWEPCo (c)		8.4		1.3		17.7		-			-			27.4
TCC (d)		218.8		16.7		-		-			13.4			248.9

(a)	Consists of asset retirement obligations related to ash ponds.
(b)	Consists of asset retirement obligations related to ash ponds ($1.2 million and $1.1 million at December 31, 2004 and 2003, respectively) and nuclear decommissioning costs for the Cook Plant ($710.6 million and $552.1 million at December 31, 2004 and 2003, respectively).
(c)	Consists of asset retirement obligations related to Sabine Mining in 2004 and 2003, which is now being consolidated under FIN 46 (see FIN 46 “Consolidation of Variable Interest Entities” section of Note 2), and Dolet Hills in 2004.
(d)	Consists of asset retirement obligations related to nuclear decommissioning costs for STP included in Liabilities Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

Accretion expense is included in Other Operation expense in the respective income statements of the individual subsidiary registrants.

As of December 31 2004, and 2003, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $934 million ($791 million for I&M and $143 million for TCC) and $845 million ($720 million for I&M and $125 million for TCC), respectively, included in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds on I&M’s Consolidated Balance Sheets and in Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

Pro forma net income and earnings per share are not presented for the year ended December 31, 2002 because the pro forma application of SFAS 143 would result in pro forma net income and earnings per share not materially different from the actual amounts reported during that period.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant. For nonregulated operations, interest is capitalized during construction in accordance with SFAS 34, “Capitalization of Interest Costs.” Capitalized interest is also recorded for domestic generating assets in Ohio, Texas and Virginia, effective with the discontinuance of SFAS 71 regulatory accounting. The amounts of AFUDC and interest capitalized for 2004, 2003 and 2002 are as follows:

	2004		2003		2002
	(in millions)
AEGCo	$	-	$	-	$	0.4
APCo		14.7		8.5		5.8
CSPCo		6.1		6.3		2.3
I&M		4.1		8.2		6.0
KPCo		0.5		1.7		2.2
OPCo		6.3		5.0		6.7
PSO		0.6		0.8		0.7
SWEPCo		1.1		1.7		0.5
TCC		1.9		1.1		5.1
TNC		0.6		0.8		0.4

Valuation of Nonderivative Financial Instruments

The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability for I&M approximates the best estimate of its fair value.

Cash and Cash Equivalents

Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.

Other Cash Deposits

Other Cash Deposits include funds held by trustees primarily for the payment of debt.

Inventory

Except for PSO and TNC, the regulated domestic utility companies value fossil fuel inventories at the lower of a weighted average cost or market. PSO and TNC record fossil fuel inventories at the lower of cost or market, utilizing the LIFO cost method. Materials and supplies inventories are carried at average cost.

Accounts Receivable

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, AEP and certain subsidiaries accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the last billings.

AEP Credit, Inc. factors accounts receivable for certain subsidiaries, including CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” allowing the receivables to be removed from the company’s balance sheet (see “Sale of Receivables” section of Note 16).

Concentrations of Credit Risk and Significant Customers

TNC and TCC have significant customers which on a combined basis account for the following percentages of total Operating Revenues for the periods ended and Accounts Receivable - Customers as of December 31:

	2004			2003			2002
TCC - two customers
Percentage of Operating Revenues		74	%		56	%		7	%
Percentage of Accounts Receivable - Customers		48			54			N/A
TNC - three customers
Percentage of Operating Revenues		79			68			9
Percentage of Accounts Receivable - Customers		57			49			N/A

We monitor credit levels and the financial condition of our customers on a continuing basis to minimize credit risk. We believe adequate provision for credit loss has been made in the accompanying Registrant Financial Statements.

Deferred Fuel Costs

The cost of fuel consumed is charged to expense when the fuel is burned. Where applicable under governing state regulatory commission retail rate orders, fuel cost over-recoveries (the excess of fuel revenues billed to ratepayers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to ratepayers) are deferred as regulatory assets. These deferrals are amortized when refunded or billed to customers in later months with the regulator’s review and approval. The amounts of an over-recovery or under-recovery can also be affected by actions of regulators. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their deferrals and record provisions for estimated refunds to recognize these probable outcomes. For TCC & TNC, their deferred fuel balances will be included in their True-up Proceedings (see Note 6). See Note 5 for the amount of deferred fuel costs by Registrant Subsidiary.

In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are reflected in rates in a timely manner through the fuel cost adjustment clauses in place in those states. All or a portion of profits from off-system sales are shared with ratepayers through fuel clauses in Texas (SPP area only), Oklahoma, Louisiana, Kentucky, Arkansas and in some areas of Michigan. Where fuel clauses have been eliminated due to the transition to market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective January 1, 2002) changes in fuel costs impact earnings unless recovered in sales price for electricity. In other state jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have been frozen or suspended for a period of years, fuel cost changes have impacted earnings. The Michigan fuel clause suspension ended December 31, 2003, and the Indiana freeze ended on March 1, 2004. Through subsequent orders, the Indiana Utility Regulatory Commission (IURC) has authorized the billing of capped fuel rates on an interim basis until April 1, 2005. In Indiana, there is an issue as to whether the freeze should be extended through 2007 under an existing corporate separation stipulation agreement. Management disagrees with this interpretation of the stipulation and the matter is pending resolution. In West Virginia, the fuel clause is suspended indefinitely. See Note 4 and Note 6 for further information about fuel recovery.

Revenue Recognition

Regulatory Accounting

The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, CSPCo, OPCo, SWEPCo, TCC and TNC), reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recorded to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues in the same accounting period and by matching income with its passage to customers in cost-based regulated rates. Regulatory liabilities or regulatory assets are also recorded for unrealized MTM gains and losses that occur due to changes in the fair value of physical and financial contracts that are derivatives and that are subject to the regulated ratemaking process when realized.

When regulatory assets are probable of recovery through regulated rates, Registrant Subsidiaries record them as assets on the balance sheet. Registrant Subsidiaries test for probability of recovery whenever new events occur, for example, issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the Registrant Subsidiaries write off that regulatory asset as a charge against earnings. A write-off of regulatory assets also reduces future cash flows since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities

Revenues are recognized from retail and wholesale electricity supply sales and electricity transmission and distribution delivery services. The revenues are recognized in our statement of operations when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase and sale contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio, Virginia and Texas. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

Beginning in July 2004, as a result of the sale of generation assets in AEP's west zone, AEP is short capacity and must purchase physical power to supply retail and wholesale customers.  For power purchased under derivative contracts in AEP’s west zone, prior to settlement the unrealized gains and losses (other than those subject to regulatory deferral) that result from measuring these contracts at fair value during the period are recognized as Revenues. If the contract results in the physical delivery of power, the previously recorded unrealized gains and losses from MTM valuations are reversed and the settled amounts are recorded gross as Purchased Energy for Resale. If the contract does not physically deliver, the previously recorded unrealized gains and losses from MTM valuations are reversed and the settled amounts are recorded as Revenues in the financial statements on a net basis (see Note 13).

Energy Marketing and Risk Management Activities

Registrant Subsidiaries engage in wholesale electricity and coal and emission allowances marketing and risk management activities. Effective October 2002, these activities were focused on wholesale markets where Registrant Subsidiaries own assets. Registrant Subsidiaries activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, and over-the-counter options and swaps. Prior to October 2002, Registrant Subsidiaries recorded wholesale marketing and risk management activities using the MTM method of accounting.

In October 2002, EITF 02-3 precluded MTM accounting for risk management contracts that were not derivatives pursuant to SFAS 133. Registrant Subsidiaries implemented this standard for all nonderivative wholesale and risk management transactions occurring on or after October 25, 2002. For nonderivative risk management transactions entered prior to October 25, 2002, Registrant Subsidiaries implemented this standard on January 1, 2003 and reported the effects of implementation as a cumulative effect of an accounting change (see “Accounting for Risk Management Contracts” section of Note 2).

After January 1, 2003, revenues and expenses are recognized from wholesale marketing and risk management transactions that are not derivatives when the commodity is delivered. Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated for hedge accounting or the normal purchase and sale exemption. The unrealized and realized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in Revenues in the financial statements on a net basis.  In jurisdictions subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).

All of the Registrant Subsidiaries except AEGCo participate in wholesale marketing and risk management activities in electricity and gas. For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles the total gain or loss is realized in revenues. Where the revenues are recorded on the income statement depends on whether the contract is subject to the regulated ratemaking process. For contracts subject to the regulated ratemaking process the total gain or loss realized for sales and the cost of purchased energy are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical and financial forward sale and purchase contracts subject to the regulated ratemaking process are deferred as regulatory liabilities (gains) or regulatory assets (losses). For contracts not subject to the ratemaking process only the differencebetween the accumulated unrealized net gains or losses recorded in prior periods and the cash proceeds are recognized in the income statement as nonoperating income. Prior to settlement, changes in the fair value of physical and financial forward sale and purchase contracts not subject to the ratemaking process are included in nonoperating income on a net basis. Unrealized mark-to-market gains and losses are included in the balance sheets as Risk Management Assets or Liabilities as appropriate.

For APCo, CSPCo and OPCo, depending on whether the delivery point for the electricity is in the traditional marketing area or not determines where the contract is reported in the income statement. Physical forward risk management sale and purchase contracts with delivery points in the traditional marketing area are included in revenues on a net basis. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts in the traditional marketing area are also included in revenues on a net basis. Physical forward sale and purchase contracts for delivery outside of the traditional marketing area are included in nonoperating income when the contract settles. Prior to settlement, changes in the fair value of physical forward sale and purchase contracts with delivery points outside of the traditional marketing area are included in nonoperating income on a net basis.

Certain wholesale marketing and risk management transactions are designated as a hedge of a forecasted transaction, a future cash flow (cash flow hedge) or as a hedge of a recognized asset, liability or firm commitment (fair value hedge). The gains or losses on derivatives designated as fair value hedges are recognized in Revenues in the financial statements in the period of change together with the offsetting losses or gains on the hedged item attributable to the risks being hedged. For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the financial statements when the forecasted transaction is realized and affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the financial statements immediately (see Note 13).

Construction Projects for Outside Parties

TCC and TNC engage in construction projects for outside parties that are accounted for on the percentage-of-completion method of revenue recognition. This method recognizes revenue, including the related margin, as project costs are incurred and billed to the outside party. Such revenue and related expenses are included in Nonoperating Income and Nonoperating Expenses, respectively, in the financial statements. Contractually billable expenses not yet billed, if significant, are included in Current Assets as Unbilled Construction Costs in the financial statements.

Levelization of Nuclear Refueling Outage Costs

In order to match costs with nuclear refueling cycles, incremental operation and maintenance costs associated with periodic refueling outages at I&M’s Cook Plant are deferred and amortized over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins. I&M adjusts the amortization amount as necessary to ensure that all deferred costs are fully amortized by the end of the refueling cycle.

Maintenance Costs

Maintenance costs are expensed as incurred. If it becomes probable that Registrant Subsidiaries will recover specifically incurred costs through future rates, a regulatory asset is established to match the expensing of maintenance costs with their recovery in cost-based regulated revenues.

Income Taxes and Investment Tax Credits

Registrant Subsidiaries use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.

When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

Investment tax credits have been accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are being amortized over the life of the regulated plant investment.

Excise Taxes

Registrant Subsidiaries, as agents for some state and local governments, collect from customers certain excise taxes levied by those state or local governments on customers. Registrant Subsidiaries do not record these taxes as revenue or expense.

Debt and Preferred Stock

Gains and losses from the reacquisition of debt used to finance domestic regulated electric utility plant are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Some jurisdictions require that these costs be expensed upon reacquisition. We report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Charges.

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The amortization expense is included in interest charges.

Registrant Subsidiaries classify instruments that have an unconditional obligation requiring them to redeem the instruments by transferring an asset at a specified date as liabilities on their balance sheets. Those instruments consist of cumulative preferred stock subject to mandatory redemption as of December 31, 2004 and 2003. Beginning July 1, 2003, the Registrant Subsidiaries classify dividends on these mandatorily redeemable preferred shares as Interest Charges. In accordance with SFAS 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” dividends from prior periods remain classified as preferred stock dividends, a component of Preferred Stock Dividend Requirements, on their financial statements.

Where reflected in rates, redemption premiums paid to reacquire preferred stock of certain Registrant Subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series. The excess of par value over the costs of reacquired preferred stock for nonregulated subsidiaries is credited to retained earnings upon reacquisition.

Goodwill and Intangible Assets

SWEPCo is the only Registrant Subsidiary with an intangible asset with a finite life and amortizes the asset over its estimated life to its residual value (see Note 3). The Registrant Subsidiaries have no recorded goodwill and intangible assets with indefinite lives as of December 31, 2004 and 2003.

Nuclear Trust Funds

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions have allowed I&M and TCC to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC have established investment limitations and general risk management guidelines. In general, limitations include:

· acceptable investments (rated investment grade or above);

· maximum percentage invested in a specific type of investment;

· prohibition of investment in obligations of the applicable company or its affiliates; and

· withdrawals only for payment of decommissioning costs and trust expenses.

Trust funds are maintained for each regulatory jurisdiction and managed by external investment managers, who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested in order to optimize the after tax earnings of the trust giving consideration to liquidity, risk, diversification, and other prudent investment objectives.

Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are included in Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds for amounts relating to I&M’s Cook Plant and are included in Assets Held for Sale-Texas Generation Plants for amounts relating to TCC’s ownership in STP (see “Assets Held for Sale” section of Note 10). These securities are recorded at market value. Securities in the trust funds have been classified as available-for-sale due to their long-term purpose. Unrealized gains and losses from securities in these trust funds are reported as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the spent nuclear fuel disposal trust funds in accordance with their treatment in rates.

Comprehensive Income(Loss)

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss). There were no material differences between net income and comprehensive income for AEGCo.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on the balance sheets in the capitalization section. Accumulated Other Comprehensive Income (Loss) for Registrant Subsidiaries as of December 31, 2004 and 2003 is shown in the following table.

	December 31,
	2004			2003
	(in thousands)
Components
Cash Flow Hedges:
APCo	$	(9,324	)	$	(1,569	)
CSPCo		1,393			202
I&M		(4,076	)		222
KPCo		813			420
OPCo		1,241			(103	)
PSO		400			156
SWEPCo		(820	)		184
TCC		657			(1,828	)
TNC		285			(601	)
Minimum Pension Liability:
APCo	$	(72,348	)	$	(50,519	)
CSPCo		(62,209	)		(46,529	)
I&M		(41,175	)		(25,328	)
KPCo		(9,588	)		(6,633	)
OPCo		(75,505	)		(48,704	)
PSO		(325	)		(43,998	)
SWEPCo		(360	)		(44,094	)
TCC		(4,816	)		(60,044	)
TNC		(413	)		(26,117	)

Earnings Per Share (EPS)

AEGCo, APCo, CSPCo, I&M, KPCo and OPCo are wholly-owned subsidiaries of AEP and PSO, SWEPCo, TCC and TNC are owned by a wholly-owned subsidiary of AEP; therefore, none are required to report EPS.

Reclassification

Certain prior period financial statement items have been reclassified to conform to current period presentation. Such reclassifications had no impact on previously reported Net Income (Loss).

2.NEW ACCOUNTING PRONOUNCEMENTS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGES

NEW ACCOUNTING PRONOUNCEMENTS

Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine its relevance, if any, to our business. The following represents a summary of new pronouncements issued or implemented during 2004 that we have determined relate to our operations.

FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” effective April 1, 2004, retroactive to January 1, 2004. The new disclosure standard provides authoritative guidance on the accounting for any effects of the Medicare prescription drug subsidy under the Act. It replaces the earlier FSP FAS 106-1, under which APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC previously elected to defer accounting for any effects of the Act until the FASB issued authoritative guidance on the accounting for the Medicare subsidy.

Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost, while the retroactive portion is an actuarial gain to be amortized over the average remaining service period of active employees, to the extent that the gain exceeds FAS 106’s 10 percent corridor. See Note 11 for additional information related to the effects of implementation of FAS 106-2 on our postretirement benefit plans.

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

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” 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 Accounting Principles Board (APB) 25. The statement is effective as of the first interim or annual period beginning after June 15, 2005, with early implementation permitted. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement.

We will implement SFAS 123R in the third quarter of 2005 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to 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 will be based on the grant-date fair value of the equity award. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

SFAS 153 “Exchange of Nonmonetary Assets: an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS 153, “Exchange of Nonmonetary Assets: an amendment of APB Opinion No. 29” to eliminate the Opinion 29 exception to fair value for nonmonetary exchanges of similar productive assets and to replace it with a general exception for exchange transactions that do not have commercial substance. We expect to implement SFAS 153 prospectively, beginning July 1, 2005. We do not expect the effect to be material to our results of operations, cash flows or financial condition.

FIN 46 (revised December 2003)“Consolidation of Variable Interest Entities” and FIN 46 “Consolidation of Variable Interest Entities”

We implemented FIN 46, “Consolidation of Variable Interest Entities,” effective July 1, 2003. FIN 46 interprets the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,”to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Due to the prospective application of FIN 46, we did not reclassify prior period amounts.

On July 1, 2003, PSO, SWEPCo and TCC deconsolidated the trusts that held mandatorily redeemable trust preferred securities.

Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company (Sabine), a contract mining operation providing mining services to SWEPCo. Also, after consolidation, SWEPCo records all expenses (depreciation, interest and other operation expense) of Sabine and eliminates Sabine’s revenues against SWEPCo’s fuel expenses. There is no cumulative effect of accounting change recorded as a result of our requirement to consolidate, and there was no change in net income due to the consolidation of Sabine.

Effective July 1, 2003, OPCo consolidated JMG, an entity formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. OPCo now records the depreciation, interest and other operating expenses of JMG and eliminates JMG’s revenues against OPCo’s operating lease expenses. There is no cumulative effect of accounting change recorded as a result of our requirement to consolidate JMG, and there was no change in net income due to the consolidation of JMG (see “Gavin Scrubber Financing Agreement” in Note 15).

In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R) which replaces FIN 46. We implemented FIN 46R effective March 31, 2004 with no material impact to our financial statements.

EITF Issue 03-13 “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations”

This issue developed a model for evaluating which cash flows are to be considered in determining whether cash flows have been or will be eliminated and what types of continuing involvement constitute significant continuing involvement when determining whether to report Discontinued Operations. We will apply this issue to components that are disposed of or classified as held for sale in periods beginning after December 15, 2004.

FASB Staff Position 109-1 “Application of FASB Statement No. 109, Accounting for Income Taxes, to the Tax Deduction on Qualified Activities Provided by the American Jobs Creation Act of 2004”

On October 22, 2004 the American Jobs Creation Act of 2004 (Act) was signed into law. The Act included tax relief for domestic manufacturers (including the production, but not the delivery of electricity) by providing a tax deduction up to 9 percent (when fully phased-in in 2010) on a percentage of “qualified production activities income.” Beginning in 2005 and for 2006, the deduction is 3 percent of qualified production activities income. The deduction increases to 6 percent for 2007, 2008 and 2009. The FASB staff has indicated that this tax relief should be treated as a special deduction and not as a tax rate reduction. While the U.S. Treasury has issued general guidance on the calculation of the deduction, this guidance lacks clarity as to determination of qualified production activities income as it relates to utility operations. We believe that the special deduction for 2005 and 2006 will not materially affect the results of operations, cash flows, or financial condition.

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, asset retirement obligations, fair value measurements, business combinations, revenue recognition, pension plans, liabilities and equity, earnings per share calculations, accounting changes and related tax impacts as applicable. We also expect to see more FASB projects as a result of their 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.

EXTRAORDINARY ITEMS

In the fourth quarter of 2004, as part of its True-up Proceeding, TCC made net adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset related to its transition to retail competition. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis, including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on a PUCT adjustment in the CenterPoint Order (see “Wholesale Capacity Auction True-up” section of Note 6). These net adjustments were recorded as an extraordinary item in accordance with SFAS 101 “Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71” and are reflected in TCC’s Consolidated Statements of Operations as Extraordinary Loss on Stranded Cost Recovery, Net of Tax.

In 2003 an extraordinary item of $177,000, net of tax of $95,000, was recorded at TNC for the discontinuance of regulatory accounting under SFAS 71 in compliance with a FERC Order dated December 24, 2003 approving a Settlement. The Registrant Subsidiaries had no extraordinary items in 2002.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

Accounting for Risk Management Contracts

EITF 02-3 rescinds EITF 98-10 “Accounting for Contracts Included in Energy Trading and Risk Management Activities,” and related interpretive guidance. Registrant Subsidiaries except PSO and AEGCo have recorded after tax charges against net income in Cumulative Effect of Accounting Changes on the Registrant financial statements in the first quarter of 2003. These amounts are recognized as the positions settle.

Asset Retirement Obligations

In the first quarter of 2003, Registrant Subsidiaries except PSO and AEGCo recorded a cumulative effect of accounting change for Asset Retirement Obligations in accordance with SFAS 143.

The following is a summary by Registrant Subsidiary of the cumulative effect of changes in accounting principles recorded in 2003 for the adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo or PSO):

	SFAS 143 Cumulative Effect				EITF 02-3 Cumulative Effect
	(in millions)
	Pretax Income (Loss)		After tax Income (Loss)		Pretax Income (Loss)			After tax Income (Loss)
APCo	$	128.3	$	80.3	$	(4.7	)	$	(3.0	)
CSPCo		49.0		29.3		(3.1	)		(2.0	)
I&M		-		-		(4.9	)		(3.2	)
KPCo		-		-		(1.7	)		(1.1	)
OPCo		213.6		127.3		(4.2	)		(2.7	)
SWEPCo		13.0		8.4		0.2			0.1
TCC		-		-		0.2			0.1
TNC		4.7		3.1		-			-

3.GOODWILL AND OTHER INTANGIBLE ASSETS

Goodwill

There is no goodwill carried by any of the Registrant Subsidiaries.

Acquired Intangible Assets

SWEPCo’s acquired intangible asset subject to amortization is $18.8 million at December 31, 2004 and $21.7 million at December 31, 2003, net of accumulated amortization and is included in Deferred Charges on the Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization are:

			December 31, 2004				December 31, 2003
	Amortization Life		Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
	(in years)		(in millions)				(in millions)
Advanced royalties		10	$	29.4	$	10.6	$	29.4	$	7.7

Amortization of the intangible asset was $2.9 million for 2004 and $3 million for 2003 and 2002. SWEPCo’s estimated total amortization is $3 million for each year 2005 through 2010 and $1 million in 2011.

4.RATE MATTERS

In certain jurisdictions, we have agreed to base rate or fuel recovery limitations usually under terms of settlement agreements. See Note 5 for a discussion of those terms related to the Nuclear Plant Restart and the Merger with CSW.

TNC Fuel Reconciliations - Affecting TNC

In 2002, TNC filed with the PUCT to reconcile fuel costs and defer the unrecovered portion applicable to retail sales within its ERCOT service area for inclusion in its True-up Proceeding. As a result of the introduction of customer choice on January 1, 2002, this fuel reconciliation for the period from July 2000 through December 2001 is the final fuel reconciliation for TNC’s ERCOT service territory.

Through 2004, TNC provided $30 million for various disallowances recommended by the ALJ and accepted by the PUCT in open session of which $20 million was recorded in 2003 and $10 million in 2004. On October 18, 2004, the PUCT issued a final order which concluded that the over-recovery balance was $4 million. TNC has fully provided for the PUCT’s final order in this proceeding. TNC has sought declaratory and injunctive relief in Federal District Court for $8 million of its provision resulting from the PUCT’s rejection of TNC’s application of a FERC-approved tariff on the basis that the interpretation of the tariff is within the exclusive jurisdiction of the FERC and not the PUCT. TNC has also appealed various other issues to state District Court in Travis County for which it has provided $22 million. Another party has also filed a state court appeal. TNC will pursue vigorously these proceedings but at present cannot predict their outcome.

In February 2002, TNC received a final PUCT order in a previous fuel reconciliation covering the period July 1997 through June 2000 and reflected the order in its financial statements. In September 2004, that decision was affirmed by the Third Court of Appeals. No appeal was filed with the Supreme Court of Texas.

TCC Fuel Reconciliation - Affecting TCC

In 2002, TCC filed its final fuel reconciliation with the PUCT to reconcile fuel costs to be included in its deferred over-recovery balance in the True-up Proceeding. This reconciliation covers the period from July 1998 through December 2001.

On February 3, 2004, the ALJ issued a Proposal for Decision (PFD) recommending that the PUCT disallow $140 million of eligible fuel costs. In May 2004, the PUCT accepted most of the ALJ’s recommendations in the TCC case, however, the PUCT rejected the ALJ’s recommendation to impute capacity to certain energy-only purchased power contracts and remanded the issue to the ALJ to determine if any energy-only purchased power contracts during the reconciliation period include a capacity component that is not recoverable in fuel revenues. In testimony filed in the remand proceeding, TCC asserted that its energy-only purchased power contracts do not include any capacity component. Intervenors, including the Office of Public Utility Counsel, have filed testimony recommending that $15 million to $30 million of TCC’s purchased power costs reflect capacity costs which are not recoverable in the fuel reconciliation. The ALJ issued a report on January 13, 2005 on the imputed capacity remand recommending that specified energy-only purchased power contracts include a capacity component with a value of $2 million. At its February 24, 2005 open meeting, the PUCT reviewed the ALJ report and also ruled that specified energy-only purchased power contracts include a capacity component of $2 million. As a result of the PUCT’s acceptance of most of the ALJ’s recommendations in TCC’s case and the PUCT’s rejection in the TNC case of our interpretation of its FERC tariff, TCC has recorded provisions totaling $143 million, with $81 million provided in 2003 and $62 million in 2004. The over-recovery balance and the provisions for probable disallowances totaled $212 million including interest at December 31, 2004.

Management believes they have materially provided for probable to-date disallowances in TCC’s final fuel reconciliation pending receipt of a final order. A final order has not yet been issued in TCC’s final fuel reconciliation.  An order from the PUCT, disallowing amounts in excess of the established provision, could have a material adverse effect on future results of operations and cash flows. We will continue to challenge adverse decisions vigorously, including appeals and challenges in Federal Court if necessary. Additional information regarding the True-up Proceeding for TCC can be found in Note 6.

TNC FERC Wholesale Fuel Complaints - Affecting TNC

Certain TNC wholesale customers filed a complaint with the FERC alleging that TNC had overcharged them through the fuel adjustment clause for certain purchased power costs since 1997.

Negotiations to settle the complaint and update the contracts resulted in new contracts. The FERC approved an offer of settlement regarding the fuel complaint and new contracts at market prices in December 2003. Since TNC had recorded a provision for refund in 2002, the effect of the settlement was a $4 million favorable adjustment recorded in December 2003.

SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This reconciliation covers the period from January 2000 through December 2002. During the reconciliation period, SWEPCo incurred $435 million of Texas retail eligible fuel expense. In December 2003, SWEPCo agreed to a settlement in principle with all parties in the fuel reconciliation proceeding. The settlement provides for a disallowance in fuel costs of $8 million which was recorded in December 2003. In April 2004, the PUCT approved the settlement.

SWEPCo Fuel Factor Increase - Affecting SWEPCo

On November 5, 2004, SWEPCo filed a petition with the PUCT to increase its annual fixed fuel factor by $29 million. SWEPCo and the various parties to the proceedings reached a settlement effective January 31, 2005 that increases its annual fixed fuel factor revenues by approximately $25 million or approximately 18% over the amount that would be collected by the fuel factors currently in effect. The settlement agreement was approved by the PUCT on January 31, 2005. Actual fuel costs will be subject to a review and approval in a future fuel reconciliation.

SWEPCo Louisiana Fuel Audit - Affecting SWEPCo

The Louisiana Public Service Commission (LPSC) is performing an audit of SWEPCo’s historical fuel costs. In addition, five SWEPCo customers filed a suit in the Caddo Parish District Court in January 2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has overcharged them for fuel costs since 1975. The LPSC consolidated the customer complaints and audit. In testimony filed in this matter, the LPSC Staff recommended refunds of approximately $5 million. Subsequently, surrebuttal testimony filed by the LPSC Staff recognized that SWEPCo’s costs were reasonable and that most costs could be recovered through the fuel adjustment clause pending LPSC approval. While initial indications from the LPSC Staff surrebuttal testimony would not indicate a material disallowance, management cannot predict the ultimate outcome in this proceeding. If the LPSC or the Court does not agree with LPSC Staff recommendations, it could have an adverse effect on future results of operations and cash flows.

PSO Fuel and Purchased Power - Affecting PSO

In 2002, PSO experienced a $44 million under-recovery 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 submitted a request to the Corporation Commission of the State of Oklahoma (OCC) to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. PSO filed testimony in February 2004.

An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested that $9 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated off-system sales margins between and among AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and, if corrected, could more than offset the $44 million 2002 reallocation under-recovery. The intervenor and the OCC Staff also argued that off-system sales margins were allocated incorrectly. The intervenors’ reallocation of such margins would reduce PSO’s recoverable fuel costs by $7 million for 2000 and $11 million for 2001, while under the OCC Staff method, the reduction for 2001 would be $9 million. The intervenor and the OCC Staff also recommended recalculation of PSO’s fuel costs for years subsequent to 2001 using the same revised methods. At a June 2004 prehearing conference, PSO questioned whether the issues in dispute were under the jurisdiction of the OCC because they relate to FERC-approved allocation agreements. As a result, the ALJ ordered that the parties brief the jurisdictional issue. After reviewing the briefs, the ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. In January 2005, the OCC conducted a hearing on the jurisdictional matter and a ruling is expected in the near future. Management is unable to predict the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.

Virginia Fuel Factor Filing - Affecting APCo

On October 29, 2004, APCo filed a request with the Virginia State Corporation Commission (Virginia SCC) to increase its fuel factor effective January 1, 2005. The requested factor is estimated to increase revenues by approximately $19 million on an annual basis. This increase reflects a continuing rise in the projected cost of coal in 2005. By order dated November 16, 2004, the Virginia SCC approved APCo’s request on an interim basis, pending a hearing held in February 2005. The Virginia SCC issued an order on February 11, 2005 approving the January 1, 2005 interim fuel factor, which is subject to final audit.  This fuel factor adjustment will increase cash flows without impacting results of operations as any over-recovery or under-recovery of fuel cost would be deferred as a regulatory liability or a regulatory asset.

Indiana Fuel Order - Affecting I&M

On August 27, 2003, the IURC ordered certain parties to negotiate the appropriate action on I&M’s fuel cost recovery beginning March 1, 2004, following the February 2004 expiration of a fixed fuel adjustment charge that capped fuel recoveries (fixed pursuant to a prior settlement of Cook Nuclear Plant outage issues). I&M agreed, contingent on AEP implementing corporate separation for some of its subsidiaries, to a fixed fuel adjustment charge beginning March 2004 and continuing through December 2007. Although we have not corporately separated, certain parties believe the fixed fuel adjustment charge should continue beyond February 2004. Negotiations to resolve this issue are ongoing. The IURC ordered that the fixed fuel adjustment charge remain in place, on an interim basis, through April 2004.

In April 2004, the IURC issued an order that extended the interim fuel factor from May through September 2004, subject to true-up to actual fuel costs following the resolution of the issue regarding the corporate separation agreement. The IURC also reopened the corporate separation docket to investigate issues related to the corporate separation agreement. In July 2004, we filed for approval of a fuel factor for the period October 2004 through March 2005. On September 22, 2004, the IURC issued another order extending the interim fuel factor from October 2004 through March 2005, subject to true-up upon resolution of the corporate separation issues. At December 31, 2004, I&M has under-recovered its fuel costs by $2 million. If I&M’s net recovery should remain an under-recovery and if I&M would be required to continue to bill the existing fixed fuel adjustment factor that caps fuel revenues, I&M’s future results of operations and cash flows would be adversely affected.

Michigan 2004 Fuel Recovery Plan - Affecting I&M

On September 30, 2003, I&M filed its 2004 Power Supply Cost Recovery (PSCR) Plan with the Michigan Public Service Commission (MPSC) requesting fuel and power supply recovery factors for 2004, which were implemented pursuant to statute effective with January 2004 billings. A public hearing was held on March 10, 2004. On June 4, 2004, the ALJ recommended that net SO₂ and NO_x credits be excluded from the fuel recovery mechanism. I&M filed its exceptions in June 2004. If the ALJ’s recommendation is adopted by the MPSC and in a future period SO₂ and NO_x are a net cost, it would adversely affect results of operations and cash flows. On September 30, 2004, I&M filed its 2005 PSCR Plan, which reflects net credits of approximately $5 million.

TCC Rate Case - Affecting TCC

On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC’s proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%.

In February 2004, eight intervening parties and the PUCT Staff filed testimony recommending reductions to TCC’s requested $67 million annual rate increase. Their recommendations ranged from a decrease in annual existing rates of approximately $100 million to an increase in TCC’s current rates of approximately $27 million. Hearings were held in March 2004. In May 2004, TCC agreed to a nonunanimous settlement on cost of capital including capital structure and return on equity with all but two parties in the proceeding. TCC agreed that the return on equity should be established at 10.125% based upon a capital structure with 40% equity resulting in a weighted cost of capital of 7.475%. The settlement and other agreed adjustments reduced TCC’s rate request from an increase of $67 million to an increase of $41 million.

On July 1, 2004, the ALJs who heard the case issued their recommendations which included a recommendation to approve the cost of capital settlement. The ALJs recommended that an issue related to the allocation of consolidated tax savings to the transmission and distribution utility be remanded back to the ALJs for additional evidence. On July 15, 2004, the PUCT remanded this issue to the ALJs. On August 19, 2004, in a separate ruling, the PUCT remanded six other issues to the ALJs requesting revisions to clarify and support the recommendations in the PFD.

The PUCT ordered TCC to calculate its revenue requirements based upon the recommendations of the ALJs. On July 21, 2004, TCC filed its revenue requirements based upon the recommendations of the ALJs. According to TCC’s calculations, the ALJs’ recommendations would reduce TCC’s annual existing rates between $33 million and $43 million depending on the final resolution of the amount of consolidated tax savings.

On November 16, 2004, the ALJs issued their PFD on remand, increasing their recommended annual rate reduction to a range of $51 million to $78 million, depending on the amount disallowed related to affiliated AEPSC billed expenses. At the January 13, 2005 and January 27, 2005 open meetings, the Commissioners considered a number of issues, but deferred resolution of the affiliated AEPSC billed expenses issue, among other less significant issues, until after additional hearings scheduled for March 2005. Adjusted for the decisions announced by the Commissioners in January 2005, the ALJs’ disallowance would yield an annual rate reduction of a range of $48 million to $75 million. If TCC were to prevail on the affiliated expenses issue and all remaining issues, the result would be annual rate increase of $6 million. When issued, the PUCT order will affect revenues prospectively. An order reducing TCC’s rates could have a material adverse effect on future results of operations and cash flows.

TCC and TNC ERCOT Price-to-Beat (PTB) Fuel Factor Appeal - Affecting TCC and TNC

Several parties including the OPC 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. On June 25, 2003, the District Court ruled in both appeals. The Court ruled in the Mutual Energy WTU case that the PUCT lacked sufficient evidence to include unaccounted for energy in the fuel factor, that the PUCT improperly shifted the burden of proof from the company to intervening parties and that the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. The amount of unaccounted for energy built into the PTB fuel factors was approximately $2.7 million for Mutual Energy WTU. The Court upheld the initial PTB orders on all other issues. In the Mutual Energy CPL proceeding, the Court also ruled that the PUCT improperly shifted the burden of proof and the record lacked substantial evidence on the effect of loss of load due to retail competition on generation requirements. At this time, management is unable to estimate the potential financial impact related to the loss of load issue. The District Court decision was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy WTU and other parties. Management believes, based on the advice of counsel, that the PUCT’s original decision will ultimately be upheld. If the District Court’s decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors charged to retail customers in the years 2002 through 2004 resulting in an adverse effect on TCC’s and TNC’s future results of operations and cash flows.

TCC Unbundled Cost of Service (UCOS) Appeal - Affecting TCC

The UCOS proceeding established the unbundled regulated wires rates to be effective when retail electric competition began. TCC placed new transmission and distribution rates into effect as of January 1, 2002 based upon an order issued by the PUCT resulting from TCC’s UCOS proceeding. TCC requested and received approval from the FERC of wholesale transmission rates determined in the UCOS proceeding. Regulated delivery charges include the retail transmission and distribution charge and, among other items, a nuclear decommissioning fund charge, a municipal franchise fee, a system benefit fund fee, a transition charge associated with securitization of regulatory assets and a credit for excess earnings. Certain PUCT rulings, including the initial determination of stranded costs, the requirement to refund TCC’s excess earnings, the regulatory treatment of nuclear insurance and the distribution rates charged municipal customers, were appealed to the Travis County District Court by TCC and other parties to the proceeding. The District Court issued a decision on June 16, 2003, upholding the PUCT’s UCOS order with one exception. The Court ruled that the refund of the 1999 through 2001 excess earnings, solely as a credit to nonbypassable transmission and distribution rates charged to REPs, discriminates against residential and small commercial customers and is unlawful. The distribution rate credit began in January 2002. This decision could potentially affect the PTB rates charged by Mutual Energy CPL and could result in a refund to certain of its customers. Mutual Energy CPL was a subsidiary of AEP until December 23, 2002 when it was sold. Management estimates that the adverse effect of a decision to reduce the PTB rates for the period prior to the sale is approximately $11 million pretax. The District Court decision was appealed to the Third Court of Appeals by TCC and other parties. Based on advice of counsel, management believes that it will ultimately prevail on appeal. If the District Court’s decision is ultimately upheld on appeal or the Court of Appeals reverses the District Court on issues adverse to TCC, it could have an adverse effect on TCC’s future results of operations and cash flows.

SWEPCo Louisiana Compliance Filing - Affecting SWEPCo

In October 2002, SWEPCo filed with the LPSC detailed financial information typically utilized in a revenue requirement filing, including a jurisdictional cost of service. This filing was required by the LPSC as a result of its order approving the merger between AEP and CSW. The LPSC’s merger order also provides that SWEPCo’s base rates are capped at the present level through mid-2005. In April 2004, SWEPCo filed updated financial information with a test year ending December 31, 2003 as required by the LPSC. Both filings indicated that SWEPCo’s current rates should not be reduced. Subsequently, direct testimony was filed on behalf of the LPSC recommending a $15 million reduction in SWEPCo’s Louisiana jurisdictional base rates. SWEPCo’s rebuttal testimony was filed on January 16, 2005. At this time, management is unable to predict the outcome of this proceeding. If a rate reduction is ordered in the future, it would adversely impact SWEPCo’s future results of operations and cash flows.

SWEPCo Louisiana Service Quality Improvement Program (SQIP) - Affecting SWEPCo

In the 1999 merger proceeding before the LPSC, the LPSC adopted a Service Quality Improvement Program (SQIP) for SWEPCo. On October 8, 2004, SWEPCo filed to amend the SQIP to increase its tree management and trimming expenditures by $5 million above the minimum expenditures currently required by the SQIP and defer these incremental expenses for future rate recovery. On December 9, 2004, the LPSC approved SWEPCo’s request to defer the incremental cost of tree management and trimming expenditures beginning December 1, 2004 and ending December 31, 2006 and has authorized SWEPCo to accrue interest based on its weighted average cost of capital. SWEPCo will be permitted to include the deferred costs, including interest, as a cost of service in future base rate proceedings, but only to the extent the deferrals are necessary to allow SWEPCo to recover its authorized return on equity during the time period the expenses were incurred (i.e. an earnings test). The earnings test will not be effective until calendar year 2005. In future rate proceedings, the amortization period will not exceed three years and amortization will commence with the recovery of such costs in base rates.

PSO Rate Review - Affecting PSO

In February 2003, the OCC Staff filed an application requiring PSO to file all documents necessary for a general rate review. In October 2003 and June 2004, PSO filed financial information and supporting testimony in response to the OCC Staff’s request. PSO’s initial response indicated that its annual revenues were $36 million less than costs. The June 2004 filing updated PSO’s request and indicated a $41 million revenue deficiency. As a result, PSO sought OCC approval to increase its base rates by that amount, which is a 3.9% increase over PSO’s existing revenues.

In August 2004, PSO filed a motion to amend the timeline to consider new service quality and reliability requirements, which took effect on July 1, 2004. Also in August 2004, the OCC approved a revised schedule. In October 2004, PSO filed supplemental information requesting consideration of approximately $55 million of additional annual operations and maintenance expenses and annual capital costs to enhance system reliability. In November 2004, PSO filed a plan with the OCC seeking interim rate relief to fund a portion of the costs to meet the new state service quality and reliability requirements pending the outcome of the current case. In the filing, PSO sought interim approval to collect annual incremental distribution tree trimming costs of approximately $23 million from its customers. Intervenors and the OCC Staff filed testimony recommending that the interim rate relief requested by PSO be modified or denied. The OCC issued an order on PSO’s interim request in January 2005, which allows PSO to recover up to an additional $12 million annually for reliability activities beginning in December 2004. Expenses exceeding that amount and the amount currently included in base rates will be considered in the base rate case.

The OCC Staff and intervenors filed testimony regarding their recommendations on revenue requirement, fuel procurement, resource planning and vegetation management in January 2005. Their recommendations ranged from a decrease in annual existing rates between $15 million and $36 million. In addition, one party recommended that the OCC require PSO file additional information regarding its natural gas purchasing practices. In the absence of such a filing, this party suggested that $30 million of PSO’s natural gas costs not be recovered from customers because it failed to implement a procurement strategy that, according to this party, would have resulted in lower natural gas costs. OCC Staff and intervenors recommended a return on common equity ranging from 9.3% to 10.11%. PSO’s rebuttal testimony was filed in February 2005, and that testimony reflects a number of adjustments to PSO’s June 2004 updated filing. These adjustments result in a decrease of PSO’s revenue deficiency in this case from $41 million to $28 million, although approximately $9 million of that decrease are items that would be recovered through the fuel adjustment clause rather than through base rates. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.

APCo Virginia Regional Transmission Entity (RTE) Credit Rider - Affecting APCo

Pursuant to a stipulation agreement approved by the Virginia SCC by order dated August 30, 2004 in APCo’s Virginia RTO approval proceeding in which APCo requested approval to become a member of PJM, a RTE Credit Rider became effective January 1, 2005. The RTE Credit Rider is designed to reduce APCo’s annual Virginia jurisdictional revenues by approximately $2 million. Under the terms of the stipulation agreement, the RTE Credit Rider will be adjusted to produce a $3 million annual Virginia jurisdictional revenue reduction effective on January 1 of the year following the year in which Dominion (Virginia Power) becomes an integrated member of PJM. The RTE Credit Rider will expire at the earlier of December 31, 2010 or upon a change in APCo’s base rates as a result of a base rate case filed by APCo.

KPCo Stipulation and Settlement Agreement - Affecting AEGCo, I&M and KPCo

On October 25, 2004, KPCo filed an application requesting the KPSC to approve the terms and provisions of a Stipulation and Settlement Agreement among KPCo, the Office of the Kentucky Attorney General and the Kentucky Industrial Utility Customers. The Stipulation: (1) extends a unit power agreement for approximately 18 years, until December 7, 2022, which obligates KPCo to pay 15 percent of the costs associated with two 1,300 MW generating units in Rockport, Indiana for 15 percent of the units’ generating output; (2) modifies KPCo’s off-system sales clause tariff to reflect as an expense the environmental costs attributable to off-system sales; and (3) establishes a schedule for KPCo to file its next integrated resource plan, and provides for retail rate recovery of supplemental payments associated with the extension of the unit power agreement and the settlement of other regulatory matters. On December 13, 2004, the KPSC issued its order approving the terms and provisions of the Stipulation and Settlement Agreement. The FERC approved the extension of the unit power agreement on December 29, 2004. KPCo will recover an additional $5 million annually during the first five years and $6 million annually for the remaining 13 years of the 18- year extension.

PSO Lawton Power Supply Agreement

On November 26, 2003, pursuant to an application by Lawton Cogeneration Incorporated seeking avoided cost payments and approval of a power supply agreement, the OCC issued an order approving payment of avoided costs and a Power Supply Agreement (Agreement). Among other things, in the order, the OCC did not approve recovery of the costs of the Agreement. 

In December 2003, PSO filed an appeal of the OCC’s order with the Oklahoma Supreme Court. In the appeal, PSO maintains that the OCC exceeded its authority under state and federal laws to require PSO to enter into the Agreement. Should the OCC’s order be upheld by the Supreme Court, PSO anticipates full recovery of the costs of the Agreement.  However, if the OCC was to deny recovery of a material amount, it would adversely affect future results of operations and cash flows.

Upon resolution of this issue, management would review any transaction for the effect, if any, on the balance sheet relating to lease and FIN 46R accounting.

KPCo Environmental Surcharge Filing - Affecting KPCo

In September 2002, KPCo filed with the KPSC to revise its environmental surcharge tariff (annual revenue increase of approximately $21 million) to recover the cost of emissions control equipment being installed at the Big Sandy Plant.

In March 2003, the KPSC granted approximately $18 million of the request. Annual rate relief of $1.7 million became effective in May 2003 and an additional $16.2 million became effective in July 2003. The recovery of such amounts is intended to offset KPCo’s cost of compliance with the CAA.

RTO Formation/Integration - Affecting APCo, CSPCo, I&M, KPCo and OPCo

Based on FERC approvals in response to nonaffiliated companies’ requests to defer RTO formation costs, the AEP East companies deferred costs incurred under FERC orders to form a new RTO (the Alliance RTO) or subsequently to join an existing RTO (PJM). In July 2003, the FERC issued an order approving the AEP East companies continued deferral of both Alliance RTO formation costs and PJM integration costs, including the deferral of a carrying charge thereon. The AEP East companies have deferred approximately $37 million of RTO formation and integration costs and related carrying charges through December 31, 2004. Amounts per company are as follows:

Company	(in millions)
APCo	$	10.5
CSPCo		4.4
I&M		8.0
KPCo		2.4
OPCo		11.9

In its July 2003 order, the FERC indicated that it would review the deferred costs at the time they are transferred to a regulatory asset account and scheduled for amortization and recovery in the OATT to be charged by PJM. Management believes that the FERC will grant permission for prudently incurred deferred RTO formation/integration costs to be amortized and included in the OATT. Whether the amortized costs will be fully recoverable depends upon the state regulatory commissions’ treatment of the AEP East companies’ portion of the OATT as these companies file rate cases. As of December 31, 2004, retail base rates are frozen or capped and cannot be increased for retail customers of CSPCo and OPCo until January 1, 2006.

In August 2004, the AEP East companies filed an application with the FERC dividing the RTO formation/integration costs between PJM-incurred integration costs billed to them including related carrying charges, and all other RTO formation/integration costs. AEP East companies intend to file with the FERC to request that deferred PJM-incurred integration costs billed to them be recovered from all PJM customers. Management anticipates the other RTO formation/integration costs will be recovered through transmission rates in the AEP East zone. The AEP East companies will be responsible for paying most of the amount allocated by the FERC to the AEP East zone since it will be attributable to their internal load. In the August 2004 application, the AEP East companies requested permission to amortize over 15 years beginning January 1, 2005 the cost to be billed within the AEP East zone which represents approximately one-half of the total deferred RTO formation/integration costs. The AEP East companies also requested to begin amortizing the deferred PJM-billed integration costs on January 1, 2005, AEP East companies but did not propose an amortization period in the application. The FERC has not ruled on the application.

The AEP East companies integrated into PJM on October 1, 2004. The AEP East companies intend to file a joint request with other new PJM members to recover approximately one-half of the deferred RTO formation/integration costs (i.e. the PJM-incurred integration expenses billed to the AEP East companies) through a new charge in the PJM OATT that would apply to all loads and generation in the PJM region during a 10-year period beginning in May 2005. The AEP East companies will expense their portion of the PJM-incurred integration costs billed by PJM under the new charge. The AEP East companies will amortize the remaining portion of our RTO formation/integration costs over the period to be approved by the FERC and seek recovery of such costs in the retail rates for each of the AEP East companies’ state jurisdictions. Management believes that it is probable that the FERC will approve recovery of the PJM-incurred integration costs to be billed to the AEP East companies through the PJM OATT and that the FERC will grant a long enough amortization period to allow for the opportunity for recovery of the non-PJM incurred RTO formation/integration costs in the AEP East retail jurisdictions. If the FERC ultimately decides not to approve an amortization period that would provide the AEP East companies with the opportunity to include such costs in future retail rate filings or the FERC or the state commissions deny recovery of these deferred costs the AEP East companies’ future results of operations and cash flows could be adversely affected.

FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M, KPCo and OPCo

In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (MISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and expanded PJM regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners including AEP East companies under the RTOs’ revenue distribution protocols.

In November 2003, the FERC issued an order finding that the T&O rates of the former Alliance RTO Participants, including AEP East companies, should also be eliminated for transactions within the Combined Footprint. The order directed the RTOs and former Alliance RTO Participants to file compliance rates to eliminate T&O rates prospectively within the Combined Footprint and simultaneously implement a load-based transitional rate mechanism called the seams elimination cost allocation (SECA), to mitigate the lost T&O revenues for a two-year transition period beginning April 1, 2004. The FERC is expected to implement a new rate design after the two-year period. In April 2004, the FERC approved a settlement that delayed elimination of T&O rates and the implementation of SECA replacement rates until December 1, 2004 when the FERC would implement a new rate design.

On November 18, 2004, the FERC conditionally approved a license plate rate design to eliminate rate pancaking for transmission service within the Combined Footprint and adopted its previously approved SECA transition rate methodology to mitigate the effects of the elimination of T&O rates effective December 1, 2004. Under license plate rates, customers serving load within a RTO pay transmission service rates based on the embedded cost of the transmission facilities in the local pricing zone where the load being served is located. The use of license plate rates would shift costs that the AEP East companies previously recovered from T&O service customers to mainly AEP’s native load customers within the AEP East pricing zone. The SECA transition rates will remain in effect through March 31, 2006. The SECA rates are designed to mitigate the loss of revenues due to the elimination of T&O rates.

The SECA rates became effective December 1, 2004. Billing statements from PJM for December 2004 did not reflect any credits to AEP East companies for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP East companies accrued $11 million in December 2004 for SECA revenues. On January 7, 2005, AEP East companies and Exelon filed joint comments and protests with the FERC including a request that FERC direct PJM and MISO to comply with the FERC decision and collect all SECA revenues due with interest charges for all late-billed amounts. On February 10, 2005, the FERC issued an order indicating that the SECA transition rates would be subject to refund or surcharge and set for hearing all remaining aspects of the compliance filings to the November 18 order, including AEP's request that the FERC direct PJM and MISO begin billing and collecting the SECA transition rates.

The AEP East companies received approximately $196 million of T&O rate revenues within the PJM/MISO Expanded Footprint for the twelve months ended September 30, 2004, the last twelve months prior to the AEP East companies joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA charges was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate AEP East companies for their lost T&O revenues through March 31, 2006, or if any increase in the AEP East companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Hold Harmless Proceeding - Affecting AEP East companies

In its July 2002 order conditionally accepting the AEP East companies’ choice to join PJM, the FERC directed AEP East companies, ComEd, MISO and PJM to propose a solution that would effectively hold harmless the utilities in Michigan and Wisconsin from any adverse effects associated with loop flows or congestion resulting from us and ComEd joining PJM instead of MISO. In December 2003, AEP East companies and ComEd jointly filed a hold-harmless proposal, which was rejected by the FERC in March 2004 without prejudice to the filing of a new proposal.

In July 2004, AEP East companies and PJM filed jointly with the FERC a new hold-harmless proposal that was nearly identical to a proposal filed jointly by ComEd and PJM in April 2004. In September 2004, the FERC accepted and suspended the new proposal that became effective October 1, 2004, subject to refund and to the outcome of a hearing on the appropriate compensation, if any, to the Michigan and Wisconsin utilities. A hearing is scheduled for April 2005.

The proposed hold-harmless agreement as filed by PJM and AEP East companies specifies that the term of the agreement commences on October 1, 2004 and terminates when the FERC determines that effective internalization of congestion and loop flows is accomplished. The Michigan and Wisconsin utilities have presented studies that show estimated adverse effects to utilities in the two states in the range of $60 to $70 million over the term of the agreement for ComEd and AEP East companies. The recent supplemental filing by the Michigan companies shows estimated adverse effects to utilities in Michigan of up to $50 million over the term of agreement. AEP East companies and ComEd have presented studies that show no adverse effects to the Michigan and Wisconsin utilities. ComEd has separately settled this issue with the Michigan and Wisconsin utilities for a one time total payment of approximately $5 million, which was approved by the FERC. On December 27, 2004, AEP East companies and the Wisconsin utilities jointly filed a settlement that resolves all hold-harmless issues for a one-time payment of $250,000 which is pending approval before the FERC.

At this time, management is unable to predict the outcome of this proceeding. AEP East companies will support vigorously its positions before the FERC. No provision has been established. If the FERC ultimately approves a significant hold-harmless payment to the Michigan and Wisconsin utilities, it would adversely impact results of operations and cash flows.

FERC Market Power Mitigation - Affecting AEP East and AEP West companies

In April 2004, the FERC issued two orders concerning utilities’ ability to sell wholesale electricity at market-based rates. In the first order, the FERC adopted two new interim screens for assessing potential generation market power of applicants for wholesale market based rates, and described additional analyses and mitigation measures that could be presented if an applicant does not pass one of these interim screens. These two screening tests include a “pivotal supplier” test which determines if the market load can be fully served by alternative suppliers and a “market share” test which compares the amount of surplus generation at the time of the applicant’s minimum load. In July 2004, the FERC issued an order on rehearing, affirming its conclusions in the April order and directing the AEP System and two nonaffiliated utilities to file generation market power analyses within 30 days. In the second order, the FERC initiated a rulemaking to consider whether the FERC’s current methodology for determining whether a public utility should be allowed to sell wholesale electricity at market-based rates should be modified in any way.

On August 9, 2004, as amended on September 16, 2004 and November 19, 2004, the AEP System submitted its generation market power screens in compliance with the FERC’s orders. The analysis focused on the three major areas in which AEP subsidiaries serve load and own generation resources -- ECAR, SPP and ERCOT, and the “first tier” control areas for each of those areas.

The pivotal supplier and market share screen analyses that were filed demonstrated that the AEP System does not possess market power in any of the control areas to which it is directly connected (first-tier markets). The AEP System passed both screening tests in all of its “first tier” markets. In its three “home” control areas, the AEP System passed the pivotal supplier test. The AEP East companies, as part of PJM, also passed the market share screen for the PJM destination market. TCC and TNC also passed the market share screen for ERCOT. PSO, SWEPCo and TNC did not pass the market share screen as designed by the FERC for the SPP control area.

In a December 17, 2004 order, FERC affirmed the conclusions that the AEP System passed both market power screen tests in all areas except SPP. Because the AEP System did not pass the market share screen in SPP, FERC initiated proceedings under Section 206 of the Federal Power Act in which the AEP West companies are rebuttably presumed to possess market power in SPP. Consequently, their revenues from sales in SPP at market based rates after March 6, 2005 will be collected subject to refund to the extent that prices are ultimately found not to be just and reasonable. On February 15, 2005, although management continues to believe the AEP System does not possess market power in SPP, the AEP West companies filed a response and proposed tariff changes to address FERC’s market-power concerns. The proposed tariff change would apply to sales that sink within the service territories of PSO, SWEPCo and TNC within SPP that encompass the AEP-SPP control area, and make such sales subject to cost-based rate caps. PSO, SWEPCo and TNC have requested the amended tariffs to become effective March 6, 2005.

In addition to FERC market monitoring, the AEP East and West companies are subject to market monitoring oversight by the RTOs in which they are a member, including PJM and SPP. These market monitors have authority for oversight and market power mitigation.

Management believes that the AEP System is unable to exercise market power in any region. At this time the impact on future wholesale power revenues, results of operations and cash flows of the FERC’s and PJM’s market power analysis cannot be determined.

5.EFFECTS OF REGULATION

Regulatory Assets and Liabilities

Regulatory assets and liabilities are comprised of the following items at Decmber 31:

	AEGCo						APCo
	2004		2003		Recovery/Refund Period		2004		2003		Recovery/Refund Period
	(in thousands)
Regulatory Assets:
SFAS 109 Regulatory Asset, Net							$	343,415	$	325,889		Various Periods (a)
Transition Regulatory Assets - Virginia								25,467		30,855		Up to 6 Years (a)
Unamortized Loss on Reacquired Debt	$	4,496	$	4,733		21 Years (b)		18,157		19,005		Up to 28 Years (b)
Asset Retirements Obligations		1,117		928		Various Periods (a)		9,879		9,048		Various Periods (a)
Unrealized Loss on Forward Commitments								13,871		17,006		Various Periods (a)
Other								12,618		15,393		Various Periods (a)
Total Regulatory Assets	$	5,613	$	5,661			$	423,407	$	417,196
Regulatory Liabilities:
Asset Removal Costs	$	25,428	$	27,822		(d)	$	95,763	$	92,497		(d)
Deferred Investment Tax Credits		46,250		49,589		Up to 18 Years (a)		30,382		30,545		Up to 16 Years (c)
SFAS 109 Regulatory Liability, Net		12,852		15,505		Various Periods (a)
Over-recovery of Fuel Costs -   West Virginia								52,071		55,250		(a)
Unrealized Gain on Forward Commitments								23,270		17,283		Various Periods (a)
Over-recovery of Fuel Costs - Virginia								5,772		13,454		1 Year (b)
Other								-		43
Total Regulatory Liabilities	$	84,530	$	92,916			$	207,258	$	209,072

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	A portion of this amount effectively earns a return.
(d)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.

	CSPCo						I&M
	2004		2003		Recovery/Refund Period		2004		2003		Recovery/Refund Period
	(in thousands)
Regulatory Assets:
SFAS 109 Regulatory Asset, Net	$	16,481	$	16,027		Various Periods (a)	$	147,167	$	151,973		Various Periods (a)
Transition Regulatory Assets		156,676		188,532		Up to 4 Years (a)
Unamortized Loss on Reacquired Debt		13,155		13,659		Up to 20 Years (b)		21,039		18,424		Up to 28 Years (b)
Incremental Nuclear Refueling Outage   Expenses, Net								44,244		57,326		(c)
DOE Decontamination Assessment								14,215		18,863		Up to 3 Years (a)
Other		25,691		24,966		Various Periods (a)		31,015		29,691		Various Periods (a)
Total Regulatory Assets	$	212,003	$	243,184			$	257,680	$	276,277
Regulatory Liabilities:
Asset Removal Costs	$	103,104	$	99,119		(d)	$	280,054	$	263,015		(d)
Deferred Investment Tax Credits		27,933		30,797		Up to 16 Years (a)		82,802		90,278		Up to 18 Years (a)
Excess ARO for Nuclear Decommissioning								245,175		215,715		(e)
Unrealized Gain on Forward Commitments								35,534		25,010		Various Periods (a)
Other								33,695		36,258		Various Periods (a)
Total Regulatory Liabilities	$	131,037	$	129,916			$	677,260	$	630,276

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage and does not earn a return.
(d)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.
(e)	This is the cumulative difference in the amount provided through rates and the amount as measured by applying SFAS 143. This amount earns a return, which accrues monthly, and will be paid when the nuclear plant is decommissioned.

	KPCo						OPCo
	2004		2003		Recovery/Refund Period		2004		2003		Recovery/Refund Period
	(in thousands)
Regulatory Assets:
SFAS 109 Regulatory Asset, Net	$	103,849	$	99,828		Various Periods (a)	$	169,866	$	169,605		Various Periods (a)
Transition Regulatory Assets								225,273		310,035		3 years (a)
Unamortized Loss on Reacquired Debt		1,021		1,088		Up to 28 Years (b)		11,046		10,172		Up to 34 Years (b)
Other		13,537		12,883		Various Periods (a)		22,189		22,506		Various Periods (a)
Total Regulatory Assets	$	118,407	$	113,799			$	428,374	$	512,318
Regulatory Liabilities:
Asset Removal Costs	$	28,232	$	26,140		(c)	$	102,875	$	101,160		(c)
Deferred Investment Tax Credits		6,722		7,955		Up to 16 Years (a)		12,539		15,641		Up to 16 Years (a)
Unrealized Gain on Forward Commitments		13,041		9,174		Various Periods (a)
Other		2,581		1,417		Various Periods (a)		-		3
Total Regulatory Liabilities	$	50,576	$	44,686			$	115,414	$	116,804

(a)	Amount does not earn a return.
(b)	Amount effectively earns a return.
(c)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.

	PSO						SWEPCo
	2004		2003		Recovery/Refund Period		2004		2003		Recovery/Refund Period
	(in thousands)
Regulatory Assets:
SFAS 109 Regulatory Asset, Net							$	18,000	$	3,235		Various Periods (b)
Under-recovered Fuel Costs	$	366	$	24,170		1 Year (a)		4,687		11,394		1 Year (a)
Unamortized Loss on Reacquired Debt		14,705		14,357		Up to 11 Years (b)		20,765		19,331		Up to 39 Years (b)
Other		17,246		14,342		Various Periods (d)		16,350		15,859		Various Periods (c)
Total Regulatory Assets	$	32,317	$	52,869			$	59,802	$	49,819
Regulatory Liabilities:
Asset Removal Costs	$	220,298	$	214,033		(e)	$	249,892	$	236,409		(e)
Deferred Investment Tax Credits		28,620		30,411		Up to 25 Years (d)		35,539		39,864		Up to 13 Years (d)
SFAS 109 Regulatory Liability, Net		21,963		24,937		Various Periods (b)
Over-recovered Fuel Costs								9,891		4,178		1 Year (a)
Excess Earnings								3,167		2,600		(d)
Unrealized Gain on Forward Commitments		19,676		15,406		Various Periods (d)		15,176		11,793		Various Periods (d)
Other								6,144		6,986		Various Periods (c)
Total Regulatory Liabilities	$	290,557	$	284,787			$	319,809	$	301,830

(a)	Over/Under-recovered fuel for PSO’s Oklahoma jurisdiction & SWEPCo’s Arkansas and Louisiana jurisdictions does not earn a return. Texas jurisdictional amounts for SWEPCo do earn a return.
(b)	Amount effectively earns a return.
(c)	Amounts are both earning and not earning a return.
(d)	Amount does not earn a return.
(e)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.

	TCC						TNC
	2004		2003		Recovery/Refund Period		2004		2003		Recovery/Refund Period
	(in thousands)
Regulatory Assets:
SFAS 109 Regulatory Asset, Net	$	15,236	$	3,249		Various Periods (a)
Designated for Securitization		1,361,299		1,289,436		(b)
Under Recovery of Fuel Costs							$	-	$	6,180		(c)
Wholesale Capacity Auction True-up		559,973		480,000		(c)
Unamortized Loss on Reacquired Debt		11,842		9,086		Up to 32 Years (a)		2,147		3,929		Up to 15 Years (a)
Deferred Debt - Restructuring		11,596		12,015		Up to 14 Years (a)		6,093		6,579		Up to 14 Years (a)
Other		102,032		127,488		Various Periods (e)		3,783		3,332		Various Periods (e)
Total Regulatory Assets	$	2,061,978	$	1,921,274			$	12,023	$	20,020
Regulatory Liabilities:
Asset Removal Costs	$	102,624	$	95,415		(f)	$	81,143	$	76,740		(f)
Deferred Investment Tax Credits		107,743		112,479		Up to 24 Years (d)		18,698		19,990		Up to 18 Years (d)
Over-recovery of Fuel Costs		211,526		150,026		(c)		3,920		-		(c)
Retail Clawback		61,384		45,527		(c)		13,924		11,804		(c)
Over-recovery of Transition Charges		14,522		22,499		Up to 12 Years (a)
Excess Earnings								13,270		14,262		Up to 30 Years (a)
SFAS 109 Regulatory Liability, Net								8,500		13,655		Various Periods (a)
Other		62,131		64,207		Various Periods (e)		1,319		1,826		Various Periods (e)
Total Regulatory Liabilities	$	559,930	$	490,153			$	140,774	$	138,277

(a)	Amount earns a return.
(b)	Amount includes a carrying cost, will be included in TCC’s True-up Proceeding and is designated for possible securitization. The cost of the securitization bonds would be recovered over a time period to be determined in a future PUCT proceeding.
(c)	See Note 6 “Texas Restructuring” and “Carrying Costs on Net True-up Regulatory Assets” for discussion of carrying costs. Amounts will be included in TCC’s and TNC’s True-up Proceedings for future recovery/refund over a time period to be determined in a future PUCT proceeding.
(d)	Amount does not earn a return.
(e)	Amounts are both earning and not earning a return.
(f)	The liability for removal costs will be discharged as removal costs are incurred over the life of the plant.

Texas Restructuring Related Regulatory Assets and Liabilities

Designated for Securitization, Wholesale Capacity Auction True-up regulatory assets, Over-recovery of Fuel Costs and Retail Clawback regulatory liabilities are not being currently recovered from or returned to ratepayers. Management believes that the laws and regulations established in Texas for industry restructuring provide for the recovery from ratepayers of these net amounts. These amounts require approval of the PUCT in a future True-up Proceeding. See Note 6 for a complete discussion of our plans to seek recovery of these regulatory assets, net of regulatory liabilities.

Nuclear Plant Restart

I&M completed the restart of both units of the Cook Plant in 2000. Settlement agreements in the Indiana and Michigan retail jurisdictions that addressed recovery of Cook Plant related outage restart costs were approved in 1999 by the Indiana Utility Regulatory Commission and Michigan Public Service Commission.

The amount of deferrals amortized to maintenance and other operation expenses under the settlement agreements were $40 million in both 2003 and 2002. The Nuclear Plant Restart regulatory asset was fully amortized as of December 31, 2004 and 2003. Also pursuant to the settlement agreements, accrued fuel-related revenues of approximately $37 million in 2003 and $38 million in 2002 were amortized as a reduction of revenues. The amortization of amounts deferred under Indiana and Michigan retail jurisdictional settlement agreements adversely affected results of operations through December 31, 2003 when the amortization period ended.

Merger with CSW

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned subsidiary of AEP. In connection with the merger, nonrecoverable merger costs were expensed in 2003 and 2002. Such costs included transaction and transition costs not recoverable from ratepayers. Also included in the merger costs were nonrecoverable change in control payments. Merger transaction and transition costs recoverable from ratepayers were deferred pursuant to state regulator approved settlement agreements. The deferred merger costs are being amortized over five to eight year recovery periods, depending on the specific terms of the settlement agreements, with the amortization included in depreciation and amortization expense. Deferred merger costs are included in Other Regulatory Assets in the above tables.

As hereinafter summarized, the state settlement agreements provide for, among other things, a sharing of net merger savings with certain regulated customers over periods of up to eight years through rate reductions which began in the third quarter of 2000.

Summary of key provisions of Merger Rate Agreements:

State/Company	Ratemaking Provisions
Texas - SWEPCo, TCC, TNC	Rate reductions of $221 million over 6 years.
Indiana - I&M	Rate reductions of $67 million over 8 years.
Michigan - I&M	Customer billing credits of approximately $14 million over 8 years.
Kentucky - KPCo	Rate reductions of approximately $28 million over 8 years.
Oklahoma - PSO	Rate reductions of approximately $28 million over 5 years.
Arkansas - SWEPCo	Rate reductions of $6 million over 5 years.
Louisiana - SWEPCo	Rate reductions to share merger savings estimated to be $18 million over 8 years and a base rate cap until June 2005.

If actual merger savings are significantly less than the merger savings rate reductions required by the merger settlement agreements in the eight-year period following consummation of the merger, future results of operations, cash flows and possibly financial condition could be adversely affected.

See “Merger Litigation” section of Note 7 for information on a court decision concerning the merger.

6.CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

With the passage of restructuring legislation, six of our eleven electric utility companies (CSPCo, I&M, APCo, OPCo, TCC and TNC) are in various stages of transitioning to customer choice and/or market pricing for the supply of electricity in four of the eleven state retail jurisdictions (Ohio, Texas, Michigan and Virginia) in which the Registrant Subsidiaries operate. The following paragraphs discuss significant events related to industry restructuring in those states.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo

The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005. The Public Utilities Commission of Ohio (PUCO) may terminate the MDP for one or more customer classes before that date if it determines either that effective competition exists in the incumbent utility’s certified territory or that there is a twenty percent switching rate of the incumbent utility’s load by customer class. Following the MDP, retail customers will receive cost-based regulated distribution and transmission service from the incumbent utility whose distribution rates will be approved by the PUCO and whose transmission rates will be approved by the FERC. Retail customers will continue to have the right to choose their electric power suppliers or receive Default Service, which must be offered by the incumbent utility at market rates.

On December 17, 2003, the PUCO adopted a set of rules concerning the method by which it will determine market rates for Default Service following the MDP. The rules provide for a Market Based Standard Service Offer (MBSSO) which would be a variable rate based on a transparent forward market, daily market, and/or hourly market prices. The rules also require a fixed-rate Competitive Bidding Process (CBP) for residential and small nonresidential customers and permits a fixed-rate CBP for large general service customers and other customer classes. Customers who do not switch to a competitive generation provider can choose between the MBSSO and the CBP. Customers who make no choice will be served pursuant to the CBP. The rules also required that electric distribution utilities file an application for MBSSO and CBP by July 1, 2004. CSPCo and OPCo were granted a waiver from making the required MBSSO/CBP filing, pending the outcome of a rate stabilization plan they filed with the PUCO in February 2004. As of December 31, 2004, none of OPCo’s customers have elected to choose an alternate power supplier and only a modest number of CSPCo’s small commercial customers has switched suppliers. This is believed to be due to CSPCo’s and OPCo’s rates being below market.

The PUCO invited default service providers to propose an alternative to all customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo and OPCo filed rate stabilization plans with the PUCO addressing prices for the three-year period following the end of the MDP, January 1, 2006 through December 31, 2008. The plans are intended to provide price stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP’s generation resources that serve Ohio customers. On January 26, 2005, the PUCO approved the plans with some modifications.

The approved plans include annual fixed increases in the generation component of all customers’ bills (3% a year for CSPCo and 7% a year for OPCo) in 2006, 2007 and 2008. The plan also includes the opportunity to annually request an additional increase in supply prices averaging up to 4% per year for each company to recover certain new governmentally-mandated increased expenditures set out in the approved plan. The plans maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level in effect on December 31, 2005. Such rates could be adjusted with PUCO approval for specified reasons. Transmission charges could also be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion and ancillary services. The approved plans provide for the continued amortization and recovery of stranded transition generation-related regulatory assets. The plans, as modified by the PUCO, require CSPCo and OPCo to allot a combined total of $14 million of previously provided unspent shopping incentives for the benefit of their low-income customers and economic development over the three-year period ending December 31, 2008 which will not have an effect on net income. The plan also authorized each company to establish unavoidable riders applicable to all distribution customers in order to be compensated in 2006 through 2008 for certain new costs incurred in 2004 and 2005 of fulfilling the companies’ Provider of Last Resort (POLR) obligations. These costs include RTO administrative fees and congestion costs net of financial transmission revenues and carrying cost of environmental capital expenditures. As a result, in 2005, CSPCo and OPCo expect to record regulatory assets of $8 million and $21 million, respectively, for the subject costs related to 2004 and $14 million and $52 million, respectively, for expected subject costs related to 2005. These regulatory assets totaling $22 million for CSPCo and $73 million for OPCo will be amortized as the costs are recovered through POLR riders in 2006 through 2008. The riders, together with the fixed annual increases in generation rates are estimated to provide additional cumulative revenues to CSPCo and OPCo of $190 million and $500 million, respectively, in the three-year period ended December 31, 2008. Other revenue increases may occur related to other provisions of the plans discussed above.

On February 25, 2005, various intervenors filed Applications for Rehearing with the PUCO regarding their approval of the rate stabilization plans.  Management expects the PUCO to address the applications before the end of March 2005.  Management cannot predict the ultimate impact these proceedings will have on the results of operations and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, CSPCo and OPCo are deferring customer choice implementation costs and related carrying costs in excess of $20 million per company. The agreements provide for the deferral of these costs as a regulatory asset until the next distribution base rate cases. Through December 31, 2004, CSPCo has incurred $38 million and deferred $18 million and OPCo has incurred $40 million and deferred $20 million of such costs for probable future recovery in distribution rates. Recovery of these regulatory assets will be subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the rate stabilization plans, recovery of these amounts will be deferred until the next distribution rate filing to change rates after December 31, 2008. Management believes that the deferred customer choice implementation costs were prudently incurred 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.

TEXAS RESTRUCTURING - Affecting SWEPCo, TCC and TNC

Texas Restructuring Legislation enacted in 1999 provides the framework and timetable to allow retail electricity competition for all Texas customers. On January 1, 2002, customer choice of electricity supplier began in the ERCOT area of Texas. Customer choice has been delayed in the SPP area of Texas until at least January 1, 2007. TCC and TNC operate in ERCOT while SWEPCo and a small portion of TNC’s business is in SPP.

The Texas Restructuring Legislation, among other things:

● provides for the recovery of net stranded generation costs and other generation true-up amounts through securitization and nonbypassable wires charges,

● requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility,

● provides for an earnings test for each of the years 1999 through 2001 and,

● provides for a stranded cost True-up Proceeding after January 10, 2004.

The Texas Restructuring Legislation also required vertically integrated utilities to legally separate their generation and retail-related assets from their transmission and distribution-related assets. Prior to 2002, TCC and TNC functionally separated their operations. AEP formed new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1, 2002 (the start date of retail competition). In December 2002, AEP sold two of its affiliated price-to-beat REPs serving ERCOT customers to a nonaffiliated company.

TEXAS TRUE-UP PROCEEDINGS

The True-up Proceedings will determine the amount and recovery of:

● net stranded generation plant costs and net generation-related regulatory assets less any unrefunded excess earnings (net stranded generation costs),

● a true-up of actual market prices determined through legislatively-mandated capacity auctions to the projected power costs used in the PUCT’s excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up revenues),

● excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback),

● final approved deferred fuel balance, and

● net carrying costs on true-up amounts.

The PUCT adopted a rule in 2003 regarding the timing of the True-up Proceedings scheduling TCC’s filing 60 days after the completion of the sale of TCC’s generation assets. Due to regulatory and contractual delays in the sale of its generating assets, TCC has not filed its true-up request. TNC filed its true-up request in June 2004 and updated the filing in October 2004. Since TNC is not a stranded cost company under Texas Restructuring Legislation, the majority of the true-up items in the table below do not apply to TNC.

Net True-up Regulatory Asset (Liability) Recorded at December 31, 2004:

	TCC			TNC
	(in millions)
Stranded Generation Plant Costs	$	897		$	-
Net Generation-related Regulatory Asset		249			-
Unrefunded Excess Earnings		(10	)		-
Net Stranded Generation Costs		1,136			-
Carrying Costs on Stranded Generation Plant Costs		225			-
Net Stranded Generation Costs Designated for Securitization		1,361			-
Wholesale Capacity Auction True-up		483			-
Carrying Costs on Wholesale Capacity Auction True-up		77			-
Retail Clawback		(61	)		(14	)
Deferred Over-recovered Fuel Balance		(212	)		(4	)
Net Other Recoverable True-up Amounts		287			(18	)
Total Recorded Net True-up Regulatory Asset (Liability)	$	1,648		$	(18	)

Amounts listed above include fourth quarter 2004 adjustments made to reflect the applicable portion of the PUCT’s decisions in prior nonaffiliated utilities’ True-up Proceedings discussed below.

Net Stranded Generation Costs

The Texas Restructuring Legislation required utilities with stranded generation plant costs to use market-based methods to value certain generation assets for determining stranded generation plant costs. TCC is the only AEP subsidiary that has stranded generation plant costs under the Texas Restructuring Legislation. TCC elected to use the sale of assets method to determine the market value of its generation assets for determining stranded generation plant costs. For purposes of the True-up Proceeding, the amount of stranded generation plant costs under this market valuation methodology will be the amount by which the book value of TCC’s generation assets exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets.

In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC’s generation capacity in Texas. TCC received bids for all of its generation plants. In January 2004, TCC agreed to sell its 7.81% ownership interest in the Oklaunion Power Station to a nonaffiliated third party for approximately $43 million. In March 2004, TCC agreed to sell its 25.2% ownership interest in STP for approximately $333 million and its other coal, gas and hydro plants for approximately $430 million to nonaffiliated entities. Each sale is subject to specified price adjustments. TCC sent right of first refusal notices to the co-owners of Oklaunion and STP. TCC filed for FERC approval of the sales of Oklaunion, STP and the coal, gas and hydro plants. TCC received a notice from co-owners of Oklaunion and STP exercising their rights of first refusal; therefore, SEC approval will be required. The original nonaffiliated third party purchaser of Oklaunion has petitioned for a court order declaring its contract valid and the co-owners’ rights of first refusal void. The sale of STP will also require approval from the NRC. On July 1, 2004, TCC completed the sale of its other coal, gas and hydro plants for approximately $428 million, net of adjustments. The closings of the sales of STP and Oklaunion plants are expected to occur in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals. In addition, there could be delays in resolving litigation with a third party affecting Oklaunion. In order to sell these assets, TCC defeased all of its remaining outstanding first mortgage bonds in May 2004. In December 2003, based on an expected loss from the sale of its generating assets, TCC recognized as a regulatory asset an estimated impairment from the sale of TCC’s generation assets of approximately $938 million. The impairment was computed based on an estimate of TCC’s generation assets sales price compared to book basis at December 31, 2003. On February 15, 2005, TCC filed with the PUCT requesting a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closings of the sales of all the generation assets. TCC asked the PUCT to rule on the request in April 2005.

On December 17, 2004, the PUCT issued an Order on Rehearing in the CenterPoint True-Up Proceeding (CenterPoint Order). All motions for rehearing of that order were denied on January 18, 2005, and the PUCT’s decision is now final and appealable. Among other things, the CenterPoint Order provided certain adjustments to stranded generation plant costs to avoid what the PUCT deemed to be duplicative recovery of stranded costs and the capacity auction true-up amount, as further discussed below (See “Wholesale Capacity Auction True-up” below). The CenterPoint Order also confirmed that stranded costs are to be determined as of December 31, 2001, and, as also discussed below, the CenterPoint Order identified how carrying costs from that date are to be computed (see “Carrying Costs on Net True-Up Regulatory Asset” below).

In the fourth quarter of 2004, TCC made adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis (instead of December 31, 2003 book basis), including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on a PUCT adjustment in the CenterPoint Order discussed below under “Wholesale Capacity Auction True-up.” These adjustments are reflected as Extraordinary Loss on Stranded Cost Recovery, Net of Tax in TCC’s Consolidated Statements of Income. Management believes that with these adjustments to TCC’s stranded generation plant costs regulatory asset, they have complied with the portions of the PUCT’s to-date orders in other Texas companies’ True-up Proceedings that apply to TCC.

In addition to the two items discussed above (the $938 million impairment in 2003 and the $185 million adjustment in 2004), TCC had recorded $121 million of impairments in 2002 and 2003 on its gas-fired plants. Additionally, other miscellaneous items and the costs to complete the sales, which are still ongoing, of $23 million are included in the recoverable stranded generation plant costs of $897 million.

The Texas Restructuring Legislation permits TCC to recover as its net stranded generation costs $897 million of net stranded generation plant cost plus its remaining not yet securitized net generation-related transition regulatory asset of $249 million less a regulatory liability for the unrefunded excess earnings of $10 million, discussed below. With the above net extraordinary basis adjustments from applicable portions of the PUCT’s prior nonaffiliated true-up orders, TCC’s net stranded generation costs before carrying costs totaled $1.1 billionat December 31, 2004.

In the CenterPoint Order, the PUCT decided that net stranded generation costs should be reduced by the present value of deferred investment tax credits (ITC) and excess deferred federal income taxes applicable to generating assets. CenterPoint testified in its True-up Proceeding that acceleration of the sharing of deferred ITC with customers may be a violation of the Internal Revenue Code’s normalization provisions. Management agrees with CenterPoint that the PUCT’s acceleration of deferred ITC and excess deferred federal income taxes may be a violation of the normalization provisions. As a result, management does not intend to include as a reduction of its net stranded generation costs the present value of TCC’s generation-related deferred ITC of $70 million and the present value of excess deferred federal income taxes of $6 million in its future true-up filing. As a result, such amounts are not reflected as a reduction of TCC’s net stranded generation costs in the above table. The Internal Revenue Service (IRS) has issued proposed regulations that would make an exception to the normalization provisions for a utility whose electric generation assets cease to be public utility property. If the IRS does not issue final regulations with protective provisions prior to the filing of TCC’s true-up, management intends to seek a private letter ruling from the IRS to determine whether the PUCT’s action would result in a normalization violation. A normalization violation could result in the repayment of TCC’s accumulated deferred ITC on all property, not just generation property, which approximates $108 million as of December 31, 2004, and a loss of the ability to elect accelerated tax depreciation in the future. Management is unable to predict how the IRS will rule on a private letter ruling request and whether TCC will ultimately suffer any adverse effects on its future results of operations and cash flows.

Unrefunded Excess Earnings

The Texas Restructuring Legislation provides for the calculation of excess earnings for each year from 1999 through 2001. The total excess earnings determined by the PUCT for this three-year period were $3 million for SWEPCo, $42 million for TCC and $15 million for TNC. TCC, TNC and SWEPCo challenged the PUCT’s treatment of fuel-related deferred income taxes in the computation of excess earnings and appealed the PUCT’s final 2000 excess earnings to the Travis County District Court which upheld the PUCT ruling. However, upon further appeal of the District Court ruling upholding the PUCT decision, the Third Court of Appeals reversed the PUCT order and the District Court’s judgment. The District Court remanded to the PUCT an appeal of the same issue from the PUCT’s 2001 order upon agreement of the parties after issuance of the Third Court of Appeals decision. On September 14, 2004, the parties to the PUCT remand reached an agreement, which changed the method for calculating excess earnings which, in turn, revised the calculation for 2000 and 2001 consistent with the ruling of the court. The PUCT issued a final order approving the agreement in October 2004. Since an expense and regulatory liability had been accrued in prior years in compliance with the PUCT orders, all three companies reversed a portion of their regulatory liability for the years 2000 and 2001 consistent with the Appeals Court’s decision and credited amortization expense during the third quarter of 2003. Under the Texas Restructuring Legislation, since TNC and SWEPCo do not have stranded generation plant cost, excess earnings have been applied to reduce T&D capital expenditures and are not a true-up item.

In 2001, the PUCT issued an order requiring TCC to return estimated excess earnings by reducing distribution rates by approximately $55 million plus accrued interest over a five-year period beginning January 1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and 2001, the order had no additional effect on reported net income but reduces cash flows over the refund period. The remaining $10 millionto be refunded is recorded as a regulatory liability at December 31, 2004 and will be included as a reduction to TCC’s net stranded generation costs unless it has been fully refunded. Management believes that TCC has stranded generation plant costs and that it is, therefore, inconsistent with the Texas Restructuring Legislation for the PUCT to have ordered a refund prior to TCC’s True-up Proceeding. TCC appealed the PUCT’s premature refund of excess earnings to the Travis County District Court. That court affirmed the PUCT’s decision and further ordered that the refunds be provided to ultimate customers. TCC has appealed the decision to the Third Court of Appeals.

In January 2005, intervenors filed testimony in TNC’s True-up Proceeding recommending that TNC’s excess earnings be increased by approximately $5 million to reflect carrying charges on its excess earnings for the period from January 1, 2002 to March 2005. A decision from the PUCT will likely be received in the second quarter of 2005.

Wholesale Capacity Auction True-up

The Texas Restructuring Legislation required that electric utilities and their affiliated power generation companies (PGCs) offer for sale at auction, in 2002, 2003 and thereafter, at least 15% of the PGCs’ Texas jurisdictional installed generation capacity in order to promote competitiveness in the wholesale market through increased availability of generation. According to the legislation, the actual market power prices received in the state-mandated auctions are used to calculate wholesale capacity auction true-up revenues for recovery in the True-up Proceeding. According to PUCT rules, the wholesale capacity auction true-up is only applicable to the years 2002 and 2003. Based on its auction prices, TCC recorded a regulatory asset and related revenues of $262 million in 2002 and $218 million in 2003 which represented the quantifiable amount of the wholesale capacity auction true-up. The cumulative amount before carrying costs was adjusted to $483 million in the fourth quarter of 2004. TCC also recorded $77 million of carrying costs in the fourth quarter of 2004 related to the wholesale capacity auction true-up, increasing the total asset to $560 million.

In the CenterPoint Order, the PUCT made three significant adverse adjustments to CenterPoint’s and its affiliated PGCs’ request for recovery related to its capacity auction true-up regulatory asset. First, the PUCT determined that CenterPoint had not met what the PUCT interpreted as a requirement to sell 15% of its generation capacity at the state-mandated auctions. Accordingly, an adjustment was made to reflect prices obtained in other auctions of CenterPoint’s affiliated PGCs’ generation. Parties to the TCC proceeding may also contend that TCC has not met the requirement to auction 15% of its generation capacity. However, based on facts not applicable to the CenterPoint case, TCC will contend that it has met the requirement. Even if it were determined that TCC has not complied with the requirement, facts unique to TCC might mitigate the potential impact and make the method of calculating an impact uncertain. Since the facts in the CenterPoint decision differ from TCC’s facts and circumstances, TCC has not recorded any provisions to reflect a similar adverse adjustment to its net true-up regulatory asset.

Second, the PUCT determined that the purpose of the capacity auction true-up is to provide a traditional regulated level of recovery during 2002-2003. The PUCT then determined that depreciation is a component of that recovery and, because depreciation represents a return of investment in generation assets, it disallowed 2002 and 2003 depreciation as a duplicative recovery of stranded costs. In the CenterPoint Order the PUCT determined that there was a duplication of depreciation due to the fact that the stranded generation plant costs also include amounts depreciated in 2002 and 2003 because the stranded generation plant costs were determined as of December 31, 2001. TCC disagrees that the purpose of the capacity auction true-up is to provide a traditional regulated recovery during 2002 through 2003. Moreover, TCC will contend, among other things, that the PUCT’s method of calculating the capacity auction true-up did not permit TCC to fully recover 2002 through 2003 depreciation expense. Nonetheless, based on the determination made by the PUCT in the CenterPoint case and the probability that it will interpret the law in the same manner in TCC’s case, TCC recorded a $238 million reduction to its stranded generation plant costs in December 2004 which is reflected as a component of the Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax in TCC’s Consolidated Statements of Income.

Third, the PUCT determined in the CenterPoint case that any nonfuel revenues produced by the capacity auction true-up regulatory asset which exceed nonfuel revenues for 2002-2003 from traditional regulation is a margin or return which is duplicative of the carrying cost. As noted above, TCC intends to challenge the conclusion that the capacity auction true-up was intended to provide a traditional regulated recovery. In addition, TCC will contend, that when applied to TCC, the calculation adopted for CenterPoint in which the PUCT determined that CenterPoint had duplicative return of carrying costs actually produces a $206 million negative margin. It will be TCC’s position that it should have the right to recover the negative margin if the purpose of the capacity auction is to allow a traditional regulated recovery. As a result, TCC has recorded no adjustment to reflect this determination in the CenterPoint case.

Retail Clawback

The Texas Restructuring Legislation provides for the affiliated PTB REPs serving residential and small commercial customers to refund to its T&D utility the excess of the PTB revenues over market prices (subject to certain conditions and a limitation of $150 per customer). This is referred to as the retail clawback. If, prior to January 1, 2004, 40% of the load for the residential or small commercial classes is served by competitive REPs, the retail clawback is not applicable for that class of customer. In December 2003, the PUCT certified that the REPs in the TCC and TNC service territories had reached the 40% threshold for the small commercial class. As a result, TCC and TNC reversed $6 million and $3 million, respectively, of retail clawback regulatory liabilities previously accrued for the small commercial class. Based upon customer information filed by the nonaffiliated company which operates as the PTB REP for TCC and TNC, TCC and TNC updated their estimated residential retail clawback regulatory liability. At December 31, 2004, TCC’s recorded retail clawback regulatory liability was $61 million and TNC’s was $14 million. TCC and TNC each recorded a receivable from the nonaffiliated company which operates as their PTB REP totaling $32 million and $7 million, respectively, for their share of the retail clawback liability.

Fuel Balance Recoveries

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to establish its deferred unrecovered fuel balance applicable to retail sales within its ERCOT service area for inclusion in the True-up Proceeding. In October 2004, the PUCT issued a final order which resulted in an over-recovery balance of $4 million. TNC had adjusted its deferred fuel balance in 2003 by $20 million and in 2004 by $10 million in compliance with the final PUCT order. Challenges to that order were filed in December 2004 in federal and state district courts.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its deferred over-recovery fuel balance for inclusion in the True-up Proceeding. TCC provided for disallowances increasing its deferred fuel over-recovery liability by $81 million in 2003 and $62 million in 2004.  On February 24, 2005, the PUCT in its open meeting increased the over-recovery by approximately $2 million, inclusive of interest, for imputed capacity. TCC has provided for a $212 million deferred over-recovery fuel balance at December 31, 2004, which does not include the $2 million disallowance ruled by the PUCT. However, management is unable to predict the amount, if any, of any additional disallowances of TCC’s final fuel over-recovery balance which will be included in its True-up Proceeding until a final order is issued. Management believes it has materially provided for probable to date disallowances in TCC’s final fuel proceeding pending receipt of an order.

See “TCC Fuel Reconciliation” and “TNC Fuel Reconciliations” in Note 4 for further discussion.

Carrying Costs on Net True-up Regulatory Assets

In December 2001, the PUCT issued a rule concerning stranded cost True-up Proceedings stating, among other things, that carrying costs on stranded costs would begin to accrue on the date that the PUCT issued its final order in the True-up Proceeding. TCC and one other Texas electric utility company filed a direct appeal of the rule to the Texas Third Court of Appeals contending that carrying costs should commence on January 1, 2002, the day that retail customer choice began in ERCOT.

The Third Court of Appeals ruled against the utilities, who then appealed to the Texas Supreme Court. On June 18, 2004, the Texas Supreme Court reversed the decision of the Third Court of Appeals determining that a carrying cost should be accrued beginning January 1, 2002 and remanded the proceeding to the PUCT for further consideration. The Supreme Court determined that utilities with stranded costs are not permitted to over-recover stranded costs and ordered that the PUCT should address whether any portion of the 2002 and 2003 wholesale capacity auction true-up regulatory asset includes a recovery of stranded costs or carrying costs on stranded costs. A motion for rehearing with the Supreme Court was denied and the ruling became final.

In the CenterPoint Order, the PUCT addressed the Supreme Court’s remand decision and specified the manner in which carrying costs should be calculated. In December 2004, TCC computed, based on its interpretation of the methodology contained in the CenterPoint Order, carrying costs of $470 million for the period January 1, 2002 through December 31, 2004 on its stranded generation plant costs net of excess earnings and its wholesale capacity auction true-up regulatory assets at the 11.79% overall pretax cost of capital rate in its UCOS rate proceeding. The embedded 8.12% debt component of the carrying cost of $302 million ($225 million on stranded generation plant costs and $77 million on wholesale capacity auction true-up) was recognized in income in December 2004. This amount is included in Carrying Costs on Stranded Cost Recovery in TCC’s Consolidated Statements of Income. Of the $302 million recorded in 2004, approximately $109 million, $105 million and $88 million related to the years 2004, 2003 and 2002, respectively. The remaining equity component of $168 million will be recognized in income as collected.

TCC will continue to accrue a carrying cost at the rate set forth above until it recovers its approved net true-up regulatory asset. The deferred over-recovered fuel balance accrues interest payable at a short-term rate set by the PUCT until one year after a final order is issued in the fuel proceeding or a final order is issued in TCC’s True-up Proceeding, whichever comes first. At that time, a carrying cost will begin to accrue on the deferred fuel. For all remaining true-up items, including the retail clawback, a carrying cost will begin to accrue when a final order is issued in TCC’s True-up Proceeding. If the PUCT further adjusts TCC’s net true-up regulatory asset in TCC’s True-up Proceeding, the carrying cost will also be adjusted.

Stranded Cost Recovery

When the True-up Proceeding is completed, TCC intends to file to recover PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through nonbypassable transition charges and competition transition charges in the regulated T&D rates. TCC will seek to securitize the approved net stranded generation costs plus related carrying costs. The annual costs of the resultant securitization bonds will be recovered through a nonbypassable transition charge collected by the T&D utility over the term of the securitization bonds. The other approved net true-up items will be recovered or refunded over time through a nonbypassable competition transition wires charge or credit inclusive of a carrying cost.

TCC’s recorded net true-up regulatory asset for amounts subject to approval in the True-up Proceeding is approximately $1.6 billionat December 31, 2004. The securitizable portion of this net true-up regulatory asset, which consists of net stranded generation costs plus related carrying costs, was $1.4 billion at December 31, 2004. We expect that TCC’s True-up Proceeding filing will seek to recover an amount in excess of the total of its recorded net true-up regulatory asset through December 31, 2004. The PUCT will review TCC’s filing and determine the amount for the recoverable net true-up regulatory assets.

Due to differences between CenterPoint’s and TCC’s facts and circumstances, the lack of direct applicability of certain portions of the CenterPoint Order to TCC and the unknown nature of future developments in TCC’s True-up Proceeding, we cannot, at this time, determine if TCC will incur disallowances in its True-up Proceeding in excess of the $185 million provided in December 2004. Management believes that TCC’s recorded net true-up regulatory asset at December 31, 2004 is in compliance with the Texas Restructuring Legislation, and the applicable portions of the CenterPoint Order and other nonaffiliated true-up orders, and management intends to seek vigorously its recovery. If, however, management determines that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset of $1.6 billion at December 31, 2004 and is able to estimate the amount of such nonrecovery, TCC will record a provision for such amount, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition. To the extent decisions in the TCC True-up Proceeding differ from management’s interpretation of the Texas Restructuring Legislation and their evaluation of the applicable portions of the CenterPoint and other true-up orders, additional material disallowances are possible.

TNC 2004 True-up Filing

In June 2004, TNC filed its True-up Proceeding which included the fuel reconciliation balance and the retail clawback calculation. The amount of the deferred over-recovered fuel balance at December 31, 2004 was approximately $4 million. TNC filed an update to its true-up filing to reflect the final order in its fuel reconciliation proceeding. The retail clawback regulatory liability included in the filing was adjusted in 2004 to $14 million, reflecting the number of customers served on January 1, 2004. In January 2005, intervenors filed testimony recommending that TNC’s over-recovery be increased by up to approximately $2 million. In addition, they recommended that TNC’s excess earnings be increased by approximately $5 million for carrying charges and its T&D rates be reduced by a maximum amount of approximately $3 million on an annual basis to reflect the return on excess earnings approved by the PUCT for the period 1999 through 2001. TNC does not agree with the intervenor’s reconciliation and filed rebuttal testimony. Management believes it has materially provided for all probable to date disallowances in TNC’s True-up Proceeding.

MICHIGAN RESTRUCTURING - Affecting I&M

Customer choice commenced for I&M’s Michigan customers on January 1, 2002. Effective with that date the rates on I&M’s Michigan customers’ bills for retail electric service were unbundled to allow customers the opportunity to evaluate the cost of generation service for comparison with other offers. I&M’s total base rates in Michigan remain unchanged and reflect cost of service. At December 31, 2004, none of I&M’s customers have elected to change suppliers and no alternative electric suppliers are registered to compete in I&M’s Michigan service territory. As a result, management has concluded that as of December 31, 2004 the requirements to apply SFAS 71 continue to be met since I&M’s rates for generation in Michigan continue to be cost-based regulated.

VIRGINIA RESTRUCTURING - Affecting APCo

In April 2004, the Governor of Virginia signed legislation that extends the transition period for electricity restructuring, including capped rates, through December 31, 2010. The legislation provides specified cost recovery opportunities during the capped rate period, including two optional bundled general base rate changes and an opportunity for timely recovery, through a separate rate mechanism, of certain incremental environmental and reliability costs incurred on and after July 1, 2004.

ARKANSAS RESTRUCTURING - Affecting SWEPCo

In February 2003, Arkansas repealed customer choice legislation originally enacted in 1999. Consequently, SWEPCo’s Arkansas operations reapplied SFAS 71 regulatory accounting, which had been discontinued in 1999. The reapplication of SFAS 71 had an insignificant effect on results of operations and financial condition.

WEST VIRGINIA RESTRUCTURING - Affecting APCo

In 2000, the Public Service Commission of West Virginia (WVPSC) issued an order approving an electricity restructuring plan, which the West Virginia Legislature approved by joint resolution. The joint resolution provided that the WVPSC could not implement the plan until the West Virginia legislature made tax law changes necessary to preserve the revenues of state and local governments.

In the 2001 and 2002 legislative sessions, the West Virginia Legislature failed to enact the required legislation that would allow the WVPSC to implement the restructuring plan. Due to this lack of legislative activity, the WVPSC closed two proceedings related to electricity restructuring during the summer of 2002.

In the 2003 legislative session, the West Virginia Legislature again failed to enact the required tax legislation. Also, legislation enacted in March 2003 clarified the jurisdiction of the WVPSC over electric generation facilities in West Virginia. In March 2003, APCo’s outside counsel advised us that restructuring in West Virginia was no longer probable and confirmed facts relating to the WVPSC’s jurisdiction and rate authority over APCo’s West Virginia generation. As a result, in March 2003 management concluded that deregulation of APCo’s West Virginia generation business was no longer probable and operations in West Virginia met the requirements to reapply SFAS 71. Reapplying SFAS 71 in West Virginia had an insignificant effect on 2003 results of operations and financial condition.

7.COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and OPCo

The Federal EPA and a number of states have alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints against AEP 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.

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 per day per violation at each generating unit ($25,000 per day prior to January 30, 1997). 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.

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, eight Northeastern States filed a separate complaint containing the same allegations against the Conesville and Amos plants that the judge disallowed in the pending case. AEP subsidiaries filed an answer to the complaint in January 2005, denying the allegations and stating their defenses.

On August 7, 2003, the District Court issued a decision following a liability trial in a case pending in the Southern District of Ohio against Ohio Edison Company, a nonaffiliated utility. The District Court held that replacements of major boiler and turbine components that are infrequently performed at a single unit, that are performed with the assistance of outside contractors, that are accounted for as capital expenditures, and that require the unit to be taken out of service for a number of months are not “routine” maintenance, repair, and replacement. The District Court also held that a comparison of past actual emissions to projected future emissions must be performed prior to any nonroutine physical change in order to evaluate whether an emissions increase will occur, and that increased hours of operation that are the result of eliminating forced outages due to the repairs must be included in that calculation. Based on these holdings, the District Court ruled that all of the challenged activities in that case were not routine, and that the changes resulted in significant net increases in emissions for certain pollutants. A remedy trial was scheduled for July 2004, but has been postponed to facilitate further settlement discussions.

Management believes that the Ohio Edison decision fails to properly evaluate and apply the applicable legal standards. The facts in our case also vary widely from plant to plant. Further, the Ohio Edison decision is limited to liability issues, and provides no insight as to the remedies that might ultimately be ordered by the Court.

On August 26, 2003, the District Court for the Middle District of South Carolina issued a decision on cross-motions for summary judgment prior to a liability trial in a case pending against Duke Energy Corporation, a nonaffiliated utility. The District Court denied all the pending motions, but set forth the legal standards that will be applied at the trial in that case. The District Court determined that the Federal EPA bears the burden of proof on the issue of whether a practice is “routine maintenance, repair, or replacement” and on whether or not a “significant net emissions increase” results from a physical change or change in the method of operation at a utility unit. However, the Federal EPA must consider whether a practice is “routine within the relevant source category” in determining if it is “routine.” Further, the Federal EPA must calculate emissions by determining first whether a change in the maximum achievable hourly emission rate occurred as a result of the change, and then must calculate any change in annual emissions holding hours of operation constant before and after the change. The Federal EPA has requested reconsideration of this decision, or in the alternative, certification of an interlocutory appeal to the Fourth Circuit Court of Appeals. The District Court denied the Federal EPA’s motion. On April 13, 2004, the parties filed a joint motion for entry of final judgment, based on stipulations of relevant facts that eliminated the need for a trial, but preserving plaintiffs’ right to seek an appeal of the federal prevention of significant deterioration (PSD) claims. On April 14, 2004, the Court entered final judgment for Duke Energy on all of the PSD claims made in the amended complaints, and dismissed all remaining claims with prejudice. The United States subsequently filed a notice of appeal to the Fourth Circuit Court of Appeals. The case is fully briefed and oral argument was heard on February 3, 2005.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued an order invalidating the administrative compliance order issued by the Federal EPA to the Tennessee Valley Authority for alleged CAA violations. The 11th Circuit determined that the administrative compliance order was not a final agency action, and that the enforcement provisions authorizing the issuance and enforcement of such orders under the CAA are unconstitutional. The United States filed a petition for certiorari with the United States Supreme Court and in May 2004, that petition was denied.

On June 26, 2003, the United States Court of Appeals for the District of Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG), of which AEP subsidiaries are members, to reopen petitions for review of the 1980 and 1992 CAA rulemakings that are the basis for the Federal EPA claims in our case and other related cases. On August 4, 2003, UARG filed a motion to separate and expedite review of their challenges to the 1980 and 1992 rulemakings from other unrelated claims in the consolidated appeal. The Circuit Court denied that motion on September 30, 2003. The central issue in these petitions concerns the lawfulness of the emissions increase test, as currently interpreted and applied by the Federal EPA in its utility enforcement actions. A decision by the D. C. Circuit Court could significantly impact further proceedings in our case. Briefing continues in this case and oral argument was held in January 2005.

On August 27, 2003, the Administrator of the Federal EPA signed a final rule that defines “routine maintenance repair and replacement” to include “functionally equivalent equipment replacement.” Under the new rule, replacement of a component within an integrated industrial operation (defined as a “process unit”) with a new component that is identical or functionally equivalent will be deemed to be a “routine replacement” if the replacement does not change any of the fundamental design parameters of the process unit, does not result in emissions in excess of any authorized limit, and does not cost more than twenty percent of the replacement cost of the process unit. The new rule is intended to have prospective effect, and was to become effective in certain states 60 days after October 27, 2003, the date of its publication in the Federal Register, and in other states upon completion of state processes to incorporate the new rule into state law. On October 27, 2003, twelve states, the District of Columbia and several cities filed an action in the United States Court of Appeals for the District of Columbia Circuit seeking judicial review of the new rule. The UARG has intervened in this case. On December 24, 2003, the Circuit Court granted a motion from the petitioners to stay the effective date of this rule, which had been December 26, 2003.

In December 2000, Cinergy Corp., a nonaffiliated utility, which operates certain plants jointly owned by CSPCo, reached a tentative agreement with the Federal EPA and other parties to settle litigation regarding generating plant emissions under the CAA. Negotiations are continuing between the parties in an attempt to reach final settlement terms. Cinergy’s settlement could impact the operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached, CSPCo will be unable to determine the settlement’s impact on its jointly-owned facilities and its future results of operations and cash flows.

On July 21, 2004, the Sierra Club issued a notice of intent to file a citizen suit claim against DPL, Inc., Cinergy Corporation, CSPCo, and The Dayton Power & Light Company for alleged violations of the New Source Review programs at the Stuart Station. CSPCo owns a 26% share of the Stuart Station. On September 21, 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio state implementation plan occurred at the Stuart Station, and seeking injunctive relief and civil penalties. The owners have filed a motion to dismiss portions of the complaint. Management believes the allegations in the complaint are without merit, and intends to defend vigorously this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. Management is 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 AEP subsidiaries do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered through regulated rates and market prices for electricity.

Notice of Enforcement and Notice of Citizen Suit - Affecting SWEPCo

On July 13, 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 SWEPCo's Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations made by a terminated AEP employee. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions.

On July 19, 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. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of volatile organic compound emissions at the Pirkey Plant, but after investigation determined further enforcement action was not warranted and withdrew the notice on January 5, 2005.

SWEPCo has previously reported to the TCEQ deviations related to the receipt of off-specification fuel at Knox Lee, the volatile organic compound emissions at Pirkey, and the referenced recordkeeping and reporting requirements and heat input value at Welsh. We have submitted additional responses to the Notice of Enforcement and the notice from the special interest groups. 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 - Affecting AEP System

On July 21, 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 and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions allege that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and seek 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. Management believes the actions are without merit and intends to defend vigorously against the claims.

NUCLEAR

Nuclear Plants - Affecting I&M and TCC

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on behalf of the joint owners under licenses granted by the NRC. The operation of a nuclear facility involves special risks, potential liabilities, and specific regulatory and safety requirements. Should a nuclear incident occur at any nuclear power plant facility in the U.S., the resultant liability could be substantial. By agreement, I&M and TCC are partially liable together with all other electric utility companies that own nuclear generating units for a nuclear power plant incident at any nuclear plant in the U.S. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, results of operations, cash flows and financial condition would be adversely affected.

Nuclear Incident Liability - Affecting I&M and TCC

The Price-Anderson Act establishes insurance protection for public liability arising from a nuclear incident at $10.8 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance provides $300 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $101 million on each licensed reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be assessed $202 million per nuclear incident payable in annual installments of $20 million. TCC could be assessed $50 million per nuclear incident payable in annual installments of $5 million as its share of a STPNOC assessment. The number of incidents for which payments could be required is not limited.

Under an industry-wide program insuring workers at nuclear facilities, I&M and TCC are also obligated for assessments of up to $6 million and $2 million, respectively, for potential claims. These obligations will remain in effect until December 31, 2007.

Insurance coverage for property damage, decommissioning and decontamination at the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8 billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for extra costs resulting from a prolonged accidental outage. I&M and STPNOC utilize an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurer requires a contingent financial obligation of up to $43 million for I&M and $2 million for TCC which is assessable if the insurer’s financial resources would be inadequate to pay for losses.

The current Price-Anderson Act expired in August 2002. Its contingent financial obligations still apply to reactors licensed by the NRC as of its expiration date. It is anticipated that the Price-Anderson Act will be renewed in 2005 with increases in required third party financial protection for nuclear incidents.

SNF Disposal - Affecting I&M and TCC

Federal law provides for government responsibility for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being collected from customers and remitted to the U.S. Treasury. Fees and related interest of $229 million for fuel consumed prior to April 7, 1983 at Cook Plant have been recorded as long-term debt. I&M has not paid the government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. At December 31, 2004, funds collected from customers towards payment of the pre-April 1983 fee and related earnings thereon are in external funds and exceed the liability amount. TCC is not liable for any assessments for nuclear fuel consumed prior to April 7, 1983 since the STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal - Affecting I&M and TCC

Decommissioning costs are accrued over the service lives of the Cook Plant and STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014 and 2017. In November 2003, I&M filed to extend the operating licenses of the two Cook Plant units for up to an additional 20 years. The review of the license extension application is expected to take at least two years. After expiration of the licenses, Cook Plant is expected to be decommissioned using the prompt decontamination and dismantlement (DECON) method. The estimated cost of decommissioning and low-level radioactive waste accumulation disposal costs for Cook Plant ranges from $889 million to $1.1 billion in 2003 nondiscounted dollars. The wide range is caused by variables in assumptions including the estimated length of time SNF may need to be stored at the plant site subsequent to ceasing operations. This, in turn, depends on future developments in the federal government's SNF disposal program. Continued delays in the federal fuel disposal program can result in increased decommissioning costs. I&M is recovering estimated Cook Plant decommissioning costs in its three rate-making jurisdictions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding. The amount recovered in rates for decommissioning the Cook Plant and deposited in the external fund was $27 million in 2004, 2003 and 2002.

The licenses to operate the two nuclear units at STP expire in 2027 and 2028. After expiration of the licenses, STP is expected to be decommissioned using the DECON method. In May 2004, an updated decommissioning study was completed for STP. The study estimates TCC’s share of the decommissioning costs of STP to be $344 million in nondiscounted 2004 dollars. TCC is accruing and recovering these decommissioning costs through rates based on the service life of STP at a rate of approximately $8 million per year. As discussed in Note 10, TCC is in the process of selling its ownership interest in STP to two nonaffiliates, and upon completion of the sale, it is anticipated that TCC will no longer be obligated for nuclear decommissioning liabilities associated with STP.

Decommissioning costs recovered from customers are deposited in external trusts. I&M deposited in its decommissioning trust an additional $4 million in 2004 and $12 million in both 2003 and 2002 related to special regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund earnings increase the fund assets and decrease the amount needed to be recovered from ratepayers. Decommissioning costs including interest, unrealized gains and losses and expenses of the trust funds are recorded in Other Operation expense for Cook Plant. For STP, nuclear decommissioning costs are recorded in Other Operation expense, interest income of the trusts are recorded in Nonoperating Income and interest expense of the trust funds are included in Interest Charges.

TCC’s nuclear decommissioning trust asset and liability are included in held for sale amounts on its Consolidated Balance Sheets.

OPERATIONAL

Construction and Commitments- Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The AEP System has substantial construction commitments to support its operations. The following table shows the estimated construction expenditures by company for 2005 including amounts for proposed environmental rules:

	(in millions)
AEGCo	$	19.9
APCo		696.7
CSPCo		193.9
I&M		322.8
KPCo		56.1
OPCo		765.6
PSO		126.2
SWEPCo		200.9
TCC		208.5
TNC		73.9

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.

AEP subsidiaries have entered into long-term contracts to acquire fuel for electric generation. The expiration date of the longest fuel contract is 2010 for APCo, 2008 for CSPCo, 2014 for I&M, 2008 for KPCo, 2012 for OPCo, 2007 for PSO and 2012 for SWEPCo. The contracts provide for periodic price adjustments and contain various clauses that would release us from our obligations under certain conditions.

I&M has a unit contingent contract to supply approximately 250 MW of capacity to a nonaffiliated entity through December 31, 2009. The commitment is pursuant to a unit power agreement requiring the delivery of energy only if the unit capacity is available.

Potential Uninsured Losses - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

Power Generation Facility - Affecting OPCo

AEP has 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 AEP. AEP has subleased the Facility to the Dow Chemical Company (Dow) under a 5-year term with three 5-year renewal terms for a total term of up to 20 years. The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo has 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 270 MW).

OPCo has also agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) 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 purpose of the PPA began April 2, 2004.

On September 5, 2003, TEM and OPCo separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. OPCo alleges that TEM has breached the PPA, and is seeking a determination of OPCo’s rights under the PPA. TEM alleges that the PPA never became enforceable, or alternatively, that the PPA has already been terminated as the result of OPCo’s breaches. If the PPA is deemed terminated or found to be unenforceable by the court, OPCo could be adversely affected to the extent it is unable to find other purchasers of the power with similar contractual terms and to the extent OPCo does not fully recover claimed termination value damages from TEM. However, OPCo has entered into an agreement with an affiliate that eliminates OPCo’s market exposure related to the PPA. The corporate parent of TEM (Tractebel SA) has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final resolution in arbitration of all issues pertaining to the protocols relating to the dispatching, operation, and maintenance of the Facility and the sale and delivery of electric power products. In the arbitration proceedings, TEM argued that in the absence of mutually agreed upon protocols there was no commercially reasonable means to obtain or deliver the electric power products and therefore the PPA is not enforceable. TEM further argued that the creation of the protocols is not subject to arbitration. The arbitrator ruled in favor of TEM on February 11, 2004 and concluded that the “creation of protocols” was not subject to arbitration, but did not rule upon the merits of TEM’s claim that the PPA is not enforceable. On January 21, 2005, the District Court granted OPCo partial summary judgment on this issue, holding that the absence of operating protocols does not prevent enforcement of the PPA. The litigation is in the discovery phase, with trial scheduled to begin in March 2005.

On March 26, 2004, OPCo requested that TEM provide assurances of performance of its future obligations under the PPA, but TEM refused to do so. As indicated above, OPCo also gave notice to TEM and declared April 2, 2004 as the “Commercial Operations Date.” Despite OPCo’s prior tenders of replacement electric power products to TEM beginning May 1, 2003 and despite OPCo’s tender of electric power products from the Facility to TEM beginning April 2, 2004, TEM refused to accept and pay for these electric power products under the terms of the PPA. On April 5, 2004, OPCo gave notice to TEM that OPCo, (i) was suspending performance of its obligations under the PPA, (ii) would be seeking a declaration from the District Court that the PPA has been terminated and (iii) would be pursuing against TEM, and Tractebel SA under the guaranty, damages and the full termination payment value of the PPA.

Merger Litigation - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ. We expect an initial decision from the ALJ later this year. The SEC will review the initial decision.

Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.

Enron Bankruptcy -Affecting APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPL from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas-related trading transactions. AEP asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding, court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding, court-sponsored mediation.

The amount expensed in prior years in connection with the Enron bankruptcy was based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on results of operations, cash flows or financial condition.

Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal District Court in Corpus Christi, Texas, in July 2003, against AEP and four AEP subsidiaries, including TCC and TNC, certain nonaffiliated energy companies and ERCOT. The action alleges violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. AEP and its subsidiaries filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. AEP and its subsidiaries filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit.

Coal Transportation Dispute - Affecting PSO, TCC and TNC

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, have disputed transportation costs for coal received between July 2000 and the present time. The joint plant has remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded a provision for possible loss in December 2004. The provision was deferred as a regulatory asset under PSO’s fuel mechanism and affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

FERC Long-term Contracts - Affecting AEP East and AEP West Companies

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 AEP subsidiaries 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 had 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 had failed to demonstrate that the public interest required that 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.

8.GUARANTEES

There are certain immaterial liabilities recorded for guarantees entered subsequent to December 31, 2002 in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Letters of Credit

Certain Registrant Subsidiaries have entered into standby letters of credit (LOC) with third parties. These LOCs cover insurance programs, security deposits, debt service reserves, and credit enhancements for issued bonds. All of these LOCs were issued in the subsidiaries’ ordinary course of business. At December 31, 2004, the maximum future payments of the LOCs include $44 million, $1 million, $51 million, $4 million and $43 million for CSPCo, I&M, OPCo, SWEPCo and TCC, respectively, with maturities ranging from March 2005 to April 2007. There is no recourse to third parties in the event these letters of credit are drawn.

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo has agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $53 million with maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo has agreed to provide 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 a third party miner. At December 31, 2004, the cost to reclaim the mine in 2035 is estimated to be approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46. SWEPCo does not have an ownership interest in Sabine.

Indemnifications and Other Guarantees

All of the Registrant Subsidiaries enter into certain types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Registrant Subsidiaries cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events. In 2004 and 2003, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary except for TCC which entered an indemnification of $129 million relating to the sale of its generation assets in July 2004 (see “Texas Plants - TCC and TNC Generation Assets” section of Note 10). There are no material liabilities recorded for any indemnifications entered during 2004 or 2003. There are no liabilities recorded for any indemnifications entered prior to December 31, 2002.

Registrant Subsidiaries are jointly and severally liable for activity conducted by AEPSC on behalf of AEP East and West companies and for activity conducted by any Registrant Subsidiary pursuant to the system integration agreement.

Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive 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, the subsidiary has 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 December 31, 2004, the maximum potential loss by subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:

Maximum Potential Loss
Subsidiary	(in millions)
APCo	$	5
CSPCo		2
I&M		3
KPCo		1
OPCo		4
PSO		4
SWEPCo		4
TCC		6
TNC		3

9.SUSTAINED EARNINGS IMPROVEMENT INITIATIVE

In response to difficult conditions in AEP’s business, a Sustained Earnings Improvement (SEI) initiative was undertaken company-wide in the fourth quarter of 2002, as a cost-saving and revenue-building effort to build long-term earnings growth.

The Registrant Subsidiaries recorded termination benefits expense relating to 389 terminated employees totaling $57.9 million pretax in the fourth quarter of 2002. Of this amount, the Registrant Subsidiaries paid $5.0 million to these terminated employees in the fourth quarter of 2002. No additional termination benefits expense related to the SEI initiative was recorded in 2004 or 2003. The remaining SEI related payments were made in 2003. The termination benefits expense is classified as Other Operation expense on the Registrant Subsidiaries’ statements of operations. Management determined that the termination of the employees under the SEI initiative did not constitute a plan curtailment of any of the retirement benefit plans.

The following table shows the staff reductions, termination benefits expense and the remaining termination benefits expense accrual as of December 31, 2002:

	Total Number of Terminated Employees		Total Expense Recorded in 2002 (in millions)		Total Termination Benefits Accrued at December 31, 2002 (in millions)
AEGCo		-	$	0.3	$	0.3
APCo		93		13.1		12.2
CSPCo		19		5.0		4.5
I&M		146		15.0		13.1
KPCo		16		2.6		2.5
OPCo		33		7.5		7.1
PSO		17		3.1		3.0
SWEPCo		8		3.3		3.1
TCC		37		6.0		5.5
TNC		20		2.0		1.6

10.DISPOSITIONS, IMPAIRMENTS, ASSETS HELD FOR SALE AND ASSETS HELD AND USED

DISPOSITIONS

2004

Texas Plants - TCC and TNC Generation Assets

In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted reliability studies, which determined that seven plants (4 TCC plants and 3 TNC plants) would be required to ensure reliability of the electricity grid. As a result of those studies, ERCOT and AEP mutually agreed to enter into reliability-must-run (RMR) agreements, which expired in December 2002, and were subsequently renewed through December 2003. However, certain contractual provisions provided ERCOT with a 90-day termination clause if the contracted facility was no longer needed to ensure reliability of the electricity grid. With ERCOT’s approval, AEP proceeded with its planned deactivation of the remaining nine plants. In August 2003, pursuant to contractual terms, ERCOT provided notification to AEP of its intent to cancel a RMR agreement at one of the TNC plants. Upon termination of the agreement, AEP proceeded with its planned deactivation of the plant. In December 2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants (4 TCC plants and 2 TNC plants) through December 2004, subject to ERCOT’s 90-day termination clause and the divestiture of the TCC facilities.

As a result of the decision to deactivate TNC plants, a pretax write-down of utility assets of approximately $34 million was recorded in Asset Impairments expense during the third quarter of 2002 on TNC’s Statements of Operations. The decision to deactivate the TCC plants resulted in a pretax write-down of utility assets of approximately $96 million, which was deferred and recorded in Regulatory Assets during the third quarter of 2002 in TCC’s Consolidated Balance Sheets.

During the fourth quarter of 2002, evaluations continued as to whether assets remaining at the deactivated plants, including materials, supplies and fuel oil inventories, could be utilized elsewhere within the AEP System. As a result of such evaluations, TNC recorded an additional pretax asset impairment charge to Asset Impairments expense of $4 million in the fourth quarter of 2002. In addition, TNC recorded related inventory write-downs of $3 million ($1 million of fuel inventory in Fuel for Electric Generation expense and $1 million of materials and supplies recorded in Other Operation expense). Similarly, TCC recorded an additional pretax asset impairment write-down of $7 million, which was deferred and recorded in Regulatory Assets Designated for Securitization in the fourth quarter of 2002. TCC also recorded related inventory write-downs and adjustments of $18 million which were deferred and recorded in Regulatory Assets.

The total Texas plant pretax asset impairment of $38 million in 2002 related to TNC is included in Asset Impairments expense in TNC’s Statements of Operations.

In December 2002, TCC filed a plan of divestiture with the PUCT proposing to sell all of its power generation assets, including the eight gas-fired generating plants that were either deactivated or designated as “reliability-must-run” status.

During the fourth quarter of 2003, after receiving indicative bids from interested buyers, TCC recorded a $938 million impairment loss and changed the classification of the plant assets from plant in service to Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets. In accordance with Texas Restructuring Legislation, the $938 million impairment was offset by the establishment of a regulatory asset, which is expected to be recovered through a wires charge, subject to the final outcome of the True-up Proceeding. As a result of the True-up Proceeding, if TCC is unable to recover all or a portion of its requested costs (see “Net Stranded Generation Costs” section of Note 6), any unrecovered costs could have a material adverse effect on TCC’s results of operations, cash flows and possibly financial condition.

In March 2004, TCC signed an agreement to sell eight natural gas plants, one coal-fired plant and one hydro plant to a nonrelated joint venture. The sale was completed in July 2004 for approximately $428 million, net of adjustments. The sale did not have a significant effect on TCC’s results of operations during the period ending December 31, 2004.

In December 2004, TCC recorded a $185 pretax deduction ($121 net of tax) related to the TCC true-up regulatory asset for stranded generation plant costs (see “Net Stranded Generation Costs” section of Note 6). This deduction is shown as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax on TCC’s 2004 Consolidated Statements of Income.

The remaining generation assets and liabilities of TCC are classified as Assets of Discontinued Operations and Held for Sale and Liabilities of Discontinued Operations and Held for Sale, respectively, on TCC’s Consolidated Balance Sheets.

2003

Water Heater Assets - APCo, CSPCo, I&M, KPCo and OPCo

APCo, CSPCo, I&M, KPCo and OPCo participated in a program to lease electric water heaters to residential and commercial customers until a decision was reached in the fourth quarter of 2002 to discontinue the program and offer the assets for sale. We sold our water heater rental program and recorded a pretax loss in the first quarter of 2003 based upon final terms of the sale agreement. We provided for pretax charges in the fourth quarter of 2002 based on an estimated sales price. See below for amounts by company:

Subsidiary Company	Asset Impairment Charge Recorded in Fourth Quarter 2002 (Pretax)		Lease Prepayment Penalty Recorded in Fourth Quarter 2002 (Pretax)		Loss on Sale Recorded in First Quarter 2003 (Pretax)
	(in millions)
APCo	$	0.050	$	0.062	$	0.056
CSPCo		0.615		0.758		0.740
I&M		0.643		0.792		0.787
KPCo		0.011		0.011		0.011
OPCo		1.757		2.163		2.165

Ft. Davis Wind Farm - TNC

In the 1990’s, TNC developed a 6 MW facility wind energy project located on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002, TNC’s engineering staff determined that operation of the facility was no longer technically feasible and the lease of the underlying site should not be renewed. Dismantling of the facility was completed in 2004. An estimated pretax loss on abandonment of $5 million was recorded in December 2002. The loss was recorded in Asset Impairments on TNC’s Statements of Operations.

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station

In January 2004, TCC signed an agreement to sell its 7.81% share of Oklaunion Power Station for approximately $43 million, subject to closing adjustments, to an unrelated party. In May 2004, TCC received notice from the two 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, TCC entered into sales agreements with both of its nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. One of these agreements is currently being challenged in Dallas County, Texas State District Court by the unrelated party with which TCC entered into the original sales agreement. The unrelated party alleges that one co-owner has exceeded its legal authority and that the second co-owner did not exercise its right of first refusal in a timely manner. The unrelated party has requested that the court declare the co-owners’ exercise of their rights of first refusal void. TCC cannot predict when these issues will be resolved. TCC does not expect the sale to have a significant effect on its future results of operations. TCC’s assets and liabilities related to the Oklaunion Power Station have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets.

Texas Plants - South Texas Project

In February 2004, TCC signed an agreement to sell its 25.2% share of the STP nuclear plant to an unrelated party for approximately $333 million, subject to closing adjustments. In June 2004, TCC received notice from co-owners of their decisions to exercise their rights of first refusal with terms similar to the original agreement. In September 2004, TCC entered into sales agreements with two of its nonaffiliated co-owners for the sale of TCC’s 25.2% share of the STP nuclear plant. TCC does not expect the sale to have a significant effect on its future results of operations. TCC expects the sale to close in the first six months of 2005. TCC’s assets and liabilities related to STP have been classified as Assets Held for Sale - Texas Generation Plants and Liabilities Held for Sale - Texas Generation Plants, respectively, in TCC’s Consolidated Balance Sheets as of December 31, 2004 and 2003.

The assets and liabilities of the entities held for sale at December 31, 2004 and 2003 are as follows:

	Texas Plants (TCC) December 31,
	2004		2003
	(in millions)
Assets:
Current Assets	$	24	$	57
Property, Plant and Equipment, Net		413		797
Regulatory Assets		48		49
Nuclear Decommissioning Trust Fund		143		125
Total Assets Held for Sale - Texas Generation Plants	$	628	$	1,028
Liabilities:
Regulatory Liabilities - Other	$	1	$	9
Asset Retirement Obligations		249		219
Total Liabilities Held for Sale - Texas Generation Plants	$	250	$	228

ASSETS HELD AND USED

Blackhawk Coal Company - I&M

Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M and was formerly engaged in coal mining operations until they ceased due to gas explosions in the mine. During the fourth quarter of 2003, it was determined that the carrying value of the investment was impaired based on an updated valuation reflecting management’s decision not to pursue development of potential gas reserves. As a result, a pretax charge of $10 million was recorded to reduce the value of the coal and gas reserves to their estimated realizable value. This charge was recorded in Nonoperating Expenses in I&M’s Consolidated Statements of Income.

11.BENEFIT PLANS

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees in the U.S. APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FSP FAS 106-2 in the second quarter of 2004, retroactive to the first quarter of 2004 (see “FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” section of Note 2). The Medicare subsidy reduced the FAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service by $202 million contributing to an actuarial gain in 2004. The tax-free subsidy reduced 2004’s net periodic postretirement benefit cost by a total of $29 million, including $12 million of amortization of the actuarial gain, $4 million of reduced service cost, and $13 million of reduced interest cost on the APBO.

The following table provides the reduction in the net periodic postretirement cost for 2004 for the Registrant Subsidiaries:

	Postretirement Benefit Cost Reduction
	(in thousands)
APCo	$	5,208
CSPCo		2,417
I&M		3,647
KPCo		690
OPCo		4,106
PSO		1,520
SWEPCo		1,571
TCC		1,849
TNC		770

The following tables provide a reconciliation of the changes in the plans’ projected benefit obligations and fair value of assets over the two-year period ending at the plan’s measurement date of December 31, 2004, and a statement of the funded status as of December 31 for both years:

Pension Obligations, Plan Assets, Funded Status as of December 31, 2004 and 2003:

	Pension Plans						Other Postretirement Benefit Plans
	2004			2003			2004			2003
	(in millions)
Change in Projected Benefit Obligation:
Projected Obligation at January 1	$	3,688		$	3,583		$	2,163		$	1,877
Service Cost		86			80			41			42
Interest Cost		228			233			117			130
Participant Contributions		-			-			18			14
Actuarial (Gain) Loss		379			91			(130	)		192
Benefit Payments		(273	)		(299	)		(109	)		(92	)
Projected Obligation at December 31	$	4,108		$	3,688		$	2,100		$	2,163
Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1	$	3,180		$	2,795		$	950		$	723
Actual Return on Plan Assets		409			619			98			122
Company Contributions (a)		239			65			136			183
Participant Contributions		-			-			18			14
Benefit Payments (a)		(273	)		(299	)		(109	)		(92	)
Fair Value of Plan Assets at December 31	$	3,555		$	3,180		$	1,093		$	950
Funded Status:
Funded Status at December 31	$	(553	)	$	(508	)	$	(1,007	)	$	(1,213	)
Unrecognized Net Transition Obligation		-			2			179			206
Unrecognized Prior Service Cost (Benefit)		(9	)		(12	)		5			6
Unrecognized Net Actuarial Loss		1,040			797			795			977
Net Asset (Liability) Recognized	$	478		$	279		$	(28	)	$	(24	)

(a) AEP’s contributions and benefit payments include only those amounts contributed directly to or paid directly from plan assets.

Amounts Recognized in the Balance Sheet as of December 31, 2004 and 2003:

	Pension Plans						Other Postretirement Benefit Plans
	2004			2003			2004			2003
	(in millions)
Prepaid Benefit Costs	$	524	(a)	$	325		$	-		$	-
Accrued Benefit Liability		(46	)		(46	)		(28	)		(24	)
Additional Minimum Liability		(566	)		(723	)		N/A			N/A
Intangible Asset		36			39			N/A			N/A
Pretax Accumulated Other Comprehensive Income		530			684			N/A			N/A
Net Asset (Liability) Recognized	$	478		$	279		$	(28	)	$	(24	)

N/A = Not Applicable

(a)  Includes $386 million related to the qualified plan that became fully funded upon receipt of the December 2004 discretionary contribution.

Pension and Other Postretirement Plans’ Assets:

The asset allocations for AEP’s pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2005		2004		2003
Asset Category	(in percentages)
Equity Securities		70		68		71
Debt Securities		28		25		27
Cash and Cash Equivalents		2		7		2
Total		100		100		100

The asset allocations for AEP’s other postretirement benefit plans at the end of 2004 and 2003, and target allocation for 2005, by asset category, are as follows:

	Target Allocation		Percentage of Plan Assets at Year End
	2005		2004		2003
Asset Category	(in percentages)
Equity Securities		70		70		61
Debt Securities		28		28		36
Other		2		2		3
Total		100		100		100

AEP’s investment strategy for their employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation when considered appropriate. Because of a $200 million discretionary contribution at the end of 2004, the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2005.

The value of AEP’s pension plans’ assets increased to $3.6 billion at December 31, 2004 from $3.2 billion at December 31, 2003. The qualified plans paid $265 million in benefits to plan participants during 2004 (nonqualified plans paid $8 million in benefits).

AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.

Accumulated Benefit Obligation:

	2004		2003
	(in millions)
Qualified Pension Plans	$	3,918	$	3,549
Nonqualified Pension Plans		80		76
Total	$	3,998	$	3,625

Minimum Pension Liability:

AEP’s combined pension funds are underfunded in total (plan assets are less than projected benefit obligations) by $553 million at December 31, 2004. For AEP’s underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets of these plans at December 31, 2004 and 2003 were as follows:

	Underfunded Pension Plans
End of Year	2004		2003
	(in millions)
Projected Benefit Obligation	$	2,978	$	3,688
Accumulated Benefit Obligation		2,880		3,625
Fair Value of Plan Assets		2,406		3,180
Accumulated Benefit Obligation Exceeds the Fair Value of Plan Assets		474		445

A minimum pension liability is recorded for pension plans with an accumulated benefit obligation in excess of the fair value of plan assets. The minimum pension liability for the underfunded pension plans declined during 2004 and 2003, resulting in the following favorable changes, which do not affect earnings or cash flow:

	Decrease in Minimum Pension Liability
	2004			2003
	(in millions)
Other Comprehensive Income	$	(92	)	$	(154	)
Deferred Income Taxes		(52	)		(75	)
Intangible Asset		(3	)		(5	)
Other		(10	)		13
Minimum Pension Liability	$	(157	)	$	(221	)

AEP made an additional discretionary contribution of $200 million in the fourth quarter of 2004 and intends to make additional discretionary contributions of approximately $100 million per quarter in 2005 to meet its goal of fully funding all qualified pension plans by the end of 2005.

Actuarial Assumptions for Benefit Obligations:

The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:

	Pension Plans		Other Postretirement Benefit Plans
	2004	2003	2004	2003
	(in percentages)
Discount Rate	5.50	6.25	5.80	6.25
Rate of Compensation Increase	3.70	3.70	N/A	N/A

The method used to determine the discount rate that AEP utilizes for determining future benefit obligations was revised in 2004. Historically, it has been based on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, AEP changed to a duration based method where a hypothetical portfolio of high quality corporate bonds was constructed with a duration similar to the duration of the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for pension plans and 5.80% for other postretirement benefit plans.

The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.

Estimated Future Benefit Payments and Contributions:

Information about the expected cash flows for the pension (qualified and nonqualified) and other postretirement benefit plans is as follows:

	Pension Plans				Other Postretirement Benefit Plans
Employer Contributions	2005		2004		2005	2004
	(in millions)
Required Contributions (a)	$17		$31		N/A	N/A
Additional Discretionary Contributions	400	(b)	200	(b)	$142	$137

(a)	Contribution required to meet minimum funding requirement per the U.S. Department of Labor.
(b)	Contribution in 2004 and expected contribution in 2005 in excess of the required contribution to fully fund AEP’s qualified pension plans by the end of 2005.

The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ expense for accounting purposes and is provided for in agreements with state regulatory authorities.

The table below reflects the total benefits expected to be paid from the plan or from AEP’s assets, including both AEP’s share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates, and variances in actuarial results. The estimated payments for pension benefits and other postretirement benefits are as follows:

	Pension Plans		Other Postretirement Benefit Plans
	Pension Payments		Benefit Payments		Medicare Subsidy Receipts
	(in millions)
2005	$	293	$	115	$	-
2006		302		122		(9	)
2007		317		131		(10	)
2008		327		140		(11	)
2009		348		151		(12	)
Years 2010 to 2014, in Total		1,847		867		(72	)

Components of Net Periodic Benefit Cost:

The following table provides the components of AEP’s net periodic benefit cost (credit) for the plans for fiscal years 2004, 2003 and 2002:

	Pension Plans									Other Postretirement Benefit Plans
	2004			2003			2002			2004			2003			2002
	(in millions)
Service Cost	$	86		$	80		$	72		$	41		$	42		$	34
Interest Cost		228			233			241			117			130			114
Expected Return on Plan Assets		(292	)		(318	)		(337	)		(81	)		(64	)		(62	)
Amortization of Transition (Asset) Obligation		2			(8	)		(9	)		28			28			29
Amortization of Prior Service Cost		(1	)		(1	)		(1	)		-			-			-
Amortization of Net Actuarial (Gain) Loss		17			11			(10	)		36			52			27
Net Periodic Benefit Cost (Credit)		40			(3	)		(44	)		141			188			142
Capitalized Portion		(10	)		(3	)		15			(46	)		(43	)		(26	)
Net Periodic Benefit Cost (Credit)     Recognized as Expense	$	30		$	(6	)	$	(29	)	$	95		$	145		$	116

Net Pension Cost by Registrant:

The following table provides the net periodic benefit cost (credit) for the plans by the following Registrant Subsidiaries for fiscal years 2004, 2003 and 2002:

	Pension Plans									Other Postretirement Benefit Plans
	2004			2003			2002			2004		2003		2002
	(in thousands)
APCo	$	1,272		$	(5,202	)	$	(9,988	)	$	25,783	$	33,682	$	25,153
CSPCo		(1,626	)		(5,399	)		(8,328	)		11,050		14,684		11,494
I&M		4,460			(812	)		(4,149	)		17,259		22,999		17,608
KPCo		571			(566	)		(1,405	)		2,961		4,043		2,986
OPCo		(128	)		(6,621	)		(11,327	)		21,038		28,208		22,654
PSO		2,795			(291	)		(3,708	)		8,449		9,885		8,436
SWEPCo		3,602			1,018			(2,162	)		8,400		10,264		8,371
TCC		2,987			(123	)		(4,560	)		10,144		12,951		10,733
TNC		1,351			606			(993	)		4,280		5,875		4,798

Actuarial Assumptions for Net Periodic Benefit Costs:

The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:

	Pension Plans						Other Postretirement Benefit Plans
	2004		2003		2002		2004		2003		2002
	(in percentages)
Discount Rate		6.25		6.75		7.25		6.25		6.75		7.25
Expected Return on Plan Assets		8.75		9.00		9.00		8.35		8.75		8.75
Rate of Compensation Increase		3.70		3.70		3.70		N/A		N/A		N/A

The expected return on plan assets for 2004 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as unrelated business income taxes) was reduced to 8.35%.

The health care trend rate assumptions used for other postretirement benefit plans measurement purposes are shown below:

Health Care Trend Rates:	2004			2003
Initial		10.0	%		10.0	%
Ultimate		5.0	%		5.0	%
Year Ultimate Reached		2009			2008

Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit health care plans. A 1% change in assumed health care cost trend rates would have the following effects:

	1% Increase		1% Decrease
	(in millions)
Effect on Total Service and Interest Cost Components of Net Periodic Postretirement   Health Care Benefit Cost	$	27	$	(21	)
Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation		302		(245	)

Retirement Savings Plan

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in an AEP sponsored defined contribution retirement savings plan eligible to substantially all non-United Mine Workers of America (UMWA) employees. This plan includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. Prior to January 1, 2003, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participated in two large AEP sponsored defined contribution retirement savings plans. The contributions to the plan are 75% of the first 6% of eligible employee compensation.

The following table provides the cost for contributions to the retirement savings plans by the following Registrant Subsidiaries for fiscal years 2004, 2003 and 2002:

	2004		2003		2002
	(in thousands)
APCo	$	6,538	$	6,450	$	6,722
CSPCo		2,723		2,745		2,784
I&M		7,262		7,616		8,039
KPCo		1,030		1,042		1,043
OPCo		5,688		5,719		5,785
PSO		2,731		2,350		2,260
SWEPCo		3,571		3,418		3,170
TCC		2,544		2,757		3,054
TNC		1,126		1,332		1,574

Other UMWA Benefits

OPCo provides UMWA pension, health and welfare benefits for certain unionized mining employees, retirees, and their survivors who meet eligibility requirements. UWMA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds. The health and welfare benefits are administered by AEP and benefits are paid from AEP’s general assets. Contributions are expensed as paid as part of the cost of active mining operations and were not material in 2004, 2003 and 2002.

12.BUSINESS SEGMENTS

All of AEP’s Registrant Subsidiaries have one reportable segment. The one reportable segment is a vertically integrated electricity generation, transmission and distribution business except AEGCo, an electricity generation business. All of the Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of bundled cost-based rates and regulatory oversight on the business process, cost structures and operating results.

13.DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS

DERIVATIVES AND HEDGING

SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. However, energy markets are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

Registrant Subsidiaries’ accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Contracts that have been designated as normal purchase or normal sale under SFAS 133 are not considered derivatives and are recognized on the accrual or settlement basis.

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on if the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Registrant Financial Statements. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses in the Consolidated Statements of Operations depending on the relevant facts and circumstances.

The Registrant Subsidiaries designate the hedging instrument, based on the exposure being hedged, as a fair value hedge or cash flow hedge. For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in Revenues in the Registrant Financial Statements during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) and subsequently reclassify it to Revenues in the Registrant Financial Statements when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change.

Fair Value Hedging Strategies

Certain Registrant Subsidiaries enter into interest rate forward and swap transactions in order to manage interest rate risk exposure. The interest rate forward and swap transactions effectively modify exposure to interest risk by converting a portion of our fixed-rate debt to a floating rate. Registrant Subsidiaries do not hedge all interest rate exposure.

Cash Flow Hedging Strategies

Certain Registrant Subsidiaries enter into forward contracts to protect against the reduction in value of forecasted cash flows resulting from transactions denominated in foreign currencies. When the dollar strengthens significantly against the foreign currencies, the decline in value of future foreign currency revenue is offset by gains in the value of the forward contracts designated as cash flow hedges. Conversely, when the dollar weakens, the increase in the value of future foreign currency cash flows is offset by losses in the value of forward contracts. Registrant Subsidiaries do not hedge all foreign currency exposure.

Certain Registrant Subsidiaries enter into interest rate forward and swap transactions in order to manage interest rate risk exposure. These transactions effectively modify exposure to interest risk by converting a portion of floating-rate debt to a fixed rate. During 2004, certain Registrant Subsidiaries also entered into various forward starting interest rate swap contracts to manage the interest rate exposure on anticipated borrowings of fixed-rate debt through the second quarter of 2005. The anticipated debt offerings have a high probability of occurrence because the proceeds will be utilized to fund existing debt maturities as well as fund projected capital expenditures. Registrant Subsidiaries do not hedge all interest rate exposure. During 2004, APCO and I&M reclassified immaterial amounts to earnings because the original forecasted transaction did not occur within the originally specified time period.

Registrant Subsidiaries enter into, and designate as cash flow hedges, certain forward and swap transactions for the purchase and sale of electricity to manage the variable price risk related to the forecasted purchase and sale of electricity. We closely monitor the potential impact of commodity price changes and, where appropriate, enter into contracts to protect margin for a portion of future sales and generation revenues. Registrant Subsidiaries do not hedge all variable price risk exposure related to the forecasted purchase and sale of electricity. During 2004, certain Registrant Subsidiaries classified immaterial amounts into earnings as a result of hedge ineffectiveness related to cash flow hedging strategies.

The following table represents the activity in Accumulated Other Comprehensive Income (Loss) for derivative contracts that qualify as cash flow hedges for the years 2002, 2003 and 2004:

	(in thousands)
APCo
Beginning Balance at December 31, 2001	$	(340	)
Effective portion of changes in fair value		(1,310	)
Reclasses from AOCI to net income		(270	)
Balance at December 31, 2002		(1,920	)
Effective portion of changes in fair value		(448	)
Reclasses from AOCI to net income		799
Balance at December 31, 2003		(1,569	)
Effective portion of changes in fair value		(6,269	)
Reclasses from AOCI to net income		(1,486	)
Ending Balance, December 31, 2004	$	(9,324	)
CSPCo
Beginning Balance at December 31, 2001	$	-
Effective portion of changes in fair value		62
Reclasses from AOCI to net income		(329	)
Balance at December 31, 2002		(267	)
Effective portion of changes in fair value		194
Reclasses from AOCI to net income		275
Balance at December 31, 2003		202
Effective portion of changes in fair value		2,304
Reclasses from AOCI to net income		(1,113	)
Ending Balance, December 31, 2004	$	1,393
I&M
Beginning Balance at December 31, 2001	$	(3,835	)
Effective portion of changes in fair value		34
Reclasses from AOCI to net income		3,515
Balance at December 31, 2002		(286	)
Effective portion of changes in fair value		209
Reclasses from AOCI to net income		299
Balance at December 31, 2003		222
Effective portion of changes in fair value		(3,141	)
Reclasses from AOCI to net income		(1,157	)
Ending Balance, December 31, 2004	$	(4,076	)
KPCo
Beginning Balance at December 31, 2001	$	(1,903	)
Effective portion of changes in fair value		343
Reclasses from AOCI to net income		1,882
Balance at December 31, 2002		322
Effective portion of changes in fair value		75
Reclasses from AOCI to net income		23
Balance at December 31, 2003		420
Effective portion of changes in fair value		918
Reclasses from AOCI to net income		(525	)
Ending Balance, December 31, 2004	$	813
OPCo
Beginning Balance at December 31, 2001	$	(196	)
Effective portion of changes in fair value		(103	)
Reclasses from AOCI to net income		(439	)
Balance at December 31, 2002		(738	)
Effective portion of changes in fair value		256
Reclasses from AOCI to net income		379
Balance at December 31, 2003		(103	)
Effective portion of changes in fair value		2,830
Reclasses from AOCI to net income		(1,486	)
Ending Balance, December 31, 2004	$	1,241
PSO
Beginning Balance at December 31, 2001	$	-
Effective portion of changes in fair value		2
Reclasses from AOCI to net income		(44	)
Balance at December 31, 2002		(42	)
Effective portion of changes in fair value		18
Reclasses from AOCI to net income		180
Balance at December 31, 2003		156
Effective portion of changes in fair value		713
Reclasses from AOCI to net income		(469	)
Ending Balance, December 31, 2004	$	400
SWEPCo
Beginning Balance at December 31, 2001	$	-
Effective portion of changes in fair value		1
Reclasses from AOCI to net income		(49	)
Balance at December 31, 2002		(48	)
Effective portion of changes in fair value		21
Reclasses from AOCI to net income		211
Balance at December 31, 2003		184
Effective portion of changes in fair value		(450	)
Reclasses from AOCI to net income		(554	)
Ending Balance, December 31, 2004	$	(820	)
TCC
Beginning Balance at December 31, 2001	$	-
Effective portion of changes in fair value		30
Reclasses from AOCI to net income		(66	)
Balance at December 31, 2002		(36	)
Effective portion of changes in fair value		(1,931	)
Reclasses from AOCI to net income		139
Balance at December 31, 2003		(1,828	)
Effective portion of changes in fair value		866
Reclasses from AOCI to net income		1,619
Ending Balance, December 31, 2004	$	657
TNC
Beginning Balance at December 31, 2001	$	-
Effective portion of changes in fair value		3
Reclasses from AOCI to net income		(18	)
Balance at December 31, 2002		(15	)
Effective portion of changes in fair value		(641	)
Reclasses from AOCI to net income		55
Balance at December 31, 2003		(601	)
Effective portion of changes in fair value		373
Reclasses from AOCI to net income		513
Ending Balance, December 31, 2004	$	285

The following table approximates net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) at December 31, 2004 that are expected to be reclassified to net income in the next twelve months as the items being hedged settle. The actual amounts reclassified from AOCI to Net Income can differ as a result of market price changes. The maximum term for which the exposure to the variability of future cash flows is being hedged is fourteen months.

	(in thousands)
APCo	$	1,876
CSPCo		1,750
I&M		1,386
KPCo		800
OPCo		2,083
PSO		1,182
SWEPCo		1,413
TCC		825
TNC		357

FINANCIAL INSTRUMENTS

The fair values of Long-term Debt and preferred stock subject to mandatory redemption are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

The book values and fair values of significant financial instruments for Registrant Subsidiaries at December 31, 2004 and 2003 are summarized in the following tables.

	2004				2003
	Book Value		Fair Value		Book Value		Fair Value
	(in thousands)
AEGCo
Long-term Debt	$	44,820	$	46,249	$	44,811	$	47,882
APCo
Long-term Debt		1,784,598		1,822,687		1,864,081		1,926,518
Cumulative Preferred Stock Subject to Mandatory Redemption		-		-		5,360		5,287
CSPCo
Long-term Debt		987,626		1,040,885		897,564		938,595
I&M
Long-term Debt		1,312,843		1,349,614		1,339,359		1,400,937
Cumulative Preferred Stock Subject to Mandatory Redemption		61,445		61,637		63,445		63,293
KPCo
Long-term Debt		508,310		521,776		487,602		503,704
OPCo
Long-term Debt		2,011,060		2,092,645		2,039,940		2,117,131
Cumulative Preferred Stock Subject to Mandatory Redemption		5,000		5,016		7,250		7,214
PSO
Long-term Debt		546,092		557,630		574,298		589,956
SWEPCo
Long-term Debt		805,369		833,246		884,308		917,982
TCC
Long-term Debt		1,907,294		2,013,546		2,291,625		2,393,468
TNC
Long-term Debt		314,357		329,514		356,754		374,420

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value

The trust investments are classified as available for sale for decommissioning (I&M, TCC) and SNF disposal for I&M. I&M reports trusts in “Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds” on its Consolidated Balance Sheets. TCC reports trusts in “Assets Held for Sale - Texas Generating Plants” on its Consolidated Balance Sheets. The following table provides fair values, cost basis and net unrealized gains or losses at December 31:

	I&M				TCC
	2004		2003		2004		2003
	(in thousands)
Fair Value	$	1,053,400	$	982,400	$	143,200	$	124,700
Cost Basis		936,500		900,000		107,000		94,800

	I&M							TCC
	2004		2003		2002			2004		2003		2002
	(in thousands)
Net Unrealized Holding Gain (Loss)	$	34,500	$	35,500	$	(25,400	)	$	6,400	$	16,700	$	(7,500	)

14.INCOME TAXES

The details of the Registrant Subsidiaries’ income taxes before extraordinary loss and cumulative effect of accounting changes as reported are as follows:

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2004
Charged (Credited) to Operating Expenses (net):
Current	$	5,729		$	34,721		$	54,287		$	79,645		$	(4,697	)
Deferred		(2,187	)		55,347			17,945			(1,784	)		14,925
Deferred Investment Tax Expense (Credits)		-			1,010			(2,864	)		(7,476	)		(1,233	)
Total		3,542			91,078			69,368			70,385			8,995
Charged (Credited) to Nonoperating Income (net):
Current		(287	)		2,968			2,853			4,994			1,827
Deferred		(32	)		(7,762	)		(4,550	)		(3,764	)		(2,151	)
Deferred Investment Tax Credits		(3,339	)		(1,173	)		-			-			-
Total		(3,658	)		(5,967	)		(1,697	)		1,230			(324	)
Total Income Tax as Reported	$	(116	)	$	85,111		$	67,671		$	71,615		$	8,671

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2004
Charged (Credited) to Operating Expenses (net):
Current	$	69,576		$	(12,315	)	$	26,618		$	117,667		$	16,693
Deferred		30,080			23,226			14,166			(86,034	)		5,272
Deferred Investment Tax Credits		(2,498	)		(1,791	)		(4,326	)		(4,736	)		(1,292	)
Total		97,158			9,120			36,458			26,897			20,673
Charged (Credited) to Nonoperating Income (net):
Current		6,307			(119	)		(347	)		5,637			2,872
Deferred		(6,751	)		(1,192	)		(1,384	)		102,524			(1,036	)
Deferred Investment Tax Credits		(604	)		-			-			-			-
Total		(1,048	)		(1,311	)		(1,731	)		108,161			1,836
Total Income Tax as Reported	$	96,110		$	7,809		$	34,727		$	135,058		$	22,509

			AEGCo			APCo			CSPCo			I&M			KPCo
			(in thousands)
Year Ended December 31, 2003
Charged (Credited) to Operating Expenses (net):
		Current	$	7,481		$	84,449		$	83,469		$	58,190		$	(7,840	)
		Deferred		(5,838	)		37,024			3,982			66			21,183
		Deferred Investment Tax Credits		-			(1,884	)		(3,041	)		(7,330	)		(1,168	)
		Total		1,643			119,589			84,410			50,926			12,175
Charged (Credited) to Nonoperating Income (net):
	Current			(196	)		(646	)		(2,183	)		5,283			(1,382	)
	Deferred			-			(12,461	)		(8,496	)		(14,960	)		(1,076	)
	Deferred Investment Tax Credits			(3,354	)		(1,262	)		(69	)		(101	)		(42	)
	Total			(3,550	)		(14,369	)		(10,748	)		(9,778	)		(2,500	)
Total Income Tax as Reported			$	(1,907	)	$	105,220		$	73,662		$	41,148		$	9,675

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2003
Charged (Credited) to Operating Expenses (net):
Current	$	116,316		$	55,834		$	51,564		$	88,530		$	33,822
Deferred		32,191			(17,036	)		7,230			14,769			(5,113	)
Deferred Investment Tax Credits		(2,493	)		(1,790	)		(4,326	)		(5,207	)		(1,520	)
Total		146,014			37,008			54,468			98,092			27,189
Charged (Credited) to Nonoperating Income (net):
Current		708			(1,566	)		(6,108	)		2,456			1,454
Deferred		(7,709	)		2,395			2,712			4,624			1,620
Deferred Investment Tax Credits		(614	)		-			-			-			-
Total		(7,615	)		829			(3,396	)		7,080			3,074
Total Income Tax as Reported	$	138,399		$	37,837		$	51,072		$	105,172		$	30,263

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2002
Charged (Credited) to Operating Expenses (net):
Current	$	6,607		$	99,140		$	81,538		$	66,063		$	680
Deferred		(5,028	)		17,626			25,771			(19,870	)		9,451
Deferred Investment Tax Expense (Credits)		2			(3,229	)		(3,095	)		(7,340	)		(1,173	)
Total		1,581			113,537			104,214			38,853			8,958
Charged (Credited) to Nonoperating Income (net):
Current		(173	)		(354	)		9,442			3,435			1,583
Deferred		-			(849	)		(2,479	)		2,949			388
Deferred Investment Tax Credits		(3,363	)		(1,408	)		(174	)		(400	)		(67	)
Total		(3,536	)		(2,611	)		6,789			5,984			1,904
Total Income Tax as Reported	$	(1,955	)	$	110,926		$	111,003		$	44,837		$	10,862

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2002
Charged (Credited) to Operating Expenses (net):
Current	$	86,026		$	(49,673	)	$	41,354		$	30,494		$	109
Deferred		30,048			75,659			(3,134	)		113,726			(10,652	)
Deferred Investment Tax Credits		(2,493	)		(1,791	)		(4,524	)		(5,206	)		(1,271	)
Total		113,581			24,195			33,696			139,014			(11,814	)
Charged (Credited) to Nonoperating Income (net):
Current		2,732			(1,812	)		1,772			3,223			1,334
Deferred		15,962			-			-			(71	)		(1,623	)
Deferred Investment Tax Credits		(684	)		-			-			-			-
Total		18,010			(1,812	)		1,772			3,152			(289	)
Total Income Tax as Reported	$	131,591		$	22,383		$	35,468		$	142,166		$	(12,103	)

Shown below is a reconciliation for each Registrant Subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory rate and the amount of income taxes reported.

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2004
Net Income	$	7,842		$	153,115		$	140,258		$	133,222		$	25,905
Income Taxes		(116	)		85,111			67,671			71,615			8,671
Pretax Income	$	7,726		$	238,226		$	207,929		$	204,837		$	34,576
Income Tax on Pretax Income at Statutory Rate (35%)	$	2,704		$	83,379		$	72,775		$	71,693		$	12,102
Increase (Decrease) in Income Tax   resulting from the following items:
Depreciation		808			10,719			2,570			19,023			1,466
Nuclear Fuel Disposal Costs		-			-			-			(3,338	)		-
Allowance for Funds Used During Construction		(1,060	)		(3,948	)		(515	)		(3,160	)		(603	)
Rockport Plant Unit 2 Investment Tax Credit		374			-			-			397			-
Removal Costs		-			(1,632	)		(336	)		(2,974	)		(1,497	)
Investment Tax Credits (net)		(3,339	)		(163	)		(2,864	)		(7,476	)		(1,233	)
State and Local Income Taxes		933			6,629			159			7,102			(197	)
Other		(536	)		(9,873	)		(4,118	)		(9,652	)		(1,367	)
Total Income Taxes as Reported	$	(116	)	$	85,111		$	67,671		$	71,615		$	8,671
Effective Income Tax Rate		N.M.			35.7	%		32.5	%		35.0	%		25.1	%

N.M. = Not Meaningful

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2004
Net Income	$	210,116		$	37,542		$	89,457		$	174,122		$	47,659
Extraordinary Loss		-			-			-			120,534			-
Income Taxes		96,110			7,809			34,727			135,058			22,509
Pretax Income	$	306,226		$	45,351		$	124,184		$	429,714		$	70,168
Income Tax on Pretax Income at Statutory Rate (35%)	$	107,179		$	15,873		$	43,464		$	150,400		$	24,559
Increase (Decrease) in Income Tax   resulting from the following items:
Depreciation		4,977			(937	)		(1,622	)		(812	)		(739	)
Investment Tax Credits (net)		(3,102	)		(1,791	)		(4,326	)		(4,736	)		(1,292	)
State and Local Income Taxes		305			1,882			4,736			543			2,762
Other		(13,249	)		(7,218	)		(7,525	)		(10,337	)		(2,781	)
Total Income Taxes as Reported	$	96,110		$	7,809		$	34,727		$	135,058		$	22,509
Effective Income Tax Rate		31.4	%		17.2	%		28.0	%		31.4	%		32.1	%

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2003
Net Income	$	7,964		$	280,040		$	200,430		$	86,388		$	32,330
Cumulative Effect of Accounting Changes		-			(77,257	)		(27,283	)		3,160			1,134
Income Taxes		(1,907	)		105,220			73,662			41,148			9,675
Pretax Income	$	6,057		$	308,003		$	246,809		$	130,696		$	43,139
Income Tax on Pretax Income at Statutory Rate (35%)	$	2,120		$	107,801		$	86,383		$	45,744		$	15,099
Increase (Decrease) in Income Tax   resulting from the following items:
Depreciation		371			9,209			2,220			17,735			1,538
Nuclear Fuel Disposal Costs		-			-			-			(6,465	)		-
Allowance for Funds Used During Construction		(1,053	)		(2,048	)		(232	)		(4,127	)		(851	)
Rockport Plant Unit 2 Investment Tax Credit		374			-			-			397			-
Removal Costs		-			(2,280	)		(7	)		(693	)		(735	)
Investment Tax Credits (net)		(3,354	)		(3,146	)		(3,110	)		(7,431	)		(1,210	)
State and Local Income Taxes		372			1,123			(3,074	)		4,634			(58	)
Other		(737	)		(5,439	)		(8,518	)		(8,646	)		(4,108	)
Total Income Taxes as Reported	$	(1,907	)	$	105,220		$	73,662		$	41,148		$	9,675
Effective Income Tax Rate		N.M.			34.2	%		29.8	%		31.5	%		22.4	%

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2003
Net Income	$	375,663		$	53,891		$	98,141		$	217,669		$	58,557
Cumulative Effect of Accounting Changes		(124,632	)		-			(8,517	)		(122	)		(3,071	)
Extraordinary Loss		-			-			-			-			177
Income Taxes		138,399			37,837			51,072			105,172			30,263
Pretax Income	$	389,430		$	91,728		$	140,696		$	322,719		$	85,926
Income Tax on Pretax Income at Statutory Rate (35%)	$	136,301		$	32,105		$	49,244		$	112,952		$	30,074
Increase (Decrease) in Income Tax   resulting from the following items:
Depreciation		4,096			(467	)		(390	)		(957	)		(214	)
Investment Tax Credits (net)		(3,107	)		(1,791	)		(4,326	)		(5,207	)		(1,521	)
State and Local Income Taxes		4,717			2,886			9,723			(10,434	)		3,078
Other		(3,608	)		5,104			(3,179	)		8,818			(1,154	)
Total Income Taxes as Reported	$	138,399		$	37,837		$	51,072		$	105,172		$	30,263
Effective Income Tax Rate		35.5	%		41.2	%		36.3	%		32.6	%		35.2	%

N.M. = Not Meaningful

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2002
Net Income	$	7,552		$	205,492		$	181,173		$	73,992		$	20,567
Income Taxes		(1,955	)		110,926			111,003			44,837			10,862
Pretax Income	$	5,597		$	316,418		$	292,176		$	118,829		$	31,429
Income Tax on Pretax Income at Statutory Rate (35%)	$	1,959		$	110,746		$	102,262		$	41,590		$	11,000
Increase (Decrease) in Income Tax resulting from the  following items:
Depreciation		286			3,082			2,899			21,812			2,057
Nuclear Fuel Disposal Costs		-			-			-			(3,087	)		-
Allowance for Funds Used During Construction		(1,136	)		-			-			(3,453	)		-
Rockport Plant Unit 2 Investment Tax Credit		374			-			-			-			-
Removal Costs		-			-			-			-			(735	)
Investment Tax Credits (net)		(3,361	)		(4,637	)		(3,270	)		(7,740	)		(1,240	)
State and Local Income Taxes		335			6,469			11,387			124			1,058
Other		(412	)		(4,734	)		(2,275	)		(4,409	)		(1,278	)
Total Income Taxes as Reported	$	(1,955	)	$	110,926		$	111,003		$	44,837		$	10,862
Effective Income Tax Rate		N.M.			35.1	%		38.0	%		37.7	%		34.6	%

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2002
Net Income	$	220,023		$	41,060		$	82,992		$	275,941		$	(13,677	)
Income Taxes		131,591			22,383			35,468			142,166			(12,103	)
Pretax Income	$	351,614		$	63,443		$	118,460		$	418,107		$	(25,780	)
Income Tax on Pretax Income at Statutory Rate (35%)	$	123,065		$	22,205		$	41,461		$	146,337		$	(9,023	)
Increase (Decrease) in Income Tax   resulting from the following items:
Depreciation		4,227			(583	)		(2,790	)		(295	)		(32	)
Investment Tax Credits (net)		(3,177	)		(1,791	)		(4,524	)		(5,207	)		(1,271	)
State and Local Income Taxes		18,051			2,639			3,987			2,202			(1,577	)
Other		(10,575	)		(87	)		(2,666	)		(871	)		(200	)
Total Income Taxes as Reported	$	131,591		$	22,383		$	35,468		$	142,166		$	(12,103	)
Effective Income Tax Rate		37.4	%		35.3	%		29.9	%		34.0	%		46.9	%

N.M. = Not Meaningful

The following tables show the elements of the net deferred tax liability and the significant temporary differences for each Registrant Subsidiary:

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2004
Deferred Tax Assets	$	65,740		$	238,784		$	98,848		$	650,596		$	39,511
Deferred Tax Liabilities		(90,502	)		(1,091,320	)		(563,393	)		(966,326	)		(267,047	)
Net Deferred Tax Liabilities	$	(24,762	)	$	(852,536	)	$	(464,545	)	$	(315,730	)	$	(227,536	)
Property Related Temporary Differences	$	(58,895	)	$	(680,324	)	$	(385,426	)	$	(71,771	)	$	(169,452	)
Amounts Due From Customers For   Future Federal Income Taxes		6,266			(94,438	)		(5,652	)		(34,260	)		(25,112	)
Deferred State Income Taxes		(5,050	)		(106,817	)		(25,658	)		(48,830	)		(32,099	)
Transition Regulatory Assets		-			(8,914	)		(54,852	)		-			-
Deferred Income Taxes on Other Comprehensive Loss		-			43,978			32,747			24,366			4,725
Net Deferred Gain on Sale and Leaseback-   Rockport Plant Unit 2		33,967			-			-			22,600			-
Accrued Nuclear Decommissioning Expense		-			-			-			(188,428	)		-
Deferred Fuel and Purchased Power		-			20,245			(39	)		(19	)		-
Accrued Pensions		-			(8,306	)		(12,528	)		6,135			(768	)
Provision for Refund		-			809			-			(73	)		-
Nuclear Fuel		-			-			-			(15,485	)		-
All Other (Net)		(1,050	)		(18,769	)		(13,137	)		(9,965	)		(4,830	)
Net Deferred Tax Liabilities	$	(24,762	)	$	(852,536	)	$	(464,545	)	$	(315,730	)	$	(227,536	)

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2004
Deferred Tax Assets	$	165,891		$	76,411		$	70,039		$	248,456		$	33,063
Deferred Tax Liabilities		(1,109,356	)		(460,501	)		(469,795	)		(1,495,567	)		(171,528	)
Net Deferred Tax Liabilities	$	(943,465	)	$	(384,090	)	$	(399,756	)	$	(1,247,111	)	$	(138,465	)
Property Related Temporary Differences	$	(781,479	)	$	(331,428	)	$	(341,306	)	$	(390,709	)	$	(132,383	)
Amounts Due From Customers For   Future Federal Income Taxes		(55,121	)		7,687			5,927			7,513			4,552
Deferred State Income Taxes		(78,060	)		(59,598	)		(44,074	)		(42,693	)		(7,705	)
Transition Regulatory Assets		(79,480	)		-			(153	)		(68,076	)		-
Accrued Nuclear Decommissioning Expense		-			-			-			(1,853	)		-
Deferred Income Taxes on Other Comprehensive Loss		39,989			(40	)		635			188			69
Deferred Fuel and Purchased Power		-			(126	)		(10,274	)		(1,738	)		(8,554	)
Accrued Pensions		(7,963	)		(30,463	)		(26,219	)		(38,836	)		(16,432	)
Provision for Refund		-			67			1,915			51,838			11,513
Deferred Book Gain		-			-			-			71,749			-
Regulatory Assets		-			-			(581	)		(580,736	)		2,886
Securitized Transition Assets		-			-			-			(257,612	)		-
All Other (Net)		18,649			29,811			14,374			3,854			7,589
Net Deferred Tax Liabilities	$	(943,465	)	$	(384,090	)	$	(399,756	)	$	(1,247,111	)	$	(138,465	)

	AEGCo			APCo			CSPCo			I&M			KPCo
	(in thousands)
Year Ended December 31, 2003
Deferred Tax Assets	$	79,545		$	237,873		$	122,453		$	695,037		$	44,413
Deferred Tax Liabilities		(103,874	)		(1,041,228	)		(580,951	)		(1,032,413	)		(256,534	)
Net Deferred Tax Liabilities	$	(24,329	)	$	(803,355	)	$	(458,498	)	$	(337,376	)	$	(212,121	)
Property Related Temporary Differences	$	(62,271	)	$	(623,126	)	$	(357,980	)	$	(74,501	)	$	(151,404	)
Amounts Due From Customers For Future   Federal Income Taxes		6,949			(94,457	)		(5,575	)		(37,233	)		(23,203	)
Deferred State Income Taxes		(4,350	)		(87,484	)		(26,972	)		(45,736	)		(33,535	)
Transition Regulatory Assets		-			(10,799	)		(66,002	)		-			-
Deferred Income Taxes on Other Comprehensive Loss		-			28,047			24,946			13,519			3,345
Net Deferred Gain on Sale and Leaseback-   Rockport Plant Unit 2		36,916			-			-			24,563			-
Accrued Nuclear Decommissioning Expense		-			-			-			(173,054	)		-
Deferred Fuel and Purchased Power		-			24,047			(273	)		(19	)		496
Deferred Cook Plant Restart Costs		-			-			-			(20,064	)		-
Accrued Pensions		-			(8,019	)		(13,000	)		(2,832	)		(1,006	)
Provision for Refund		-			809			-			(73	)		-
Nuclear Fuel		-			-			-			(7,027	)		-
All Other (Net)		(1,573	)		(32,373	)		(13,642	)		(14,919	)		(6,814	)
Net Deferred Tax Liabilities	$	(24,329	)	$	(803,355	)	$	(458,498	)	$	(337,376	)	$	(212,121	)

	OPCo			PSO			SWEPCo			TCC			TNC
	(in thousands)
Year Ended December 31, 2003
Deferred Tax Assets	$	192,026		$	164,801		$	163,457		$	298,648		$	67,794
Deferred Tax Liabilities		(1,125,608	)		(500,235	)		(512,521	)		(1,543,560	)		(180,813	)
Net Deferred Tax Liabilities	$	(933,582	)	$	(335,434	)	$	(349,064	)	$	(1,244,912	)	$	(113,019	)
Property Related Temporary Differences	$	(721,118	)	$	(297,809	)	$	(321,082	)	$	(698,554	)	$	(118,876	)
Amounts Due From Customers For Future   Federal Income Taxes		(55,143	)		8,728			8,259			8,330			5,402
Deferred State Income Taxes		(80,573	)		(56,413	)		(33,651	)		(42,044	)		(2,946	)
Transition Regulatory Assets		(109,150	)		-			-			(68,076	)		-
Accrued Nuclear Decommissioning Expense		-			-			-			(1,470	)		-
Nuclear Fuel		-			-			-			(7,240	)		-
Deferred Income Taxes on Other Comprehensive Loss		26,280			23,607			23,644			33,316			14,387
Deferred Fuel and Purchased Power		12			(8,460	)		(10,996	)		(1,738	)		(10,143	)
Accrued Pensions		(9,222	)		(16,088	)		(12,922	)		(20,054	)		(9,961	)
Provision for Refund		-			67			3,000			29,823			7,601
Regulatory Assets		-			-			-			(199,945	)		4,577
Securitized Transition Assets		-			-			-			(281,260	)		-
All Other (Net)		15,332			10,934			(5,316	)		4,000			(3,060	)
Net Deferred Tax Liabilities	$	(933,582	)	$	(335,434	)	$	(349,064	)	$	(1,244,912	)	$	(113,019	)

The IRS and other taxing authorities routinely examine the Registrant Subsidiaries tax returns. Management believes that the Registrant Subsidiaries have filed tax returns with positions that may be challenged by these tax authorities. Theses positions relate to the timing and amount of income, deductions and the computation of the tax liability. Registrant Subsidiaries have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. Registrant Subsidiaries have received Revenue Agent’s Reports from the IRS for the years 1991 through 1999, and have filed protests contesting certain proposed adjustments. CSW, which was a separate consolidated group prior to its merger with AEP, is currently being audited for the years 1997 through the date of the merger in June 2000. Returns for the years 2000 through 2003 are presently being audited by the IRS.

Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters.  As of December 31, 2004, Registrant Subsidiaries have total provisions for uncertain tax positions of approximately $23 million, excluding AEGCo.  In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

Registrant Subsidiaries join in the filing of a consolidated federal income tax return with the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

15.LEASES

Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to operating expenses in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:

	AEGCo		APCo		CSPCo		I&M		KPCo
Year Ended December 31, 2004	(in thousands)
Lease Payments on Operating Leases	$	75,545	$	6,832	$	5,313	$	111,344	$	1,416
Amortization of Capital Leases		92		7,906		3,933		6,825		1,605
Interest on Capital Leases		7		1,260		705		1,403		258
Total Lease Rental Costs	$	75,644	$	15,998	$	9,951	$	119,572	$	3,279

	OPCo		PSO		SWEPCo		TCC		TNC
Year Ended December 31, 2004	(in thousands)
Lease Payments on Operating Leases	$	14,390	$	3,697	$	4,877	$	3,949	$	1,458
Amortization of Capital Leases		8,232		520		3,543		437		216
Interest on Capital Leases		2,259		53		2,054		66		27
Total Lease Rental Costs	$	24,881	$	4,270	$	10,474	$	4,452	$	1,701

	AEGCo		APCo		CSPCo		I&M		KPCo
Year Ended December 31, 2003	(in thousands)
Lease Payments on Operating Leases	$	76,322	$	6,148	$	5,277	$	111,923	$	1,258
Amortization of Capital Leases		269		9,217		4,898		7,370		1,951
Interest on Capital Leases		-		1,123		899		1,276		148
Total Lease Rental Costs	$	76,591	$	16,488	$	11,074	$	120,569	$	3,357

	OPCo		PSO		SWEPCo		TCC		TNC
Year Ended December 31, 2003	(in thousands)
Lease Payments on Operating Leases	$	40,034	$	4,883	$	4,708	$	6,360	$	2,132
Amortization of Capital Leases		9,437		174		1,434		161		83
Interest on Capital Leases		2,472		17		899		16		9
Total Lease Rental Costs	$	51,943	$	5,074	$	7,041	$	6,537	$	2,224

	AEGCo		APCo		CSPCo		I&M		KPCo
Year Ended December 31, 2002	(in thousands)
Lease Payments on Operating Leases	$	76,143	$	6,634	$	5,209	$	112,037	$	1,597
Amortization of Capital Leases		238		9,729		6,010		8,319		2,171
Interest on Capital Leases		19		2,240		1,717		2,221		469
Total Lease Rental Costs	$	76,400	$	18,603	$	12,936	$	122,577	$	4,237

	OPCo		PSO		SWEPCo		TCC		TNC
Year Ended December 31, 2002	(in thousands)
Lease Payments on Operating Leases	$	80,210	$	4,403	$	3,240	$	7,184	$	1,981
Amortization of Capital Leases		12,637		-		-		-		-
Interest on Capital Leases		4,501		-		-		-		-
Total Lease Rental Costs	$	97,348	$	4,403	$	3,240	$	7,184	$	1,981

Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:

	AEGCo		APCo		CSPCo		I&M		KPCo
Year Ended December 31, 2004	(in thousands)
Property, Plant and Equipment   Under Capital Leases:
Production	$	12,339	$	1,759	$	7,104	$	22,917	$	797
Distribution		-		-		-		14,589		-
Other		353		45,892		21,270		43,478		10,405
Total Property, Plant and Equipment		12,692		47,651		28,374		80,984		11,202
Accumulated Amortization		218		27,709		15,884		30,252		6,839
Net Property, Plant and Equipment  Under Capital Leases	$	12,474	$	19,942	$	12,490	$	50,732	$	4,363
Obligations Under Capital Leases:
Noncurrent Liability	$	12,264	$	13,136	$	8,660	$	44,608	$	2,802
Liability Due Within One Year		210		6,742		3,854		6,124		1,561
Total Obligations Under Capital Leases	$	12,474	$	19,878	$	12,514	$	50,732	$	4,363

	OPCo		PSO		SWEPCo		TCC		TNC
Year Ended December 31, 2004	(in thousands)
Property, Plant and Equipment Under Capital Leases:
Production	$	34,796	$	-	$	14,269	$	-	$	-
Distribution		-		-		-		-		-
Other		46,131		1,813		53,620		1,364		780
Total Property, Plant and Equipment		80,927		1,813		67,889		1,364		780
Accumulated Amortization		41,187		529		33,343		484		246
Net Property, Plant and Equipment Under Capital Leases	$	39,740	$	1,284	$	34,546	$	880	$	534
Obligations Under Capital Leases:
Noncurrent Liability	$	31,652	$	747	$	30,854	$	468	$	314
Liability Due Within One Year		9,081		537		3,692		412		220
Total Obligations Under Capital Leases	$	40,733	$	1,284	$	34,546	$	880	$	534

	AEGCo		APCo		CSPCo		I&M		KPCo
Year Ended December 31, 2003	(in thousands)
Property, Plant and Equipment Under Capital Leases:
Production	$	865	$	2,758	$	7,104	$	4,492	$	1,138
Distribution		-		-		-		14,589		-
Other		-		55,640		25,345		52,536		11,562
Total Property, Plant and Equipment		865		58,398		32,449		71,617		12,700
Accumulated Amortization		596		33,036		16,828		33,774		7,408
Net Property, Plant and Equipment Under Capital Leases	$	269	$	25,362	$	15,621	$	37,843	$	5,292
Obligations Under Capital Leases:
Noncurrent Liability	$	182	$	16,134	$	11,397	$	31,315	$	3,549
Liability Due Within One Year		87		9,218		4,221		6,528		1,743
Total Obligations Under Capital Leases	$	269	$	25,352	$	15,618	$	37,843	$	5,292

	OPCo		PSO		SWEPCo		TCC		TNC
Year Ended December 31, 2003	(in thousands)
Property, Plant and Equipment  Under Capital Leases:
Production	$	21,099	$	-	$	-	$	-	$	-
Distribution		-		-		-		-		-
Other		53,752		1,176		52,695		1,204		556
Total Property, Plant and Equipment		74,851		1,176		52,695		1,204		556
Accumulated Amortization		40,565		166		31,153		160		83
Net Property, Plant and   Equipment Under Capital Leases	$	34,286	$	1,010	$	21,542	$	1,044	$	473
Obligations Under Capital Leases:
Noncurrent Liability	$	25,064	$	558	$	18,383	$	636	$	270
Liability Due Within One Year		9,624		452		3,159		407		203
Total Obligations Under   Capital Leases	$	34,688	$	1,010	$	21,542	$	1,043	$	473

Future minimum lease payments consisted of the following at December 31, 2004:

	AEGCo		APCo		CSPCo		I&M		KPCo
Capital Leases	(in thousands)
2005	$	990	$	7,988	$	4,468	$	8,367	$	1,854
2006		980		6,192		3,184		6,895		1,195
2007		972		3,512		2,178		4,733		962
2008		964		3,060		2,100		4,342		519
2009		962		1,053		1,131		6,734		184
Later Years		17,997		1,060		931		25,348		169
Total Future Minimum Lease Payments		22,865		22,865		13,992		56,419		4,883
Less Estimated Interest Element		10,391		2,987		1,478		5,687		520
Estimated Present Value of Future Minimum   Lease Payments	$	12,474	$	19,878	$	12,514	$	50,732	$	4,363

	OPCo		PSO		SWEPCo		TCC		TNC
Capital Leases	(in thousands)
2005	$	9,795	$	579	$	6,160	$	456	$	242
2006		9,295		413		6,057		300		140
2007		7,093		211		5,892		120		59
2008		5,061		99		5,832		71		44
2009		3,392		44		5,445		18		41
Later Years		20,332		33		20,513		-		59
Total Future Minimum Lease Payments		54,968		1,379		49,899		965		585
Less Estimated Interest Element		14,235		95		15,353		85		51
Estimated Present Value of Future Minimum   Lease Payments	$	40,733	$	1,284	$	34,546	$	880	$	534

	AEGCo		APCo		CSPCo		I&M		KPCo
Noncancelable Operating Leases	(in thousands)
2005	$	73,955	$	7,126	$	5,670	$	104,003	$	1,475
2006		73,938		6,126		3,212		98,883		1,150
2007		73,934		4,554		2,720		96,330		982
2008		73,933		3,624		2,089		95,529		741
2009		73,932		2,982		1,755		94,630		595
Later Years		960,341		6,354		3,188		1,019,602		1,792
Total Future Minimum Lease Payments	$	1,330,033	$	30,766	$	18,634	$	1,508,977	$	6,735

	OPCo		PSO		SWEPCo		TCC		TNC
Noncancelable Operating Leases	(in thousands)
2005	$	16,220	$	5,760	$	6,793	$	5,751	$	2,200
2006		15,005		4,877		6,786		4,117		1,860
2007		14,448		4,409		7,979		3,456		1,497
2008		13,893		2,334		8,917		2,694		1,315
2009		13,410		2,139		8,176		2,377		1,440
Later Years		71,888		6,777		10,614		6,276		3,053
Total Future Minimum Lease Payments	$	144,864	$	26,296	$	49,265	$	24,671	$	11,365

Gavin Scrubber Financing Arrangement

In 1994, OPCo entered into an agreement with JMG, an unrelated special purpose entity. JMG was formed to design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber and previously leased it to OPCo. Prior to July 1, 2003, the lease was accounted for as an operating lease.

On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon consolidation, OPCo recorded the assets and liabilities of JMG ($470 million). Since the debt obligations of JMG are now consolidated, the JMG lease is no longer accounted for as an operating lease. For 2002 and the first half of 2003, operating lease payments related to the Gavin Scrubber were recorded as operating lease expense by OPCo. After July 1, 2003, OPCo records the depreciation, interest and other operating expenses of JMG and eliminates JMG’s rental revenues against OPCo’s operating lease expenses. There was no cumulative effect of an accounting change recorded as a result of the requirement to consolidate JMG and there was no change in net income due to the consolidation of JMG. The debt obligations of JMG are now included in long-term debt as Notes Payable and Installment Purchase Contracts and are excluded from the above table of future minimum lease payments.

At any time during the obligation, OPCo has the option to purchase the Gavin Scrubber for the greater of its fair market value or adjusted acquisition cost (equal to the unamortized debt and equity of JMG) or sell the Gavin Scrubber on behalf of JMG. The initial 15-year term is noncancelable. At the end of the initial term, OPCo can renew the obligation, purchase the Gavin Scrubber (terms previously mentioned), or sell the Gavin Scrubber on behalf of JMG. In the case of a sale at less than the adjusted acquisition cost, OPCo is required to pay the difference to JMG.

Rockport Lease

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The future minimum lease payments for each respective company as of December 31, 2004 are $1.3 billion.

The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt.

16.FINANCING ACTIVITIES

Dividend Restrictions

Under PUHCA, Registrant Subsidiaries can only pay dividends out of retained or current earnings.

Trust Preferred Securities

SWEPCo has a wholly-owned business trust that issued trust preferred securities. Effective July 1, 2003, the trust was deconsolidated due to the implementation of FIN 46. The trust, which holds mandatorily redeemable trust preferred securities, is reported as two components on the Balance Sheet. The investment in the trust is reported as Other Investments within Other Property and Investments while the Junior Subordinated Debentures are reported as Notes Payable to Trust within Long-term Debt.

In October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are due October 1, 2043. Junior Subordinated Debentures were retired in the second quarter of 2004 for PSO and in the third quarter of 2004 for TCC. The following Trust Preferred Securities issued by the wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2004 and 2003:

Business Trust	Security		Units Issued/ Outstanding at 12/31/04	Amount in Other Investments at 12/31/04 (a)		Amount in Notes Payable to Trust at 12/31/04 (b)		Amount in Other Investments at 12/31/03 (a)		Amount in Notes Payable to Trust at 12/31/03 (b)		Description of Underlying Debentures of Registrant
		(in millions)
CPL Capital I	8.00%, Series A		-	$	-	$	-	$	5	$	141	TCC, $141 million,   8.00%, Series A
PSO Capital I	8.00%, Series A		-		-		-		2		77	PSO, $77 million,   8.00%, Series A
SWEPCo Capital I	5.25%, Series B		110,000		3		113		3		113	SWEPCo, $113   million, 5.25%    5-year fixed rate   period, Series B
Total			110,000	$	3	$	113	$	10	$	331

(a)	Amounts are in Other Investments within Other Property and Investments.
(b)	Amounts are in Notes Payable to Trust within Long-term Debt.

Each of the business trusts is treated as a nonconsolidated subsidiary of its parent company. The only assets of the business trusts are the subordinated debentures issued by their parent company as specified above. In addition to the obligations under the subordinated debentures, the parent company has also agreed to a security obligation which represents a full and unconditional guarantee of its capital trust obligation.

Lines of Credit - AEP System

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its 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, the AEP System also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The AEP System Corporate Borrowing Program operates in accordance with the terms and conditions outlined by the SEC. AEP has authority from the SEC through March 31, 2007 for short-term borrowings sufficient to fund the Utility Money Pool and the Nonutility Money Pool as well as its own requirements in an amount not to exceed $7.2 billion. The Utility Money Pool participants’ money pool activity and corresponding SEC authorized limits for the year ended December 31, 2004 are described in the following table:

Company	Maximum Borrowings from Utility Money Pool		Maximum Loans to Utility Money Pool		Average Borrowings from Utility Money Pool		Average Loans to Utility Money Pool		Loans (Borrowings) to/from Utility Money Pool as of December 31, 2004			SEC Authorized Short-Term Borrowing Limit
	(in thousands)
AEGCo	$	56,525	$	932	$	23,532	$	731	$	(26,915	)	$	125,000
APCo		211,060		32,575		76,100		13,501		(211,060	)		600,000
CSPCo		29,687		184,962		12,808		75,580		141,550			350,000
I&M		216,528		70,363		89,578		29,290		5,093			500,000
KPCo		44,749		41,501		13,580		15,282		16,127			200,000
OPCo		81,862		297,136		29,578		152,442		125,971			600,000
PSO		145,619		35,158		47,099		16,204		(55,002	)		300,000
SWEPCo		71,252		107,966		38,073		64,386		39,106			350,000
TCC		109,696		427,414		62,494		120,312		(207	)		600,000
TNC		16,136		110,430		6,704		41,500		51,504			250,000

Maximum, minimum and average interest rates for funds loaned to and borrowed from the Utility Money Pool during 2004 are summarized in the following table:

Company	Maximum Interest Rates for Funds Borrowed from the Utility Money Pool		Minimum Interest Rates for Funds Borrowed from the Utility Money Pool		Maximum Interest Rates for Funds Loaned to the Utility Money Pool		Minimum Interest Rates for Funds Loaned to the Utility Money Pool		Average Interest Rate for Funds Borrowed from the Utility Money Pool		Average Interest Rate for Funds Loaned to the Utility Money Pool
	(in percentages)
AEGCo		2.24		0.89		1.97		1.78		1.47		1.91
APCo		2.24		0.89		1.72		1.23		1.68		1.48
CSPCo		1.88		0.92		2.24		0.89		1.50		1.69
I&M		2.24		0.89		2.23		0.94		1.45		1.93
KPCo		1.92		0.91		2.24		0.89		1.59		1.61
OPCo		1.92		1.18		2.24		0.89		1.29		1.46
PSO		2.23		0.89		2.24		1.29		1.38		1.80
SWEPCo		1.92		0.89		2.24		0.91		1.37		1.67
TCC		2.23		0.91		2.24		0.89		1.40		1.47
TNC		1.50		0.91		2.24		0.89		1.09		1.56

As of December 31, 2004, AEP had credit facilities totaling $2.8 billion to support its commercial paper program. At December 31, 2004, AEP had $23 million in outstanding commercial paper related to JMG Funding. This commercial paper is specifically associated with the Gavin Scrubber as identified in the “Gavin Scrubber Financing Arrangement” section of Note 15. This commercial paper does not reduce AEP’s available liquidity. As of December 31, 2004, AEP’s commercial paper outstanding related to the corporate borrowing program was $0. For the corporate borrowing program, the maximum amount of commercial paper outstanding during the year was $661 million in June 2004 and the weighted average interest rate of commercial paper outstanding during the year was 1.81%. On February 10, 2003, Moody’s Investor Services downgraded AEP’s short-term rating for commercial paper to Prime-3 from Prime-2. On March 7, 2003, Standard & Poor’s Rating Services reaffirmed AEP’s A-2 short-term rating for commercial paper. On August 2, 2004, Moody’s Investor Services placed AEP’s ratings on positive outlook.

Interest expense related to the Utility Money Pool is included in Interest Charges in each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:

	Year Ended December 31,
	2004		2003		2002
	(in thousands)
AEGCo	$	338	$	289	$	345
APCo		1,136		147		4,396
CSPCo		32		732		1,771
I&M		1,127		313		196
KPCo		65		897		1,638
OPCo		51		2,332		5,685
PSO		486		1,218		4,114
SWEPCo		217		787		3,118
TCC		177		617		7,773
TNC		8		449		3,242

Interest income related to the Utility Money Pool is included in Nonoperating Income in each of the Registrant Subsidiaries’ Financial Statements. Interest income earned from amounts advanced to the Utility Money Pool by registrant were:

	Year Ended December 31,
	2004		2003		2002
	(in thousands)
AEGCo	$	1	$	8	$	126
APCo		24		1,589		366
CSPCo		1,076		777		683
I&M		84		1,814		1,260
KPCo		177		-		2
OPCo		1,965		700		-
PSO		76		156		-
SWEPCo		649		662		105
TCC		1,445		589		-
TNC		587		164		-

Outstanding short-term debt for AEP Consolidated consisted of:

		Year Ended December 31,
		2004		2003
		(in millions)
Balance Outstanding
	Notes Payable	$	-	$	18
	Commercial Paper - AEP		-		282
	Commercial Paper - JMG		23		26
Total		$	23	$	326

Sale of Receivables - AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. This transaction constitutes a sale of receivables in accordance with SFAS 140, allowing the receivables to be taken off of AEP Credit’s balance sheet and allowing AEP Credit to repay any debt obligations. AEP has no ownership interest in the commercial paper conduits and are not required to consolidate these entities in accordance with GAAP. We continue to service the receivables. This off-balance sheet transaction was entered into to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the AEP operating companies’ receivables, and accelerate its cash collections.

During 2004, AEP Credit renewed its sale of receivables agreement which had expired on August 25, 2004. As a result of the renewal, AEP Credit’s sale of receivables agreement will now expire on August 24, 2007. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2004, $435 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in all of its regulatory jurisdictions, only a portion of APCo’s accounts receivable are sold to AEP Credit.

Comparative accounts receivable information for AEP Credit:

	Year Ended December 31,
	2004			2003
	(in millions)
Proceeds from Sale of Accounts Receivable	$	5,163		$	5,221
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts		80			124
Deferred Revenue from Servicing Accounts Receivable		1			1
Loss on Sale of Accounts Receivables		7			7
Average Variable Discount Rate		1.50	%		1.33	%
Retained Interest if 10% Adverse Change in Uncollectible Accounts		78			122
Retained Interest if 20% Adverse Change in Uncollectible Accounts		76			121

Historical loss and delinquency amount for the AEP System’s customer accounts receivable managed portfolio:

	Face Value Year Ended December 31,
	2004			2003
	(in millions)
Customer Accounts Receivable Retained	$	930		$	1,155
Accrued Unbilled Revenues Retained		592			596
Miscellaneous Accounts Receivable Retained		79			83
Allowance for Uncollectible Accounts Retained		(77	)		(124	)
Total Net Balance Sheet Accounts Receivable		1,524			1,710
Customer Accounts Receivable Securitized (Affiliate)		435			385
Total Accounts Receivable Managed	$	1,959		$	2,095
Net Uncollectible Accounts Written Off	$	86		$	39

Customer accounts receivable retained and securitized for the domestic electric operating companies are managed by AEP Credit. Miscellaneous accounts receivable have been fully retained and not securitized.

Delinquent customer accounts receivable for the electric utility affiliates that AEP Credit currently factors were $25 million and $30 million at December 31, 2004 and 2003, respectively.

Under the factoring arrangement, participating Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company’s receivables and administrative costs. The costs of factoring customer accounts receivable are reported as an operating expense. The amount of factored accounts receivable and accrued unbilled revenues for each Registrant Subsidiary was as follows:

	December 31,
	2004		2003
	(in millions)
APCo	$	58.7	$	60.2
CSPCo		110.1		100.2
I&M		91.4		93.0
KPCo		34.4		30.4
OPCo		106.0		99.3
PSO		96.7		99.6
SWEPCo		72.0		64.4

The fees paid by the Registrant Subsidiaries to AEP Credit for factoring customer accounts receivable were:
 

	Year Ended December 31,
	2004		2003		2002
	(in millions)
APCo	$	3.9	$	3.4	$	4.8
CSPCo		10.2		9.8		15.8
I&M		6.5		6.1		7.4
KPCo		2.6		2.4		2.7
OPCo		7.7		8.7		11.4
PSO		8.9		5.8		7.2
SWEPCo		5.8		4.9		5.4
TCC		-		-		2.2
TNC		-		-		1.4

17.RELATED PARTY TRANSACTIONS

For other related party transactions, also see in Note 16 “Lines of Credit - AEP System” and “Sale of Receivables-AEP Credit.”

AEP System Power Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended (the Interconnection Agreement), defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s “member-load-ratio,” which is calculated monthly on the basis of each company’s maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO₂ allowances associated with the transactions under the Interconnection Agreement.

Power and Gas and risk management activities are conducted by the AEP Power Pool and profits/losses are shared among the parties under the System Integration Agreement. Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices. In addition the risk management of electricity, and to a lesser extent gas contracts including exchange traded futures and options and over-the-counter options and swaps. The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts. In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.

CSW Operating Agreement

PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which has been approved by the FERC. The CSW Operating Agreement requires the AEP West companies to maintain adequate annual planning reserve margins and requires the operating companies that have capacity in excess of the required margins to make such capacity available for sale to other operating companies as capacity commitments. Parties are compensated for energy delivered to recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales are shared based on the amount of energy each AEP West company contributes that is sold to third parties. Upon sale of its generation assets, TCC will no longer supply generating capacity under the CSW Operating Agreement.

AEP’s System Integration Agreement, which has been approved by the FERC, provides for the integration and coordination of AEP’s East and West companies zone. This includes joint dispatch of generation within the AEP System, and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). It is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within each zone.

Power generated by or allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers (or in the case of the ERCOT area of Texas, REPs) by such Registrant Subsidiary at rates approved (other than in Ohio, Virginia and the ERCOT area of Texas) by the public utility commission in the jurisdiction of sale. In Ohio, Virginia and the ERCOT area of Texas, such rates are based on a statutory formula as those jurisdictions transition to the use of market rates for generation (see Note 6).

Under both the Interconnection Agreement and CSW Operating Agreement, power generated that is not needed to serve the native load of any Registrant Subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary. See Note 13 for a discussion of the marketing of such power.

AEP East and West Companies Sales and Purchases to the Pools

The following table shows the revenues derived from sales to the pools and direct sales to affiliates for years ended December 31, 2004, 2003 and 2002:

	APCo		CSPCo		I&M		KPCo		OPCo		AEGCo
Related Party Revenues	(in thousands)
2004
Sales to East System Pool	$	128,736	$	60,409	$	243,105	$	36,032	$	497,925	$	-
Direct Sales to East Affiliates		62,018		-		-		-		57,241		241,578
Direct Sales to West Affiliates		22,017		13,190		14,536		5,155		17,721		-
Other		3,792		6,516		3,533		403		8,628		-
Total Revenues	$	216,563	$	80,115	$	261,174	$	41,590	$	581,515	$	241,578

	APCo		CSPCo		I&M		KPCo		OPCo		AEGCo
Related Party Revenues	(in thousands)
2003
Sales to East System Pool	$	130,921	$	59,113	$	228,667	$	32,827	$	503,334	$	-
Sales to West System Pool		27		9		17		6		21		-
Direct Sales to East Affiliates		60,638		-		-		-		50,764		232,955
Direct Sales to West Affiliates		27,951		16,428		17,674		6,425		21,759		-
Other		3,256		8,819		2,845		550		8,400		-
Total Revenues	$	222,793	$	84,369	$	249,203	$	39,808	$	584,278	$	232,955

	APCo		CSPCo		I&M		KPCo		OPCo		AEGCo
Related Party Revenues	(in thousands)
2002
Sales to East System Pool	$	106,651	$	42,986	$	197,525	$	22,369	$	397,248	$	-
Sales to West System Pool		18,300		12,107		13,036		4,717		16,265		-
Direct Sales to East Affiliates		58,213		-		-		-		50,599		213,071
Direct Sales to West Affiliates		-		-		-		-		-		-
Other		3,313		2,109		3,577		878		1,090		-
Total Revenues	$	186,477	$	57,202	$	214,138	$	27,964	$	465,202	$	213,071

	PSO		SWEPCo		TCC		TNC
Related Party Revenues	(in thousands)
2004
Sales to West System Pool	$	103	$	521	$	-	$	159
Direct Sales to East Affiliates		2,652		1,878		188		78
Direct Sales to West Affiliates		3,203		63,141		3,027		71
Other		4,732		5,650		43,824		51,372
Total Revenues	$	10,690	$	71,190	$	47,039	$	51,680

	PSO		SWEPCo		TCC		TNC
Related Party Revenues	(in thousands)
2003
Sales to West System Pool	$	793	$	600	$	15,157	$	651
Direct Sales to East Affiliates		1,159		706		677		6
Direct Sales to West Affiliates		17,855		64,802		23,248		1,929
Other		3,323		2,746		114,486		52,567
Total Revenues	$	23,130	$	68,854	$	153,568	$	55,153

	PSO		SWEPCo			TCC		TNC
Related Party Revenues	(in thousands)
2002
Sales to West System Pool	$	674	$	1,334		$	18,416	$	1,280
Direct Sales to East Affiliates		611		270			366		(23	)
Direct Sales to West Affiliates		6,047		75,674			956,751		228,404
Other		2,107		(4,949	)		32,911		10,764
Total Revenues	$	9,439	$	72,329		$	1,008,444	$	240,425

The following table shows the purchased power expense incurred from purchases from the pools and affiliates for the years ended December 31, 2004, 2003, and 2002:

	APCo		CSPCo		I&M		KPCo		OPCo
Related Party Purchases	(in thousands)
2004
Purchases from East System Pool	$	370,038	$	346,463	$	102,760	$	68,072	$	84,042
Direct Purchases from East Affiliates		-		-		169,103		72,475		4,334
Direct Purchases from West Affiliates		915		539		589		211		979
Total Purchases	$	370,953	$	347,002	$	272,452	$	140,758	$	89,355

	APCo		CSPCo		I&M		KPCo		OPCo
Related Party Purchases	(in thousands)
2003
Purchases from East System Pool	$	348,899	$	335,916	$	109,826	$	71,259	$	88,962
Direct Purchases from East Affiliates		1,546		936		164,069		70,249		1,234
Direct Purchases from West Affiliates		765		471		505		182		625
Total Purchases	$	351,210	$	337,323	$	274,400	$	141,690	$	90,821

	APCo		CSPCo		I&M		KPCo		OPCo
Related Party Purchases	(in thousands)
2002
Purchases from East System Pool	$	233,677	$	309,999	$	83,918	$	68,846	$	70,338
Purchases from West System Pool		337		219		237		86		297
Direct Purchases from East Affiliates		583		387		149,569		64,070		519
Total Purchases	$	234,597	$	310,605	$	233,724	$	133,002	$	71,154

	PSO		SWEPCo		TCC		TNC
Related Party Purchases	(in thousands)
2004
Purchases from East System Pool	$	66	$	177	$	-	$	-
Purchases from West System Pool		49		191		-		568
Direct Purchases from East Affiliates		45,689		24,988		1,984		1,278
Direct Purchases from West Affiliates		58,197		3,698		4,156		3,365
Total Purchases	$	104,001	$	29,054	$	6,140	$	5,211

	PSO		SWEPCo		TCC		TNC
Related Party Purchases	(in thousands)
2003
Purchases from East System Pool	$	639	$	-	$	-	$	-
Purchases from West System Pool		704		741		289		15,467
Direct Purchases from East Affiliates		46,384		28,376		10,238		4,677
Direct Purchases from West Affiliates		61,912		18,087		8,570		19,265
Other		-		710		-		-
Total Purchases	$	109,639	$	47,914	$	19,097	$	39,409

	PSO		SWEPCo			TCC		TNC
Related Party Purchases	(in thousands)
2002
Purchases from East System Pool	$	343	$	-		$	-	$	-
Purchases from West System Pool		874		(456	)		1,366		15,475
Direct Purchases from East Affiliates		29,029		17,242			8,236		2,669
Direct Purchases from West Affiliates		59,208		25,236			13,804		19,438
Total Purchases	$	89,454	$	42,022		$	23,406	$	37,582

The above summarized related party revenues and expenses are reported as consolidated and are presented as Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the statements of operations of each AEP Power Pool member. Since all of the above pool members are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.

AEP System Transmission Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated April 1, 1984, as amended (the Transmission Agreement), defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kV and above) and certain facilities operated at lower voltages (138 kV and above). Like the Interconnection Agreement, this sharing is based upon each company’s “member-load-ratio.”

The following table shows the net charges (credits) allocated among the parties to the Transmission Agreement during the years ended December 31, 2004, 2003 and 2002:

	2004			2003			2002
	(in thousands)
APCo	$	(500	)	$	-		$	(13,400	)
CSPCo		37,700			38,200			42,200
I&M		(40,800	)		(39,800	)		(36,100	)
KPCo		(6,100	)		(5,600	)		(5,400	)
OPCo		9,700			7,200			12,700

PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Transmission Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with the responsibility of overseeing the coordinated planning of the transmission facilities of the AEP West companies, including the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such tariff.

Under the TCA, the AEP West companies have delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The TCA also provides for the allocation among the AEP West companies of revenues collected for transmission and ancillary services provided under the OATT.

The following table shows the net charges (credits) allocated among parties to the TCA during the years ended December 31, 2004, 2003 and 2002:

	2004			2003			2002
	(in thousands)
PSO	$	8,100		$	4,200		$	4,200
SWEPCo		13,800			5,000			5,000
TCC		(12,200	)		(3,600	)		(3,600	)
TNC		(9,700	)		(5,600	)		(5,600	)

AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP’s East and West companies zones. Like the System Integration Agreement, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the AEP Transmission Agreement and the Transmission Coordination Agreement. The System Transmission Integration Agreement contains two service schedules that govern:

· The allocation of transmission costs and revenues and

· The allocation of third-party transmission costs and revenues and AEP System dispatch costs.

The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

CSPCo coal purchases from AEP Coal, Inc.

As a result of management’s decision to exit our non-core businesses, AEP Coal, Inc. (AEP Coal) was sold in March 2004. During 2004, AEP Coal sold approximately 330,000 tons of coal mined by AEP Coal to CSPCo to be delivered (at CSPCo’s expense) to the Conesville Plant for a price of $26.15 per ton. In 2003, AEP Coal and CSPCo were parties to a 2003 coal purchase agreement, dated October 15, 2002. The agreement provided for the sale of up to 960,000 tons of coal mined by AEP Coal to be delivered (at CSPCo’s expense) to the Conesville Plant for a price ranging from $23.15 per ton to $26.15 per ton plus quality adjustments. In 2002, AEP Coal and CSPCo were parties to a 2002 coal purchase agreement, dated February 1, 2002. The agreement provided for the sale of up to 785,000 tons of coal mined by AEP Coal to be delivered (at CSPCo’s expense) to the Conesville Plant for a price ranging from $24.00 per ton to $27.00 per ton plus quality adjustments. During 2004, 2003 and 2002, AEP Coal derived revenues from sales to CSPCo of $9.5 million, $23.9 million and $21 million, respectively.

AEP Coal and CSPCo were parties to a 1998 coal transloading agreement, dated June 12, 1998. Pursuant to the agreement, AEP Coal transferred coal from railcars into trucks at AEP Coal’s Muskie Transloading Facility and delivered the coal via trucks to CSPCo’s Conesville Preparation Plant or CSPCo’s Power Plant for a rate of $1.25 per ton, $1.25 per ton and $1.03 per ton, in 2004, 2003 and 2002, respectively. During 2004, 2003 and 2002, AEP Coal derived revenues from sales to CSPCo of $1.0 million, $3.4 million and $3.5 million, respectively.

Natural Gas Contracts with DETM

Effective October 31, 2003, AEPES assigned to AEPSC, as agent for the AEP East companies, approximately $97 million (negative value) associated with its natural gas contracts with DETM. The assignment was executed in order to consolidate DETM positions within AEP. Concurrently, in order to ensure that there would be no financial impact to the companies as a result of the assignment, AEPES and AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any related cash settlements and all income related to the assigned contracts. There is no impact to the AEP consolidated financial statements. The following table represents Registrant Subsidiaries’ liabilities at December 31, 2004 and 2003:

	2004			2003
Company	(in thousands)
APCo	$	(23,736	)	$	(32,287	)
CSPCo		(13,654	)		(18,185	)
I&M		(15,266	)		(19,932	)
KPCo		(5,570	)		(7,349	)
OPCo		(19,065	)		(24,055	)
Total	$	(77,291	)	$	(101,808	)

Fuel Agreement between OCPo and National Power Cooperative, Inc

In conjunction with a 500 MW agreement between OPCo and National Power Cooperative, Inc (NPC), AEPES entered into a fuel management agreement with those two parties to manage and procure fuel needs for the gas plant, which is owned by NPC. The plant went into service in July 2002 and the AEP East companies purchase 100% of the available generating capacity from the plant through December 2005. The related purchases of gas managed by AEPES were as follows:

	Year Ended December 31,
	2004		2003		2002
Company	(in thousands)
APCo	$	1,351	$	1,546	$	583
CSPCo		804		936		387
I&M		884		1,000		418
KPCo		315		363		150
OPCo		980		1,234		519
Total	$	4,334	$	5,079	$	2,057

Unit Power Agreements

A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) for such amounts, as when added to amounts received by AEGCo from any other sources, will be at least sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo unit power agreement was renegotiated and extended from December 31, 2004 to December 7, 2022.

I&M Barging and Other Services

I&M provides barging and other transportation services to affiliates. I&M records revenues from barging services as nonoperating income. The affiliates record costs paid to I&M for barging services as fuel expense or operation expense. The amount of affiliated revenues and affiliated expenses were:

	Year Ended December 31,
	2004		2003		2002
Company	(in millions)
I&M - revenues	$	38.2	$	31.9	$	34.3
AEGCo - expense		9.5		8.1		7.8
APCo - expense		13.0		12.3		12.8
KPCo - expense		0.1		0.1		-
OPCo - expense		4.9		4.3		7.9
MEMCo - expense (Nonutility subsidiary of AEP)		10.7		7.1		5.7
AEP Energy Services - expense (Nonutility subsidiary of AEP)		-		-		0.1

MEMCO services provided and received

AEP MEMCO LLC (MEMCO) provides services for barge towing and general and administrative expenses to I&M. The costs are recorded by I&M as nonoperating expenses. For the years ended December 31, 2004, 2003 and 2002, I&M recorded $12.6 million, $8.8 million and $2.6 million, respectively.

I&M provides services for barge towing and general and administrative expenses to MEMCO. The income is recorded by I&M as an offset to nonoperating expense. For the years ended December 31, 2004, 2003 and 2002, I&M recorded $10.7 million, $7.0 million and $5.0 million, respectively.

Gas Purchases from HPL

HPL purchases physical gas in the spot market, which in turn, is sold to certain operating companies at cost for their fuel requirements. The related HPL sales to TCC and TNC are as follows:

	Year Ended December 31,
	2004 (a)		2003		2002
Company	(in thousands)
TCC	$	129,682	$	195,527	$	157,346
TNC		45,767		44,197		64,385

(a) In 2004, purchases from Oklaunion along with the HPL purchases described above comprise the total Fuel from Affiliates for Electric Generation as shown on the Registrant Subsidiaries’ financial statements.

OPCo Indemnification Agreement with AEPR

OPCo has an indemnification agreement with AEPR whereby AEPR holds OPCo harmless from market exposure related to OPCo’s Power Purchase and Sale Agreement dated November 15, 2000 with Dow Chemical Company. In 2004, AEPR paid OPCo $21.5 million, which is reported in OPCo’s Nonoperating Income and Nonoperating Expenses on its Consolidated Statements of Income. See Note 7, “Power Generation Facility - Affecting OPCo” for further discussion.

Purchased Power from Ohio Valley Electric Corporation

The amounts of power purchased by the Registrant Subsidiaries from Ohio Valley Electric Corporation, which is 44.2% owned by the AEP and CSPCo, for the years ended December 31, 2004, 2003 and 2002 were:

	Year Ended December 31,
	2004		2003		2002
Company	(in thousands)
APCo	$	62,101	$	55,219	$	53,386
CSPCo		16,724		15,259		14,885
I&M		27,474		25,659		23,282
OPCo		55,052		50,995		50,135

Sales of Property

The Registrant Subsidiaries had sales of electric property for the years ended December 31, 2004, 2003 and 2002 as shown in the following table.

	2004
	(in thousands)
APCo to OPCo	$	2,992
I&M to APCo		1,630
		2003
		(in thousands)
AEGCo to OPCo	$	105
APCo to OPCo		1,079
I&M to OPCo		1,492
OPCo to APCo		2,768
OPCo to I&M		1,096
		2002
		(in thousands)
OPCo to I&M	$	4,768

AEPSC

AEPSC provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable bases of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the PUHCA.

18.JOINTLY-OWNED ELECTRIC UTILITY PLANT

CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly-owned with affiliated and nonaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each Registrant Subsidiary’s proportionate share of the operating costs associated with such facilities is included in its statements of operations and the investments are reflected in its balance sheets under utility plant as follows:

				Company’s Share December 31,
				2004				2003
	Percent of Ownership			Utility Plant in Service		Construction Work in Progress		Utility Plant in Service		Construction Work in Progress
CSPCo				(in thousands)
W.C. Beckjord Generating Station (Unit No. 6)		12.5	%	$	15,531	$	139	$	15,455	$	127
Conesville Generating Station (Unit No. 4)		43.5			85,036		654		82,115		722
J.M. Stuart Generating Station		26.0			209,842		60,535		204,820		50,326
Wm. H. Zimmer Generating Station		25.4			741,043		7,976		707,281		31,249
Transmission		(a)			62,287		3,744		62,061		742
Total				$	1,113,739	$	73,048	$	1,071,732	$	83,166
PSO
Oklaunion Generating Station (Unit No. 1)		15.6	%	$	85,834	$	345	$	85,064	$	518
SWEPCo
Dolet Hills Generating Station (Unit No. 1)		40.2	%	$	237,741	$	2,559	$	236,116	$	2,304
Flint Creek Generating Station (Unit No. 1)		50.0			93,887		756		93,309		737
Pirkey Generating Station (Unit No. 1)		85.9			456,730		2,373		454,303		3,125
Total				$	788,358	$	5,688	$	783,728	$	6,166
TCC (b)
Oklaunion Generating Station (Unit No. 1)		7.8	%	$	39,464	$	271	$	38,798	$	252
South Texas Project Generation Station   (Units No. 1 and 2)		25.2			2,386,961		2,144		2,386,579		934
Total				$	2,426,425	$	2,415	$	2,425,377	$	1,186
TNC
Oklaunion Generating Station (Unit No. 1)		54.7	%	$	287,198	$	1,418	$	285,314	$	1,351

(a)	Varying percentages of ownership.
(b)	Included in Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

The accumulated depreciation with respect to each Registrant Subsidiary’s share of jointly owned facilities is shown below:

	December 31,
	2004		2003
Company	(in thousands)
CSPCo	$	464,136	$	435,249
PSO		52,679		50,968
SWEPCo		491,269		465,871
TCC (a)		991,410		991,665
TNC		110,763		103,642

(a) Included in Assets Held for Sale - Texas Generation Plants on TCC’s Consolidated Balance Sheets.

19.UNAUDITED QUARTERLY FINANCIAL INFORMATION

The unaudited quarterly financial information for each Registrant Subsidiary follows:

Quarterly Periods Ended:	AEGCo		APCo		CSPCo		I&M		KPCo
	(in thousands)
March 31, 2004
Operating Revenues	$	55,282	$	526,457	$	362,305	$	412,186	$	113,513
Operating Income		1,547		87,397		54,508		56,813		19,214
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		1,827		65,336		45,119		43,008		11,611
Net Income		1,827		65,336		45,119		43,008		11,611
June 30, 2004
Operating Revenues	$	56,348	$	464,517	$	358,126	$	406,802	$	109,142
Operating Income		1,373		46,082		44,629		42,995		11,605
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		1,506		21,826		30,755		27,030		4,068
Net Income		1,506		21,826		30,755		27,030		4,068
September 30, 2004
Operating Revenues	$	65,303	$	491,385	$	391,833	$	443,660	$	114,712
Operating Income		2,214		62,690		65,262		67,482		13,479
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		2,404		38,459		52,570		51,548		6,160
Net Income		2,404		38,459		52,570		51,548		6,160
December 31, 2004
Operating Revenues	$	64,855	$	465,823	$	321,317	$	398,932	$	113,246
Operating Income		1,770		47,841		19,847		28,598		11,023
Income (Loss) Before Extraordinary Item  and Cumulative Effect of Accounting Changes		2,105		27,494		11,814		11,636		4,066
Net Income (Loss)		2,105		27,494		11,814		11,636		4,066

Quarterly Periods Ended:	OPCo		PSO			SWEPCo		TCC			TNC
	(in thousands)
March 31, 2004
Operating Revenues	$	589,706	$	207,456		$	236,160	$	287,123		$	104,377
Operating Income		108,359		856			20,197		55,519			17,350
Income (Loss) Before Extraordinary Item and  Cumulative Effect of Accounting Changes		80,164		(9,003	)		5,021		29,404			13,096
Net Income (Loss)		80,164		(9,003	)		5,021		29,404			13,096
June 30, 2004
Operating Revenues	$	533,058	$	231,623		$	268,728	$	269,868		$	101,052
Operating Income		62,910		16,860			41,528		23,337			10,772
Income (Loss) Before Extraordinary Item and  Cumulative Effect of Accounting Changes		38,783		7,391			27,946		(341	)		7,751
Net Income (Loss)		38,783		7,391			27,946		(341	)		7,751
September 30, 2004
Operating Revenues	$	558,116	$	356,631		$	330,370	$	354,609		$	152,504
Operating Income		80,837		47,202			60,618		67,790			21,895
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		50,685		38,980			47,209		43,012			16,853
Net Income		50,685		38,980			47,209		43,012			16,853
December 31, 2004
Operating Revenues	$	555,516	$	251,811		$	252,088	$	263,666		$	134,212
Operating Income		60,266		10,158			20,835		49,373			11,229
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes (a)		40,484		174			9,281		222,581			9,959
Net Income		40,484		174			9,281		102,047			9,959

(a) See “Texas Restructuring” and “Net Stranded Generation Costs” sections of Note 6 for a discussion of net adjustments of stranded costs recorded in the fourth quarter of 2004.

Quarterly Periods Ended:	AEGCo		APCo		CSPCo		I&M			KPCo
	(in thousands)
March 31, 2003
Operating Revenues	$	60,428	$	536,228	$	359,205	$	418,598		$	112,094
Operating Income		1,851		112,684		55,151		58,990			19,834
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		1,796		79,153		38,359		30,687			11,021
Net Income		1,796		156,410		65,642		27,527			9,887
June 30, 2003
Operating Revenues	$	59,568	$	444,751	$	333,071	$	376,906		$	95,464
Operating Income		1,514		49,056		43,417		19,229			10,964
Income (Loss) Before Extraordinary Item and  Cumulative Effect of Accounting Changes		1,768		14,636		29,331		(1,191	)		4,095
Net Income (Loss)		1,768		14,636		29,331		(1,191	)		4,095
September 30, 2003
Operating Revenues	$	59,008	$	483,611	$	397,655	$	423,004		$	103,693
Operating Income		1,809		67,134		71,193		56,242			13,097
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		2,021		45,715		62,825		37,116			6,501
Net Income		2,021		45,715		62,825		37,116			6,501
December 31, 2003
Operating Revenues	$	54,161	$	492,768	$	341,920	$	377,088		$	105,219
Operating Income		2,000		89,937		55,725		51,606			20,849
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		2,379		63,279		42,632		22,936			11,847
Net Income		2,379		63,279		42,632		22,936			11,847

Quarterly Periods Ended:	OPCo		PSO			SWEPCo		TCC		TNC
	(in thousands)
March 31, 2003
Operating Revenues	$	590,631	$	242,662		$	255,278	$	428,358	$	116,262
Operating Income		98,870		13,146			26,044		92,010		9,865
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		68,350		691			10,491		64,437		6,765
Net Income		192,982		691			19,008		64,559		9,836
June 30, 2003
Operating Revenues	$	539,386	$	277,236		$	281,306	$	482,446	$	136,806
Operating Income		79,831		28,715			35,588		96,603		23,243
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		56,277		17,927			20,590		63,587		17,922
Net Income		56,277		17,927			20,590		63,587		17,922
September 30, 2003
Operating Revenues	$	565,318	$	358,575		$	361,622	$	485,129	$	114,455
Operating Income		93,798		43,527			59,229		84,502		17,419
Income Before Extraordinary Item and  Cumulative Effect of Accounting Changes		70,367		38,090			42,181		66,221		17,347
Net Income		70,367		38,090			42,181		66,221		17,347
December 31, 2003
Operating Revenues	$	549,318	$	224,349		$	248,636	$	351,578	$	98,423
Operating Income		87,168		7,475			29,275		48,425		17,500
Income (Loss) Before Extraordinary Item  and Cumulative Effect of Accounting Changes		56,037		(2,817	)		16,362		23,302		13,629
Net Income (Loss)		56,037		(2,817	)		16,362		23,302		13,452

For each of the Registrant Subsidiaries, (excluding TCC for 2004) there were no significant, nonrecurring events in the fourth quarter of 2004 or 2003.

COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES

The following is a combined presentation of certain components of the registrants’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and results of operations and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements, (iii) footnotes and (iv) the schedules of each individual registrant.

Source of Funding

Short-term funding for AEP’s electric subsidiaries comes from AEP’s commercial paper program and revolving credit facilities. Proceeds are loaned to the subsidiaries through intercompany notes. AEP and its subsidiaries also operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity for certain electric subsidiaries. The electric subsidiaries generally use short-term funding sources (the money pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leaseback, leasing arrangements and additional capital contributions from their parent company.

Dividend Restrictions

Under PUHCA, Registrant Subsidiaries can only pay dividends out of retained or current earnings.

Sale of Receivables Through AEP Credit

AEP Credit has a sale of receivables agreement with banks and commercial paper conduits. Under the sale of receivables agreement, AEP Credit sells an interest in the receivables it acquires to the commercial paper conduits and banks and receives cash. AEP does not have an ownership interest in the commercial paper conduits and is not required to consolidate these entities in accordance with GAAP. AEP continues to service the receivables. This off-balance sheet transaction was entered to allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables, and accelerate cash collections.

During 2004, AEP Credit renewed its sale of receivables agreement through August 24, 2007. The sale of receivables agreement provides commitments of $600 million to purchase receivables from AEP Credit. At December 31, 2004, $435 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. All receivables sold represent affiliate receivables. AEP Credit maintains a retained interest in the receivables sold and this interest is pledged as collateral for the collection of receivables sold. The fair value of the retained interest is based on book value due to the short-term nature of the accounts receivable less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with certain Registrant Subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit.

Budgeted Construction Expenditures

Construction expenditures for Registrant Subsidiaries for 2005 are:

	Projected Construction Expenditures
Company	(in millions)
AEGCo	$	19.9
APCo		696.7
CSPCo		193.9
I&M		322.8
KPCo		56.1
OPCo		765.6
PSO		126.2
SWEPCo		200.9
TCC		208.5
TNC		73.9

Significant Factors

Possible Divestitures

AEP’s management is firmly committed to continually evaluating the need to reallocate resources to areas that effectively match investments with our business strategy, providing the greatest potential for financial returns and to disposing of investments that no longer meet these goals.

TCC made progress on its planned divestiture of its generation assets by (1) announcing in June 2004 and September 2004 that it had signed agreements to sell its 7.81% share of the Oklaunion Power Station to two nonaffiliated co-owners of the plant for approximately $43 million, subject to closing adjustments, (2) announcing in September 2004 that it had signed agreements to sell its 25.2% share of the STP nuclear plant to two nonaffiliated co-owners of the plant for approximately $333 million, subject to closing adjustments, and (3) closing in July 2004 on the sale of its remaining generation assets, including eight natural gas plants, one coal-fired plant and one hydro-electric plant for approximately $428 million, net of adjustments. TCC expects the sales of Oklaunion and STP to be completed in the first half of 2005. Nevertheless, there could be potential delays in receiving necessary regulatory approvals and clearances or in resolving litigation with a third party affecting Oklaunion which could delay the closings. TCC will file with the PUCT to recover net stranded costs associated with the sales pursuant to Texas Restructuring Legislation. Stranded costs will be calculated on the basis of all generation assets, not individual plants.

Texas Regulatory Activity - Affecting TCC

Texas Restructuring

Texas Restructuring Legislation enacted in 1999 provides the framework and timetable to allow retail electricity competition.

The Texas Restructuring Legislation, among other things:

● provides for the recovery of net stranded generation costs and other generation true-up amounts through securitization and nonbypassable wires charges,

● requires each utility to structurally unbundle into a retail electric provider, a power generation company and a transmission and distribution (T&D) utility,

● provides for an earnings test for each of the years 1999 through 2001 and,

● provides for a stranded cost True-up Proceeding after January 10, 2004.

The True-up Proceedings will determine the amount and recovery of:

● net stranded generation plant costs and net generation-related regulatory assets less any unrefunded excess earnings (net stranded generation costs),

● a true-up of actual market prices determined through legislatively-mandated capacity auctions to the projected power costs used in the PUCT’s excess cost over market (ECOM) model for 2002 and 2003 (wholesale capacity auction true-up revenues),

● excess of price-to-beat revenues over market prices subject to certain conditions and limitations (retail clawback),

● final approved deferred fuel balance, and

● net carrying costs on true-up amounts.

TCC’s recorded net true-up regulatory asset for amounts subject to approval in the True-up Proceeding is approximately $1.6 billionat December 31, 2004.

The Texas Restructuring Legislation required utilities with stranded generation plant costs to use market-based methods to value certain generation assets for determining stranded generation plant costs. TCC elected to use the sale of assets method to determine the market value of its generation assets for determining stranded generation plant costs. For purposes of the True-up Proceeding, the amount of stranded generation plant costs under this market valuation methodology will be the amount by which the book value of TCC’s generation assets exceeds the market value of the generation assets as measured by the net proceeds from the sale of the assets.

In December 2003, based on an expected loss from the sale of its generating assets, TCC recognized as a regulatory asset an estimated impairment of approximately $938 million from the sale of all its generation assets. The impairment was computed based on an estimate of TCC’s generation assets sales price compared to book basis at December 31, 2003. On July 1, 2004, TCC completed the sale of most of its coal, gas and hydro plants for approximately $428 million, net of adjustments. The closings of the sales of STP and Oklaunion plants are expected to occur in the first half of 2005, subject to resolution of the rights of first refusal issues and obtaining the necessary regulatory approvals. In addition, there could be delays in resolving litigation with a third party affecting Oklaunion. On February 15, 2005, TCC filed with the PUCT requesting a good cause exception to the true-up rule to allow TCC to make its true-up filing prior to the closings of the sales of all the generation assets. TCC asked the PUCT to rule on the request in April 2005.

On December 17, 2004, the PUCT also issued an Order on Rehearing in the CenterPoint True-up Proceeding (CenterPoint Order). CenterPoint is a nonaffiliated electric utility in Texas. Among other things, the CenterPoint Order provided certain adjustments to stranded generation plant costs to avoid what the PUCT deemed to be duplicative recovery of stranded costs and the capacity auction true-up amount. The CenterPoint Order also confirmed that stranded costs are to be determined as of December 31, 2001, and identified how carrying costs from that date are to be computed.

In the fourth quarter of 2004, TCC made net adjustments totaling $185 million ($121 million, net of tax) to its stranded generation plant cost regulatory asset. TCC increased this net regulatory asset by $53 million to adjust its estimated impairment loss to a December 31, 2001 book basis (instead of December 31, 2003 book basis), including the reflection of certain PUCT-ordered accelerated amortizations of the STP nuclear plant as of that date. In addition, TCC’s stranded generation plant costs regulatory asset was reduced by $238 million based on an applicable PUCT duplicate depreciation adjustment in the CenterPoint Order. These net adjustments are reflected as Extraordinary Loss on Texas Stranded Cost Recovery, Net of Tax in TCC’s Consolidated Statements of Income.

In addition to the two items above (the $938 million impairment in 2003 and the $185 million adjustment in 2004), TCC had recorded $121 million of impairments in 2002 and 2003 on its gas-fired plants. Additionally, other miscellaneous items and the costs to complete the sales, which are still ongoing, of $23 million are included in the recoverable stranded generation plant costs of $897 million.

In the CenterPoint Order, the PUCT specified the manner in which carrying costs should be calculated. In December 2004, TCC computed, based on its interpretation of the methodology contained in the CenterPoint Order, carrying costs of $470 million for the period January 1, 2002 through December 31, 2004 on its stranded generation plant costs net of excess earnings and its wholesale capacity auction true-up regulatory assets at the 11.79% overall pretax cost of capital rate in its UCOS rate proceeding. The embedded 8.12% debt component of the carrying cost of $302 million ($225 million on stranded generation plant costs and $77 million on wholesale capacity auction true-up) was recognized in income in December 2004. This amount is included in Carrying Costs on Stranded Cost Recovery in TCC’s Consolidated Statements of Income. Of the $302 million recorded in 2004, approximately $109 million, $105 million and $88 million related to the years 2004, 2003 and 2002, respectively. The remaining equity component of $168 million will be recognized in income as collected. TCC will continue to accrue a carrying cost at the rate set forth above until it recovers its approved net true-up regulatory asset. If the PUCT further adjusts TCC’s net true-up regulatory asset in TCC’s True-up Proceeding, the carrying cost will also be adjusted.

When the True-up Proceeding is completed, TCC intends to file to recover PUCT-approved net stranded generation costs and other true-up amounts, plus appropriate carrying costs, through nonbypassable transition charges and competition transition charges in the regulated T&D rates. TCC will seek to securitize the approved net stranded generation costs plus related carrying costs. The securitizable portion of this net true-up regulatory asset, which consists of net stranded generation costs plus related carrying costs, was $1.4 billion at December 31, 2004. The other approved net true-up items will be recovered or refunded over time through a nonbypassable competition transition wires charge or credit inclusive of a carrying cost. We expect that TCC’s True-up Proceeding filing will seek to recover an amount in excess of the total of its recorded net true-up regulatory asset through December 31, 2004. The PUCT will review TCC’s filing and determine the amount for the recoverable net true-up regulatory assets.

Due to differences between CenterPoint’s and TCC’s facts and circumstances, the lack of direct applicability of certain portions of the CenterPoint Order to TCC and the unknown nature of future developments in TCC’s True-up Proceeding, we cannot, at this time, determine if TCC will incur additional disallowances in its True-up Proceeding. We believe that TCC’s recorded net true-up regulatory asset at December 31, 2004 is in compliance with the Texas Restructuring Legislation, and the applicable portions of the CenterPoint Order and other nonaffiliated true-up orders, and we intend to seek vigorously its recovery. If, however, TCC determines that it is probable it cannot recover a portion of its recorded net true-up regulatory asset of $1.6 billion at December 31, 2004 and TCC is able to estimate the amount of such nonrecovery, TCC will record a provision for such amount, which could have a material adverse effect on future results of operations, cash flows and possibly financial condition. To the extent decisions in the TCC True-up Proceeding differ from management’s interpretation of the Texas Restructuring Legislation and its evaluation of the applicable portions of the CenterPoint and other true-up orders, additional material disallowances are possible.

See “TEXAS RESTRUCTURING” section of Note 6 for further discussion of Texas Regulatory Activity.

TCC Rate Case

On June 26, 2003, the City of McAllen, Texas requested that TCC provide justification showing that its transmission and distribution rates should not be reduced. Other municipalities served by TCC passed similar rate review resolutions. In Texas, municipalities have original jurisdiction over rates of electric utilities within their municipal limits. Under Texas law, TCC must provide support for its rates to the municipalities. TCC filed the requested support for its rates based on a test year ending June 30, 2003 with all of its municipalities and the PUCT on November 3, 2003. TCC’s proposal would decrease its wholesale transmission rates by $2 million or 2.5% and increase its retail energy delivery rates by $69 million or 19.2%.

In February 2004, eight intervening parties and the PUCT Staff filed testimony recommending reductions to TCC’s requested $67 million annual rate increase. Their recommendations ranged from a decrease in annual existing rates of approximately $100 million to an increase in TCC’s current rates of approximately $27 million. Hearings were held in March 2004. In May 2004, TCC agreed to a nonunanimous settlement on cost of capital including capital structure and return on equity with all but two parties in the proceeding. TCC agreed that the return on equity should be established at 10.125% based upon a capital structure with 40% equity resulting in a weighted cost of capital of 7.475%. The settlement and other agreed adjustments reduced TCC’s rate request from an increase of $67 million to an increase of $41 million.

On July 1, 2004, the ALJs who heard the case issued their recommendations, which included a recommendation to approve the cost of capital settlement. The ALJs recommended that an issue related to the allocation of consolidated tax savings to the transmission and distribution utility be remanded back to the ALJs for additional evidence. On July 15, 2004, the PUCT remanded this issue to the ALJs. On August 19, 2004, in a separate ruling, the PUCT remanded six other issues to the ALJs requesting revisions to clarify and support the recommendations in the Proposal for Decision (PFD).

The PUCT ordered TCC to calculate its revenue requirements based upon the recommendations of the ALJs. On July 21, 2004, TCC filed its revenue requirements based upon the recommendations of the ALJs. According to TCC’s calculations, the ALJs’ recommendations would reduce TCC’s annual existing rates between $33 million and $43 million depending on the final resolution of the amount of consolidated tax savings.

On November 16, 2004, the ALJs issued their PFD on remand, increasing their recommended annual rate reduction to a range of $51 million to $78 million, depending on the amount disallowed related to affiliated AEPSC billed expenses. At the January 13, 2005 and January 27, 2005 open meetings, the Commissioners considered a number of issues, but deferred resolution of the affiliated AEPSC billed expenses issue, among other less significant issues, until after additional hearings scheduled for early March 2005. Adjusted for the decisions announced by the Commissioners in January 2005, the ALJs’ disallowance would yield an annual rate reduction of a range of $48 million to $75 million. If TCC were to prevail on the affiliated expenses issue and all remaining issues, the result would be annual rate increase of $6 million. When issued, the PUCT order will affect revenues prospectively. An order reducing TCC’s rates could have a material adverse effect on future results of operations and cash flows.

Ohio Regulatory Activity - Affecting CSPCo and OPCo

The Ohio Electric Restructuring Act of 1999 (Ohio Act) provides for a Market Development Period (MDP) during which retail customers can choose their electric power suppliers or receive Default Service at frozen generation rates from the incumbent utility. The MDP began on January 1, 2001 and is scheduled to terminate no later than December 31, 2005.

The PUCO invited default service providers to propose an alternative to all customers moving to market prices on January 1, 2006. On February 9, 2004, CSPCo and OPCo filed rate stabilization plans with the PUCO addressing prices for the three-year period following the end of the MDP, January 1, 2006 through December 31, 2008. The plans are intended to provide price stability and certainty for customers, facilitate the development of a competitive retail market in Ohio, provide recovery of environmental and other costs during the plan period and improve the environmental performance of AEP’s generation resources that serve Ohio customers. On January 26, 2005, the PUCO approved the plans with some modifications.

The approved plans include annual, fixed increases in the generation component of all customers’ bills (3% a year for CSPCo and 7% a year for OPCo) in 2006, 2007 and 2008. The plan also includes the opportunity to annually request an additional increase in supply prices averaging up to 4% per year for each company to recover certain new governmentally mandated increased expenditures set out in the approved plan. The plans maintain distribution rates through the end of 2008 for CSPCo and OPCo at the level in effect on December 31, 2005. Such rates could be adjusted with PUCO approval for specified reasons. Transmission charges could also be adjusted to reflect applicable charges approved by the FERC related to open access transmission, net congestion and ancillary services. The approved plans provide for the continued amortization and recovery of stranded transition generation-related regulatory assets. The plans, as modified by the PUCO, require CSPCo and OPCo to allot a combined total of $14 million of previously provided unspent shopping incentives for the benefit of their low-income customers and economic development over the three-year period ending December 31, 2008 which will not have an effect on net income. The plans also authorized each company to establish unavoidable riders applicable to all distribution customers in order to be compensated in 2006 through 2008 for certain new costs incurred in 2004 and 2005 of fulfilling the companies’ Provider of Last Resort (POLR) obligations. These costs include RTO administrative fees and congestion costs net of financial transmission revenues and carrying cost of environmental capital expenditures. As a result, in 2005, CSPCo and OPCo expect to record regulatory assets of approximately $8 million and $21 million, respectively, for the subject costs related to 2004 and $14 million and $52 million, respectively,  for expected subject costs related to 2005. These regulatory assets totaling $22 million for CSPCo and $73 million for OPCo will be amortized as the costs are recovered through POLR riders in 2006 through 2008. The riders, together with the fixed annual increases in generation rates are estimated to provide additional cumulative revenues to CSPCo and OPCo of $190 million and $500 million, respectively, in the three-year period ended December 31, 2008. Other revenue increases may occur related to other provisions of the plans discussed above.

On February 25, 2005, various intervenors filed Applications for Rehearing with the PUCO regarding their approval of the rate stabilization plans.  Management expects the PUCO to address the applications before the end of March 2005.  Management cannot predict the ultimate impact these proceedings will have on the results of operations and cash flows.

See “OHIO RESTRUCTURING” section of Note 6 for further discussion of Ohio Regulatory Activity.

Oklahoma Regulatory Activity - Affecting PSO

PSO Fuel and Purchased Power

In 2002, PSO experienced a $44 million under-recovery of fuel costs resulting from a reallocation among AEP West electric operating companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO submitted a request to the OCC to collect those costs over 18 months. In August 2003, the OCC Staff filed testimony recommending PSO recover $42 million of the reallocation over three years. In September 2003, the OCC expanded the case to include a full review of PSO’s 2001 fuel and purchased power practices. PSO filed testimony in February 2004.

An intervenor and the OCC Staff filed testimony in April 2004. The intervenor suggested that $9 million related to the 2002 reallocation not be recovered from customers. The Attorney General of Oklahoma also filed a statement of position, indicating allocated off-system sales margins between and among AEP West companies were inconsistent with the FERC-approved Operating Agreement and System Integration Agreement and, if corrected, could more than offset the $44 million 2002 reallocation under-recovery. The intervenor and the OCC Staff also argued that off-system sales margins were allocated incorrectly. The intervenors’ reallocation of such margins would reduce PSO’s recoverable fuel costs by $7 million for 2000 and $11 million for 2001, while under the OCC Staff method, the reduction for 2001 would be $9 million. The intervenor and the OCC Staff also recommended recalculation of PSO’s fuel costs for years subsequent to 2001 using the same revised methods. At a June 2004 prehearing conference, PSO questioned whether the issues in dispute were under the jurisdiction of the OCC because they relate to FERC-approved allocation agreements. As a result, the ALJ ordered that the parties brief the jurisdictional issue. PSO filed its brief on September 1, 2004. After reviewing the briefs, the ALJ recommended that the OCC lacks authority to examine whether PSO deviated from the FERC allocation methodology and that any such complaints should be addressed at the FERC. In January 2005, the OCC conducted a hearing on the jurisdictional matter and a ruling is expected in the near future. Management is unable to predict the ultimate effect of these proceedings on our revenues, results of operations, cash flows and financial condition.

PSO Rate Review

In February 2003, the OCC Staff filed an application requiring PSO to file all documents necessary for a general rate review. In October 2003 and June 2004, PSO filed financial information and supporting testimony in response to the OCC Staff’s request. PSO’s initial response indicated that its annual revenues were $36 million less than costs. The June 2004 filing updated PSO’s request and indicated a $41 million revenue deficiency. As a result, PSO sought OCC approval to increase its base rates by that amount, which is a 3.9% increase over PSO’s existing revenues.

In August 2004, PSO filed a motion to amend the timeline to consider new service quality and reliability requirements, which took effect on July 1, 2004. Also in August 2004, the OCC approved a revised schedule. In October 2004, PSO filed supplemental information requesting consideration of approximately $55 million of additional annual operations and maintenance expenses and annual capital costs to enhance system reliability. In November 2004, PSO filed a plan with the OCC seeking interim rate relief to fund a portion of the costs to meet the new state service quality and reliability requirements pending the outcome of the current case. In the filing, PSO sought interim approval to collect annual incremental distribution tree trimming costs of approximately $23 million from its customers. Intervenors and the OCC Staff filed testimony recommending that the interim rate relief requested by PSO be modified or denied. The OCC issued an order on PSO’s interim request in January 2005, which allows PSO to recover up to an additional $12 million annually for reliability activities beginning in December 2004. Expenses exceeding that amount and the amount currently included in base rates will be considered in the base rate case.

The OCC Staff and intervenors filed testimony regarding their recommendations on revenue requirement, fuel procurement, resource planning and vegetation management in January 2005. Their recommendations ranged from a decrease in annual existing rates between $15 million and $36 million. In addition, one party recommended that the OCC require PSO file additional information regarding its natural gas purchasing practices. In the absence of such a filing, this party suggested that $30 million of PSO’s natural gas costs not be recovered from customers because it failed to implement a procurement strategy that, according to this party, would have resulted in lower natural gas costs. OCC Staff and intervenors recommended a return on common equity ranging from 9.3% to 10.11%. PSO’s rebuttal testimony was filed in February 2005, and that testimony reflects a number of adjustments to PSO’s June 2004 updated filing. These adjustments result in a decrease of PSO’s revenue deficiency from $41 million to $28 million, although approximately $9 million of that decrease are items that would be recovered through the fuel adjustment clause rather than through base rates. Hearings are scheduled to begin in March 2005, and a final decision is not expected any earlier than the second quarter of 2005. Management is unable to predict the ultimate effect of these proceedings on PSO’s revenues, results of operations, cash flows and financial condition.

FERC Order on Regional Through and Out Rates - Affecting AEP East Companies

In July 2003, the FERC issued an order directing PJM and the Midwest Independent System Operator (MISO) to make compliance filings for their respective OATTs to eliminate the transaction-based charges for through and out (T&O) transmission service on transactions where the energy is delivered within the proposed MISO and expanded PJM regions (Combined Footprint). The elimination of the T&O rates will reduce the transmission service revenues collected by the RTOs and thereby reduce the revenues received by transmission owners including AEP East companies under the RTOs’ revenue distribution protocols.

In November 2003, the FERC issued an order finding that the T&O rates of the former Alliance RTO participants, including AEP, should also be eliminated for transactions within the Combined Footprint. The order directed the RTOs and former Alliance RTO participants to file compliance rates to eliminate T&O rates prospectively within the Combined Footprint and simultaneously implement a load-based transitional rate mechanism called the seams elimination cost allocation (SECA), to mitigate the lost T&O revenues for a two-year transition period beginning April 1, 2004. The FERC was expected to implement a new rate design after the two-year period. In April 2004, the FERC approved a settlement that delayed elimination of T&O rates and the implementation of SECA replacement rates until December 1, 2004 when the FERC would implement a new rate design.

On November 18, 2004, the FERC conditionally approved a license plate rate design to eliminate rate pancaking for transmission service within the Combined Footprint and adopted its previously approved SECA transition rate methodology to mitigate the effects of the elimination of T&O rates effective December 1, 2004. Under license plate rates, customers serving load within a RTO pay transmission service rates based on the embedded cost of the transmission facilities in the local pricing zone where the load being served is located. The use of license plate rates would shift costs that were previously recovered from T&O service customers to mainly AEP’s native load customers within the AEP East pricing zone. The SECA transition rates will remain in effect through March 31, 2006. The SECA rates are designed to mitigate the loss of revenues due to the elimination of T&O rates.

The SECA rates became effective December 1, 2004. Billing statements from PJM for December 2004 did not reflect any credits to AEP for SECA revenues. Based upon the SECA transition rate methodology approved by the FERC, AEP East companies accrued $11 million in December 2004 for SECA revenues. On January 7, 2005, AEP and Exelon filed joint comments and protest with the FERC including a request that FERC direct PJM and MISO to comply with the FERC decision and collect all SECA revenues due with interest charges for all late-billed amounts. On February 10, 2005, the FERC issued an order indicating that the SECA transition rates would be subject to refund or surcharge and set for hearing all remaining aspects of the compliance filings to the November 18 order, including AEP's request that the FERC direct PJM and MISO begin billing and collecting the SECA transition rates.

The AEP East companies received approximately $196 million of T&O rate revenues for the twelve months ended September 30, 2004, the twelve months prior to joining PJM. The portion of those revenues associated with transactions for which the T&O rate is being eliminated and replaced by SECA charges was $171 million. At this time, management is unable to predict whether the SECA transition rates will fully compensate the AEP East companies for their lost T&O revenues for the period December 1, 2004 through March 31, 2006 and whether, effective with the expiration of the SECA rates on March 31, 2006, the resultant increase in the AEP East zonal transmission rates applicable to AEP’s internal load will be recoverable on a timely basis in the AEP East state retail jurisdictions and from wholesale customers within the AEP zone. If the SECA transition rates do not fully compensate the AEP East companies for its lost T&O revenues through March 31, 2006, or if any increase in the AEP East Companies’ transmission expenses from higher AEP zonal rates are not fully recovered in retail and wholesale rates on a timely basis, future results of operations, cash flows and financial condition could be materially affected.

Pension and Postretirement Benefit Plans

AEP maintains qualified, defined benefit pension plans (Qualified Plans or Pensions Plans), which cover a substantial majority of nonunion and certain union associates, and unfunded, nonqualified supplemental plans to provide benefits in excess of amounts permitted to be paid under the provisions of the tax law to participants in the Qualified Plans. Additionally, AEP has entered into individual retirement agreements with certain current and retired executives that provide additional retirement benefits. AEP also sponsors other postretirement benefit plans to provide medical and life insurance benefits for retired employees in the U.S. (Postretirement Plans). The Qualified Plans and Postretirement Plans are collectively “the Plans.”

The following table shows the net periodic cost (credit) for AEP’s Pension Plans and Postretirement Plans:

	2004			2003
	(in millions)
Net Periodic Cost (Credit):
Pension Plans	$	40		$	(3	)
Postretirement Plans		141			188
Assumed Rate of Return:
Pension Plans		8.75	%		9.00	%
Postretirement Plans		8.35	%		8.75	%

The net periodic cost is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on the Plans’ assets. In developing the expected long-term rate of return assumption, AEP evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Projected returns by such actuaries and consultants are based on broad equity and bond indices. AEP also considered historical returns of the investment markets as well as its 10-year average return, for the period ended December 2004, of approximately 12%. AEP anticipates that the investment managers employed for the Plans will continue to generate long-term returns averaging 8.75%.

The expected long-term rate of return on the Plans’ assets is based on AEP’s targeted asset allocation and its expected investment returns for each investment category. AEP’s assumptions are summarized in the following table:

	2004 Actual Pension Plan Asset Allocation			2004 Actual Postretirement Plan Asset Allocation			2005 Target Asset Allocation			Assumed/Expected Long-term Rate of Return
Equity		68	%		70	%		70	%		10.50	%
Fixed Income		25	%		28	%		28	%		5.00	%
Cash and Cash Equivalents		7	%		2	%		2	%		2.00	%
Total		100	%		100	%		100	%
Overall Expected Return (weighted average)											8.75	%

AEP regularly reviews the actual asset allocation and periodically rebalances the investments to its targeted allocation when considered appropriate. Because of a $200 million discretionary contribution to the Qualified Plans at the end of 2004, the actual asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced back to the target allocation in January 2005. AEP believes that 8.75% is a reasonable long-term rate of return on the Plans’ assets despite the recent market volatility. The Plans’ assets had an actual gain of 13.75% and 23.80% for the twelve months ended December 31, 2004 and 2003, respectively. AEP will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust them as necessary.

AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2004, AEP had cumulative losses of approximately $30 million which remain to be recognized in the calculation of the market-related value of assets. These unrecognized net actuarial losses result in increases in the future pension costs depending on several factors, including whether such losses at each measurement date exceed the corridor in accordance with SFAS No. 87, “Employers’ Accounting for Pensions.”

The method used to determine the discount rate that AEP utilizes for determining future obligations was revised in 2004. Historically, AEP based it on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings from a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, AEP changed to a duration based method where a hypothetical portfolio of high quality corporate bonds was constructed with a duration similar to the duration of the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for the Pension Plans and 5.80% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Plans’ assets of 8.75%, a discount rate of 5.50% and various other assumptions, AEP estimates that the pension cost for all pension plans will approximate $55 million, $54 million and $61 million in 2005, 2006 and 2007, respectively. AEP estimates Postretirement Plan cost will approximate $164 million, $155 million and $146 million in 2005, 2006 and 2007, respectively. Future actual cost will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 0.5% basis point change to selective actuarial assumptions are in “Pension and Other Postretirement Benefits” within the “Critical Accounting Estimates” section of this Combined Management’s Discussion and Analysis of Registrant Subsidiaries.

The value of AEP’s Pension Plans’ assets increased to $3.6 billion at December 31, 2004 from $3.2 billion at December 31, 2003. The Qualified Plans paid $265 million in benefits to plan participants during 2004 (nonqualified plans paid $8 million in benefits). The value of AEP’s Postretirement Plans’ assets increased to $1.1 billion at December 31, 2004 from $1.0 billion at December 31, 2003. The Postretirement Plans paid $109 million in benefits to plan participants during 2004.

For AEP’s underfunded pension plans, the accumulated benefit obligation in excess of plan assets was $474 million and $445 million at December 31, 2004 and 2003, respectively.

A minimum pension liability is recorded for pension plans with an accumulated benefit obligation in excess of the fair value of plan assets. The minimum pension liability for the underfunded pension plans declined during 2004 and 2003, resulting in the following favorable changes, which do not affect earnings or cash flow:

	Decrease in Minimum Pension Liability
	2004			2003
	(in millions)
Other Comprehensive Income	$	(92	)	$	(154	)
Deferred Income Taxes		(52	)		(75	)
Intangible Asset		(3	)		(5	)
Other		(10	)		13
Minimum Pension Liability	$	(157	)	$	(221	)

AEP made an additional discretionary contribution of $200 million in the fourth quarter of 2004 and intends to make additional discretionary contributions of $100 million per quarter in 2005 to meet the goal of fully funding all Qualified Plans by the end of 2005.

Certain pension plans AEP sponsors and maintains contain a cash balance benefit feature. In recent years, cash balance benefit features have become a focus of scrutiny, as government regulators and courts consider how the Employee Retirement Income Security Act of 1974, as amended, the Age Discrimination in Employment Act of 1967, as amended, and other relevant federal employment laws apply to plans with such a cash balance plan feature. AEP believes that the defined benefit pension plans it sponsors and maintains are in compliance with the applicable requirements of such laws.

Litigation

Federal EPA Complaint and Notice of Violation

See discussion of New Source Review Litigation under “Environmental Matters.”

Enron Bankruptcy

In 2002, certain subsidiaries of AEP filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES challenging AEP’s offsetting of receivables and payables and related collateral across various Enron entities and seeking payment of approximately $125 million plus interest in connection with gas-related trading transactions. AEP asserted its right to offset trading payables owed to various Enron entities against trading receivables due to several AEP subsidiaries. The parties are currently in nonbinding, court-sponsored mediation.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC seeking approximately $93 million plus interest in connection with a transaction for the sale and purchase of physical power among Enron, AEP and Allegheny Energy Supply, LLC during November 2001. Enron’s claim seeks to unwind the effects of the transaction. AEP believes it has several defenses to the claims in the action being brought by Enron. The parties are currently in nonbinding, court-sponsored mediation.

The amounts expensed in prior years in connection with the Enron bankruptcy were based on an analysis of contracts where AEP and Enron entities are counterparties, the offsetting of receivables and payables, the application of deposits from Enron entities and management’s analysis of the HPL-related purchase contingencies and indemnifications. As noted above, Enron has challenged the offsetting of receivables and payables. Although management is unable to predict the outcome of these lawsuits, it is possible that their resolution could have an adverse impact on results of operations, cash flows and financial condition.

Merger Litigation

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the SEC failed to adequately explain that the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and sent the case back to the SEC for further review. Specifically, the court told the SEC to revisit the basis for its conclusion that the merger met PUHCA requirements that utilities be “physically interconnected” and confined to a “single area or region.” In January 2005, a hearing was held before an ALJ. Management expects an initial decision from the ALJ later this year. The SEC will review the initial decision.

Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.

Texas Commercial Energy, LLP Lawsuit

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against AEP and four of its subsidiaries including TCC and TNC, certain nonaffiliated energy companies and ERCOT alleging violations of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract, civil conspiracy and negligence. The allegations, not all of which are made against the AEP companies, range from anticompetitive bidding to withholding power. TCE alleges that these activities resulted in price spikes requiring TCE to post additional collateral and ultimately forced it into bankruptcy when it was unable to raise prices to its customers due to fixed price contracts. The suit alleges over $500 million in damages for all defendants and seeks recovery of damages, exemplary damages and court costs. Two additional parties, Utility Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as plaintiffs asserting similar claims. We filed a Motion to Dismiss in September 2003. In February 2004, TCE filed an amended complaint. We filed a Motion to Dismiss the amended complaint. In June 2004, the Court dismissed all claims against the AEP companies. TCE has appealed the trial court’s decision to the United States Court of Appeals for the Fifth Circuit.

Coal Transportation Dispute

PSO, TCC, TNC and two nonaffiliated entities, as joint owners of a generating station, have disputed transportation costs billed for coal received between July 2000 and the present time. The joint plant has remitted less than the amount billed and the dispute is pending before the Surface Transportation Board. Based upon a weighted average probability analysis of possible outcomes, PSO, as operator of the plant, recorded a provision for possible loss in December 2004 and a receivable from the other owners. The provision was deferred as a regulatory asset under PSO’s fuel mechanism and affected income for TCC and TNC for their respective ownership shares. Management continues to work toward mitigating the disputed amounts to the extent possible.

Other Litigation

AEP subsidiaries are involved in a number of other legal proceedings and claims. While management is unable to predict the outcome of such litigation, it is not expected that the ultimate resolution of these matters will have a material adverse effect on results of operations, cash flows or financial condition.

Potential Uninsured Losses

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant or STP and costs of replacement power in the event of a nuclear incident at the Cook Plant or STP. Future losses or liabilities which are not completely insured, unless recovered from customers, could have a material adverse effect on results of operations, cash flows and financial condition.

Environmental Matters

There are new environmental control requirements that management expects will result in substantial capital investments and operational costs. The sources of these future requirements include:

· Legislative and regulatory proposals to adopt stringent controls on sulfur dioxide (SO₂), nitrogen oxide (NO_x) and mercury emissions from coal-fired power plants,

· New Clean Water Act rules 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 emissions to address concerns about global climate change.

In addition to achieving full compliance with all applicable legal requirements, AEP subsidiaries strive to go beyond compliance in an effort to be good environmental stewards. For example, AEP subsidiaries invest in research, through groups like the Electric Power Research Institute, to develop, implement and demonstrate new emission control technologies. AEP subsidiaries plan to continue in a leadership role to protect and preserve the environment while providing vital energy commodities and services to customers at fair prices. AEP subsidiaries have a proven record of efficiently producing and delivering electricity while minimizing the impact on the environment. The AEP System has invested over $2 billion, from 1990 through 2004, to equip many of its facilities with pollution control technologies. The AEP System will continue to make investments to improve the air emissions from its fossil fuel generating stations as this is the most cost-effective generation source to meet its customers’ electricity needs.

In 2002, the AEP System joined the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program. AEP subsidiaries committed to reduce or offset approximately 18 million short tons of CO₂ emissions during 2003-2006 below baseline emissions (i.e. average emission levels during 1998-2001) as adjusted to reflect any changes in the baseline during the commitment period. During 2003, AEP subsidiaries reduced or offset emissions by approximately seven million tons below the voluntary emissions cap and, based on preliminary estimates, AEP subsidiaries anticipate being below the voluntary emissions cap in 2004.

In August 2004, management released “An Assessment of AEP’s Actions to Mitigate the Economic Impacts of Emissions Policies.” The assessment evaluated the AEP System’s operating emissions control technology, planned investment in additional control equipment and risks associated with an uncertain regulatory environment. It concluded that AEP’s actions over the past decade constitute a solid foundation for future efforts to address the intersection between environmental policy and business opportunities. It also concluded that irrespective of the uncertainties surrounding potential air emission regulations and possible future mandatory greenhouse gas regulations, the pollution control investments planned over the next six to eight years are sound. The report also details many of the voluntary actions to be undertaken to limit greenhouse gas emissions and to develop and/or advance future clean energy technologies.

The Current Air Quality Regulatory Framework

The CAA establishes the federal regulatory authority and oversight for emissions from fossil-fired generating plants. The states, with oversight and approval from the Federal EPA, administer and enforce these laws and related regulations.

Title I of the CAA

National Ambient Air Quality Standards: The Federal EPA periodically reviews the available scientific data for six pollutants and establishes a standard for concentration levels in ambient air for these substances to protect the public welfare and public health with an extra margin for safety. These requirements are known as “national ambient air quality standards” (NAAQS).

The states identify those areas within their state that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). States must develop their individual state implementation plans (SIPs) with the intention of bringing nonattainment areas into compliance with the NAAQS. In developing a SIP, each state must demonstrate that attainment areas will maintain compliance with the NAAQS. This is accomplished by controlling sources that emit one or more pollutants or precursors to those pollutants. The Federal EPA approves SIPs if they meet the minimum criteria in the CAA. Alternatively, the Federal EPA may prescribe a federal implementation plan if they conclude that a SIP is deficient. Additionally, the Federal EPA can impose sanctions, up to and including withholding of federal highway funds, in states that fail to submit an adequate SIP or a SIP that fails to bring nonattainment areas into NAAQS compliance within the time prescribed by the CAA.

The CAA also establishes visibility goals, which are known as the regional haze program, for certain federally designated areas, including national parks. States are required to develop and submit SIP provisions that will demonstrate reasonable progress toward preventing the impairment and remedying any existing impairment of visibility in these federally designated areas.

Each state’s SIP must include requirements to control sources that emit pollutants in that state as well as requirements to control sources that significantly contribute to nonattainment areas in another state. If a state believes that its air quality is impacted by upwind sources outside their borders, that state can submit a petition that asks the Federal EPA to impose control requirements on specific sources in other states if those states’ SIPs do not contain adequate requirements to control those sources. For example, the Federal EPA issued a NO_x Rule in 1997, which affected 22 eastern states (including states in which AEP subsidiaries operate) and the District of Columbia. The NO_x Rule asked these 23 jurisdictions to adopt requirements, for utility and industrial boilers and certain other emission sources, to employ cost-effective control technologies to reduce NO_x emissions. The purpose of the request was to reduce the contribution from these 23 jurisdictions to ozone nonattainment areas in certain eastern states.

The Federal EPA also granted four petitions filed by certain eastern states seeking essentially the same levels of control on emission sources outside of their states and issued a Section 126 Rule. All of the states in which the AEP System operates that were subject to the NO_x Rule have submitted the required SIP revisions. In response, the Federal EPA approved the SIPs. The compliance date for the SIPs implementing the NO_x Rule and the revised Section 126 Rule was May 31, 2004. The requirements apply to most of the AEP System’s coal-fired generating units.

In 2000, the Texas Commission on Environmental Quality (TCEQ) adopted rules requiring significant reductions in NO_x emissions from utility sources, including TCC and SWEPCo. The compliance requirements began in May 2003 for TCC and will begin in May 2005 for SWEPCo.

AEP subsidiaries installed a variety of emission control technologies to reduce NO_x emissions and to comply with applicable state and federal NO_x requirements. These include selective catalytic reduction (SCR) technology on certain units and other combustion control technologies on a larger number of units.

AEP’s electric generating units are currently subject to other SIP requirements that control SO₂ and particulate matter emissions in all states, and that control NO_x emissions in certain states. Management believes that the AEP System’s generating plants comply with applicable SIP limits for SO₂, NO_x and particulate matter.

Hazardous Air Pollutants: In the 1990 Amendments to the CAA, Congress required the Federal EPA to identify the sources of 188 hazardous air pollutants (HAPs) and to develop regulations that prescribe a level of HAP emission reduction. These reductions must reflect the application of maximum achievable control technology (MACT). Congress also directed the Federal EPA to investigate HAP emissions from the electric utility sector and to submit a report to Congress. The Federal EPA’s 1998 report to Congress identified mercury emissions from coal-fired electric utility units and nickel emissions from oil-fired utility units as sources of HAP emissions that warranted further investigation and possible control.

New Source Performance Standards and New Source Review: The Federal EPA establishes New Source Performance Standards (NSPS) for 28 categories of major stationary emission sources that reflect the best demonstrated level of pollution control. Sources that are constructed or modified after the effective date of an NSPS standard are required to meet those limitations. For example, many electric generating units are regulated under the NSPS for SO₂, NO_x, and particulate matter. Similarly, each SIP must include regulations that require new sources, and major modifications at existing emission sources that result in a significant net increase in emissions, to submit a permit application and undergo a review of available technologies to control emissions of pollutants. These rules are called new source review (NSR) requirements.

Different NSR requirements apply in attainment and nonattainment areas.

In attainment areas:

· An air quality review must be performed, and

· The best available control technology must be employed to reduce new emissions.

In nonattainment areas:

· Requirements reflecting the lowest achievable emission rate are applied to new or modified sources, and

· All new emissions must be offset by reductions in emissions of the same pollutant from other sources within the same control area.

Neither the NSPS nor NSR requirements apply to certain activities, including routine maintenance, repair or replacement, changes in fuels or raw materials that a source is capable of accommodating, the installation of a pollution control project, and other specifically excluded activities.

Title IV of the CAA (Acid Rain)

The 1990 Amendments to the CAA included a market-based emission reduction program designed to reduce the amount of SO₂ emitted from electric generating units by approximately 50 percent from 1980 levels. This program also established a nationwide cap on utility SO₂ emissions of 8.9 million tons per year. The Federal EPA administers the SO₂ program through an allowance allocation and trading system. Allowances are allocated to specific units based on statutory formulas. Annually each generating unit surrenders one allowance for each ton of SO₂ that it emits. Emission sources may bank their excess allowances for future use or trade them to other emission sources.

Title IV also contains requirements for utility sources to reduce NO_x emissions through the use of available combustion controls. Generating units must meet their specific NO_x emission standards or units under common control may participate in an annual averaging program for that group of units.

Future Reduction Requirements for SO₂, NO_x and Mercury

In 1997, the Federal EPA adopted more stringent NAAQS for fine particulate matter and ground-level ozone. The Federal EPA finalized designations for fine particulate matter nonattainment areas on December 17, 2004. Approximately 200 counties are included in the nonattainment areas including many rural counties in the Eastern United States where our generating units are located. The Federal EPA has not yet issued a rule establishing planning and control requirements or attainment deadlines for these areas. The Federal EPA finalized designations for ozone nonattainment areas on April 15, 2004. On the same day, the Administrator of the Federal EPA signed a final rule establishing the elements that must be included in SIPs to achieve the new standards, and setting deadlines ranging from 2008 to 2015 for achieving compliance with the final standard, based on the severity of nonattainment. All or parts of 474 counties are affected by this new rule, including many urban areas in the Eastern United States.

The Federal EPA has identified SO₂ and NO_x emissions as precursors to the formation of fine particulate matter. NO_x emissions are also identified as a precursor to the formation of ground-level ozone. As a result, requirements for future reductions in emissions of NO_x and SO₂ from the AEP System’s generating units are highly probable. In addition, the Federal EPA proposed a set of options for future mercury controls at coal-fired power plants.

Multi-emission control legislation is supported by the Bush Administration. This legislation would regulate NO_x, SO₂, and mercury emissions from electric generating plants. AEP supports enactment of a comprehensive, multi-emission legislation so that compliance planning can be coordinated and collateral emission reductions maximized. Management believes this legislation would establish stringent emission reduction targets and achievable compliance timetables utilizing a cost-effective nationwide cap and trade program. Management believes regulation or legislation will require the AEP System to substantially reduce SO_2, NO_x and mercury emissions over the next ten years.

Regulatory Emissions Reductions

In January 2004, the Federal EPA published two proposed rules that would collectively require reductions of approximately 70% in emissions of SO₂, NO_x and mercury from coal-fired electric generating units by 2015 (2018 for mercury). This initiative has two major components:

· The Federal EPA proposed a Clean Air Interstate Rule (CAIR) to reduce SO₂ and NO_x emissions across the eastern half of the United States (29 states and the District of Columbia) and make progress toward attainment of the fine particulate matter and ground-level ozone NAAQS. These reductions could also satisfy these states’ obligations to make reasonable progress towards the national visibility goal under the regional haze program.

· The Federal EPA proposed to regulate mercury emissions from coal-fired electric generating units.

The CAIR would require affected states to include, in their SIPs, a program to reduce NO_x and SO₂ emissions from coal-fired electric utility units. SO₂ and NO_x emissions would be reduced in two phases, which would be implemented through a cap-and-trade program. Regional SO₂ emissions would be reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional NO_x emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million tons by 2015. Rules to implement the SO₂ and NO_x trading programs were proposed in June 2004.

On April 15, 2004, the Federal EPA Administrator signed a proposed rule detailing how states should analyze and include “Best Available Retrofit” requirements for individual facilities in their SIPs to address regional haze. The guidance applies to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. The Federal EPA included an alternative “Best Available Retrofit” program based on emissions budgeting and trading programs. For generating units that are affected by the CAIR, described above, the Federal EPA proposed that participation in the trading program under the CAIR would satisfy any applicable “Best Available Retrofit” requirements. However, the guidance preserves the ability of a state to require site-specific installation of pollution control equipment through the SIP for purposes of abating regional haze.

To control and reduce mercury emissions, the Federal EPA published two alternative proposals. The first option requires the installation of MACT on a site-specific basis. Mercury emissions would be reduced from 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and the industry concurs, that there are no commercially available mercury control technologies in the marketplace today that can achieve the MACT standards for bituminous coals, but certain generating units have achieved comparable levels of mercury reduction by installing conventional SO₂ (scrubbers) and NO_x (SCR) emission reduction technologies. The proposed rule imposes significantly less stringent standards on generating plants that burn sub-bituminous coal or lignite. The proposed standards for sub-bituminous coals potentially could be met without installation of mercury control technologies.

The Federal EPA recommends, and AEP supports, a second mercury emission reduction option. The second option would permit mercury emission reductions to be achieved from existing sources through a national cap-and-trade approach. The cap-and-trade approach would include a two-phase mercury reduction program for coal-fired utilities. This approach would coordinate the reduction requirements for mercury with the SO₂ and NO_x reduction requirements imposed on the same sources under the CAIR. Coordination is significantly more cost-effective because technologies like scrubbers and SCRs which can be used to comply with the more stringent SO₂ and NO_x requirements, have also proven highly effective in reducing mercury emissions on certain coal-fired units that burn bituminous coal. The second option contemplates reducing mercury emissions from 48 million tons to 34 million tons by 2010 and to 15 million tons by 2018. A supplemental proposal including unit-specific allocations and a framework for the emissions budgeting and trading program preferred by the Federal EPA was published in the Federal Register in March 2004. We filed comments on both the initial proposal and the supplemental proposal in June 2004.

The Federal EPA’s proposals are the beginning of a lengthy rulemaking process, which will involve supplemental proposals on many details of the new regulatory programs, written comments and public hearings, issuance of final rules, and potential litigation. In addition, states have substantial discretion in developing their rules to implement cap-and-trade programs, and will have 18 months after publication of the notice of final rulemaking to submit their revised SIPs. As a result, the ultimate requirements may not be known for several years and may depart significantly from the original proposed rules described here.

While uncertainty remains as to whether future emission reduction requirements will result from new legislation or regulation, it is certain under either outcome that AEP subsidiaries will invest in additional conventional pollution control technology on a major portion of their coal-fired power plants. Finalization of new requirements for further SO₂, NO_x and/or mercury emission reductions will result in the installation of additional scrubbers, SCR systems and/or the installation of emerging technologies for mercury control. The cost of such facilities could have an adverse effect on future results of operations, cash flows and financial condition unless recovered from customers.

Estimated Air Quality Environmental Investments

Each of the current and possible future environmental compliance requirements discussed above will require significant additional investments, some of which are estimable. The proposed rules discussed above have not been adopted, will be subject to further revision, and may be the subject of a court challenge and further modifications.

All of management’s estimates are subject to significant uncertainties about the outcome of several interrelated assumptions and variables, including:

· Timing of implementation

· Required levels of reductions

· Allocation requirements of the new rules, and

· Selected compliance alternatives.

As a result, management cannot estimate compliance costs with certainty, and the actual costs to comply could differ significantly from the estimates discussed below.

All of the costs discussed below are incremental to the AEP subsidiaries’ current investment base and operating cost structure. Management intends to seek recovery of these expenditures for pollution control technologies, replacement generation and associated operating costs from customers through regulated rates (in regulated jurisdictions). Management believes market prices should allow recovery of these expenditures in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Estimated Investments for NO_x Compliance

Management estimates that AEP subsidiaries will make future investments of approximately $450 million to comply with the Federal EPA’s NO_x Rule, the TCEQ Rule and other final NO_x-related requirements. Approximately $380 million of these investments are expected to be expended during 2005-2007. As of December 31, 2004, the AEP System has invested approximately $1.3 billion to comply with various NO_x requirements. Estimated future compliance costs, investment amounts estimated for 2005-2007 and amounts spent by subsidiaries are as follows:

	Future Estimated Compliance Investment		Investment Amount Estimated for 2005 - 2007		Amount Spent
	(in millions)
AEGCo	$	-	$	-	$	17
APCo		47		42		425
CSPCo		24		7		87
I&M		-		-		22
KPCo		48		-		181
OPCo		319		319		496
SWEPCo		14		11		25

Estimated Investments for SO₂ Compliance

The AEP System is complying with Title IV SO₂ requirements by installing scrubbers, other controls and fuel switching at certain generating units. AEP subsidiaries also use SO₂ allowances that were:

· Received in the Federal EPA’s annual allowance allocation,

· Obtained through participation in the annual Federal allowance auction,

· Purchased in the market, and

· Obtained as bonus allowances for installing controls early.

Decreasing SO₂ allowance allocations, a diminishing SO₂ allowance bank, and increasing allowance prices in the market will require the installation of additional controls on certain generating units. AEP subsidiaries plan to install 3,500 MW of additional scrubbers to comply with our Title IV SO₂ obligations. In total, management estimates these additional capital costs to be approximately $1.2 billion with approximately $97 million invested during 2004 and the remainder will be expended during 2005-2007. The following table shows the estimated additional capital costs and amounts for 2005-2007 for additional scrubbers by subsidiary:

	Cost of Additional Scrubbers		Amount Estimated for 2005 - 2007
	(in millions)
APCo	$	442	$	442
OPCo		727		714
SWEPCo		19		19

Estimated Investments to Comply with Future Reduction Requirements

The AEP System’s planning assumptions for the levels and timing of emissions reductions parallel the reduction levels and implementation time periods stated in the proposed rules issued by the Federal EPA in January 2004. Management has also assumed that the Federal EPA will implement a mercury trading option and will design its proposed cap and trade mechanism for SO₂, NO_x and mercury emissions in a manner similar to existing cap and trade programs. Based on these assumptions, compliance would require additional capital investment of approximately $1.7 billion by 2010, the end of the first phase for each proposed rule. Management estimates that the subsidiaries will invest $1 billion of this amount through 2007.

	Estimated Compliance Investments		Amount Estimated for 2005 - 2007
	(in millions)
APCo	$	628	$	469
CSPCo		236		133
I&M		61		8
KPCo		383		49
OPCo		364		319
SWEPCo		54		18

Management also estimates that the subsidiaries would incur increases in variable operation and maintenance expenses of $150 million for the periods by 2010, due to the costs associated with the maintenance of additional control systems, disposal of scrubber by-products and the purchase of reagents.

If the Federal EPA’s preferred mercury trading option is not implemented, then any alternative mercury control program requiring adherence to MACT standards would have higher implementation costs that could be significant. Management cannot currently estimate the nature or amount of these costs. Furthermore, scrubber and SCR technologies could not be deployed at every bituminous-fired plant that the AEP System operates within the three-year compliance schedule provided under the proposed MACT rule. These MACT compliance costs, which management is not able to estimate, would be incremental to other cost estimates that are discussed above.

Between 2010 and 2020, the AEP System expects to incur additional costs for pollution control technology retrofits and investment of $1.6 billion. However, the post-2010 capital investment estimates are quite uncertain, reflecting the uncertain nature of future air emission regulatory requirements, technology performance and costs, new pollution control and generating technology developments, among other factors. Associated operation and maintenance expenses for the equipment will also increase during those years. Management cannot estimate these additional costs because of the uncertainties associated with the final control requirements and the associated compliance strategy, but these additional costs are expected to be significant.

New Source Review Litigation

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 Federal EPA and a number of states have alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities modified certain units at coal-fired generating plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints against AEP 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 the generating units over a 20-year period.

On June 18, 2004, the Federal EPA issued a Notice of Violation (NOV) in order to “perfect” its complaint in the pending litigation. The NOV expands the number of alleged “modifications” undertaken at the Amos, Cardinal, Conesville, Kammer, Muskingum River, Sporn and Tanners Creek plants during scheduled outages on these units from 1979 through the present. Approximately one-third of the allegations in the NOV are already contained in allegations made by the states or the special interest groups in the pending litigation. The Federal EPA filed a motion to amend its complaints and to expand the scope of the pending litigation. The AEP subsidiaries opposed that motion. In September 2004, the judge disallowed the addition of claims to the pending case. The judge also granted motions to dismiss a number of allegations in the original filing. Subsequently, eight Northeastern States filed a separate complaint containing the same allegations against the Conesville and Amos plants that the judge disallowed in the pending case. AEP subsidiaries filed an answer to the complaint in January 2005.

Management is unable to estimate the loss or range of loss related to the contingent liability for civil penalties under the CAA proceedings. Management is 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 the AEP subsidiaries do not prevail, any capital and operating costs of additional pollution control equipment that may be required, as well as any penalties imposed, would adversely affect future results of operations, cash flows and possibly financial condition unless such costs can be recovered from customers.

In September 2004, the Sierra Club filed a complaint under the citizen suit provisions of the CAA in the United States District Court for the Southern District of Ohio alleging that violations of the PSD and New Source Performance Standards requirements of the CAA and the opacity provisions of the Ohio SIP occurred at the Stuart Station, and seeking injunctive relief and civil penalties. Stuart Station is jointly-owned by CSPCo (26%) and two nonaffiliated utilities. The owners have filed a motion to dismiss portions of the complaint. The owners believe the allegations in the complaint are without merit, and intend to defend vigorously against this action. Management is unable to predict the timing of any future action by the special interest group or the effect of such actions on future operations or cash flows.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

On July 13, 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 SWEPCo's Welsh, Knox Lee, and Pirkey plants. This notice was prompted by allegations made by a terminated AEP employee. The allegations at the Welsh Plant concern compliance with emission limitations on particulate matter and carbon monoxide, compliance with a referenced design heat input value, and compliance with certain reporting requirements. The allegations at the Knox Lee Plant relate to the receipt of an off-specification fuel oil, and the allegations at Pirkey Plant relate to testing and reporting of volatile organic compound emissions.

On July 19, 2004, the 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. The summary includes allegations concerning compliance with certain recordkeeping and reporting requirements, compliance with a referenced design heat input value in the Welsh permit, compliance with a fuel sulfur content limit, and compliance with emission limits for sulfur dioxide.

On August 13, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the off-specification fuel oil deliveries at the Knox Lee Plant. On August 30, 2004, TCEQ issued a Notice of Enforcement to SWEPCo relating to the reporting of volatile organic compound emissions at the Pirkey Plant, but after investigation determined that further enforcement was not warranted and withdrew the notice on January 5, 2005.

SWEPCo has previously reported to the TCEQ, deviations related to the receipt of off-specification fuel at Knox Lee, the volatile organic compound emissions at Pirkey, and the referenced recordkeeping and reporting requirements and heat input value at Welsh. We have submitted additional responses to the Notice of Enforcement and the notice from the special interest groups. 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.

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically disposed of or treated in captive disposal facilities or are beneficially utilized. In addition, our generation plants and transmission and distribution facilities have used asbestos, PCBs and other hazardous and nonhazardous materials. AEP subsidiaries are currently incurring costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances at disposal sites and authorized the Federal EPA to administer the clean-up programs. As of year-end 2004, APCo, CSPCo, I&M and OPCo are each named by the Federal EPA as a Potentially Responsible Party (PRP) for one site. There are six additional sites for which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received information requests which could lead to PRP designation. OPCo, SWEPCo and TCC have also been named potentially liable at four sites under state law. Liability has been resolved for a number of sites with no significant effect on results of operations. In those instances where AEP subsidiaries have been named a PRP or defendant, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Unfortunately, Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.

While the potential liability for each Superfund site must be evaluated separately, several general statements can be made regarding potential future liability. Disposal of materials at a particular site is often unsubstantiated and the quantity of materials deposited at a site was small and often nonhazardous. Although superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. Therefore, present estimates do not anticipate material cleanup costs for identified sites for which AEP subsidiaries have been declared PRPs. If significant cleanup costs are attributed to any AEP subsidiary in the future under Superfund, its results of operations, cash flows and possibly financial condition would be adversely affected unless the costs can be included in its electricity prices.

Emergency Release Reporting

Superfund also requires immediate reporting to the Federal EPA for releases of hazardous substances to the environment above the identified reportable quantity (RQ). The Environmental Planning and Community Right-to-Know Act (EPCRA) requires immediate reporting of releases of hazardous substances which cross property boundaries of the releasing facility.

On July 27, 2004, the Federal EPA Region 5 issued an Administrative Complaint related to alleged failure of I&M to immediately report under Superfund and EPCRA a November 2002 release of sodium hypochlorite from the Cook Plant. The Federal EPA's Complaint seeks an immaterial amount of civil penalties. I&M has requested a hearing and raised several defenses to the claim, including federally permitted release exemption from reporting. Negotiations on the penalty amount are continuing.

On December 21, 2004, the Federal EPA notified OPCo of its intent to file a Civil Administrative Complaint, alleging one violation of Superfund reporting obligations and two violations of EPCRA for failure to timely report a June 2004 release of an RQ amount of ammonia from OPCo’s Gavin Plant SCR system. The Federal EPA indicated its intent to seek civil penalties. In February 2005, OPCo provided relevant information that the Federal EPA should consider in advance of any filing.

Global Climate Change

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 on November 12, 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. Ratification of the treaty by a majority of the countries’ legislative bodies is required for it to be enforceable. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries and is now in effect as of February 2005.

In August 2003, the Federal EPA issued a decision in response to a petition for rulemaking seeking reductions of CO₂ and other greenhouse gas emissions from mobile sources. The Federal EPA denied the petition and issued a memorandum stating that it does not have the authority under the CAA to regulate CO₂ or other greenhouse gas emissions that may affect global warming trends. The Circuit Court of Appeals for the District of Columbia is reviewing these actions.

AEP has been working with the Bush Administration on a voluntary program aimed at meeting the President’s goal of reducing the greenhouse gas intensity of the economy by 18% by 2012. For many years, AEP has been a leader in pursuing voluntary actions to control greenhouse gas emissions. AEP expanded its commitment in this area in 2002 by joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading program. AEP subsidiaries made a voluntary commitment to reduce or offset 18 million tons of CO₂ emissions during 2003-2006 as adjusted to reflect any changes in baseline during the commitment period.

Carbon Dioxide Public Nuisance Claims

On July 21, 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 and four other nonaffiliated governmental and investor-owned electric utility systems. That same day, a similar complaint was filed in the same court against the same defendants by the Natural Resources Defense Council on behalf of three special interest groups. The actions allege that carbon dioxide emissions from power generation facilities constitute a public nuisance under federal common law due to impacts associated with global warming, and seek 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. Management believes the actions are without merit and intends to defend vigorously against the claims.

Costs for Spent Nuclear Fuel and Decommissioning

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a significant future financial commitment to safely dispose of SNF and to decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of SNF and high-level radioactive waste. By law I&M and TCC participate in the DOE’s SNF disposal program which is described in the “SNF Disposal” section of Note 7. Since 1983, I&M has collected $333 million from customers for the disposal of nuclear fuel consumed at the Cook Plant. I&M deposited $118 million of these funds in external trust funds to provide for the future disposal of SNF and remitted $215 million to the DOE. TCC has collected and remitted to the DOE, $61 million for the future disposal of SNF since STP began operation in the late 1980s. Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel. However, in 1996, the DOE notified the companies that it would be unable to begin accepting SNF by the January 1998 deadline required by law. To date, the DOE has failed to comply with the requirements of the Nuclear Waste Policy Act.

As a result of DOE's failure to make sufficient progress toward a permanent repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and STPNOC on behalf of TCC and the other STP owners, along with a number of nonaffiliated utilities and states, filed suit in the D.C. Circuit Court requesting, among other things, that the D.C. Circuit Court order DOE to meet its obligations under the law. The D.C. Circuit Court ordered the parties to proceed with contractual remedies but declined to order DOE to begin accepting SNF for disposal. DOE estimates its planned site for the nuclear waste will not be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court of Federal Claims seeking damages in excess of $150 million due to the DOE's partial material breach of its unconditional contractual deadline to begin disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by other utilities. In August 2000, in an appeal of related cases involving other nonaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held that the delays clause of the standard contract between utilities and the DOE did not apply to DOE’s complete failure to perform its contract obligations, and that the utilities’ suits against DOE may continue in court. In January 2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of liability. The case continued on the issue of damages owed to I&M by the DOE. In May 2004, the U.S. Court of Federal Claims ruled against I&M and denied damages. In July 2004, I&M appealed this ruling to the U.S. Court of Appeals for the Federal Circuit. As long as the delay in the availability of a government-approved storage repository for SNF continues, the cost of both temporary and permanent storage of SNF and the cost of decommissioning will continue to increase.

The cost to decommission nuclear plants is affected by both NRC regulations and the delayed SNF disposal program. Studies completed in 2003 estimate the cost to decommission the Cook Plant ranges from $889 million to $1.1 billion in 2003 nondiscounted dollars. External trust funds have been established with amounts collected from customers to decommission the plant. At December 31, 2004, the total decommissioning trust fund balance for Cook Plant was $791 million, which includes earnings on the trust investments. In May 2004, an updated decommissioning study was completed for STP. The study estimates TCC’s share of the decommissioning costs of STP to be $344 million in nondiscounted 2004 dollars. Amounts collected from customers to decommission STP have been placed in an external trust. At December 31, 2004, the total decommissioning trust fund for TCC’s share of STP was $143 million, which includes earnings on the trust investments. TCC is in the process of selling its ownership interest in STP to two nonaffiliated companies, and upon completion of the sale it is anticipated that TCC will no longer be obligated for nuclear decommissioning liabilities associated with STP. Estimates from the decommissioning studies could continue to escalate due to the uncertainty in the SNF disposal program and the length of time that SNF may need to be stored at the plant site. I&M and TCC will work with regulators and customers to recover the remaining estimated costs of decommissioning Cook Plant and STP. However, future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.

Clean Water Act Regulation

On July 9, 2004, the Federal EPA published in the Federal Register a rule pursuant to the Clean Water Act that will require all large existing, once-through cooled power plants to meet certain performance standards to reduce the mortality of juvenile and adult fish or other larger organisms pinned against a plant’s cooling water intake screen. All plants must reduce fish mortality by 80% to 95%. A subset of these plants that are located on sensitive water bodies will be required to meet additional performance standards for reducing the number of smaller organisms passing through the water screens and the cooling system. These plants must reduce the rate of smaller organisms passing through the plant by 60% to 90%. Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and small rivers with large generating plants. These rules will result in additional capital and operation and maintenance expenses to ensure compliance. The estimated capital cost of compliance for AEP System facilities, based on the Federal EPA’s analysis in the rule, is $193 million. Any capital costs associated with compliance activities to meet the new performance standards would likely be incurred during the years 2008 through 2010. Management has not independently confirmed the accuracy of the Federal EPA’s estimate. The rule has provisions to limit compliance costs. Management may propose less costly site-specific performance criteria if compliance cost estimates are significantly greater than the Federal EPA’s estimates or greater than the environmental benefits. The rule also allows Management to propose mitigation (also called restoration measures) that is less costly and has equivalent or superior environmental benefits than meeting the criteria in whole or in part. Several states, electric utilities (including APCo) and environmental groups appealed certain aspects of the rule. We cannot predict the outcome of the appeals. The following table shows the investment amount per subsidiary.

	Estimated Compliance Investments
	(in millions)
APCo	$	21
CSPCo		19
I&M		118
OPCo		31

Other Environmental Concerns

Management performs 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, the AEP subsidiaries are managing other environmental concerns which are not believed to be material or potentially material at this time. If they become significant or if any new matters arise that could be material, they could have a material adverse effect on results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:

· it requires assumptions to be made that were uncertain at the time the estimate was made; and

· changes in the estimate or different estimates that could have been selected could have a material effect on our consolidated results of operations or financial condition.

Management has discussed the development and selection of its critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee has reviewed the disclosure relating to them.

Management believes that the current assumptions and other considerations used to estimate amounts reflected in our consolidated financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions.

The sections that follow present information about the Registrant Subsidiaries’ most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.

Regulatory Accounting

Nature of Estimates Required - The consolidated financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (I&M, KPCo, PSO and a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo) reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.

Regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) are recognized for the economic effects of regulation by matching the timing of expense recognition with the recovery of such expense in regulated revenues. Likewise, income is matched with the passage to customers through regulated revenues in the same accounting period.

Regulatory liabilities are also recorded for refunds, or probable refunds, to customers that have not yet been made.

Assumptions and Approach Used - When regulatory assets are probable of recovery through regulated rates, they are recorded as assets on the balance sheet. Regulatory assets are tested for probability of recovery whenever new events occur, for example, changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate of return earned on invested capital and the timing and amount of assets to be recovered through regulated rates. If it is determined that recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there will be no recovery through regulated rates.

Effect if Different Assumptions Used - A change in the above assumptions may result in a material impact on the results of operations. Refer to Note 5 of the Notes to Financial Statements of Registrant Subsidiaries for further detail related to regulatory assets and liabilities.

Revenue Recognition - Unbilled Revenues

Nature of Estimates Required - Revenues are recognized and recorded when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is also estimated. This estimate is reversed in the following month and actual revenue is recorded based on meter readings.

Unbilled revenues included in Revenue for the years ended December 31 were as follows:

	2004			2003			2002
	(in thousands)
TCC	$	(1,579	)	$	4,636		$	(19,023	)
TNC		(1,160	)		1,834			(1,775	)
APCo		18,206			1,876			3,890
CSPCo		283			(5,881	)		6,917
I&M		(2,942	)		10,722			9,329
KPCo		3,833			(448	)		708
OPCo		(2,793	)		(18,502	)		(346	)
PSO		2,789			984			4,008
SWEPCo		1,814			(6,996	)		3,637

Assumptions and Approach Used - The monthly estimate for unbilled revenues is calculated by operating company as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to the occurrence of problems in meter readings, meter drift and other anomalies, a separate monthly calculation determines factors that limit the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are then statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and lower limits.

In addition, an annual comparison to a load research estimate is performed for the East Companies. The annual load research study is an independent unbilled KWH estimate based on a sample of accounts. The unbilled estimate is also adjusted annually for significant differences from the load research estimate.

Effect if Different Assumptions Used - Significant fluctuations in energy demand for the unbilled period, weather impact, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1%.

Revenue Recognition - Accounting for Derivative Instruments

Nature of Estimates Required - Management considers fair value techniques, valuation adjustments related to credit and liquidity, and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.

Assumptions and Approach Used - APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based on exchange prices and broker quotes. If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data, and other assumptions. Fair value estimates based upon the best market information available is somewhat subjective in nature and involves uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing future bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments are based on estimated defaults by counterparties that are calculated using historical default probabilities for companies with similar credit ratings.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC evaluate the probability of the occurrence of the forecasted transaction within the specified time period as provided for in the original documentation related to hedge accounting.

Effect if Different Assumptions Used - There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts are ultimately settled.

The probability that hedged forecasted transactions will occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified in operating income.

Long-Lived Assets

Nature of Estimates Required - In accordance with the requirements of SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets are evaluated periodically for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable or the assets meet the held for sale criteria under SFAS 144. These events or circumstances may include the expected ability to recover additional investment in environmental compliance expenditures, the relative pricing of wholesale electricity by region, the anticipated demand and the cost of fuel. If the carrying amount is not recoverable, an impairment is recorded to the extent that the fair value of the asset is less than its book value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery was probable. For nonregulated assets, an impairment charge would be recorded as a charge against earnings.

Assumptions and Approach Use - The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales, or independent appraisals. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Effect if Different Assumptions Used - In connection with the periodic evaluation of long-lived assets in accordance with the requirements of SFAS 144, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. In cases of impairment as described in Note 10, the best estimate of fair value was made using valuation methods based on the most current information at that time. Certain Registrant Subsidiaries have been in the process of divesting certain noncore assets and their sales values can vary from the recorded fair value as described in Note 10. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including differences in subsequent market conditions, the level of bidder interest, timing and terms of the transactions and management’s analysis of the benefits of the transaction.

Pension and Other Postretirement Benefits

Nature of Estimates Required - APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC sponsor pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under SFAS 87, “Employers’ Accounting For Pensions” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”, respectively. See Note 11 of the Notes to Financial Statements of Registrant Subsidiaries for more information regarding costs and assumptions for employee retirement and postretirement benefits. The measurement of pension and postretirement obligations, costs and liabilities is dependent on a variety of assumptions used by actuaries and APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded.

Assumptions and Approach Used - The critical assumptions used in developing the required estimates include the following key factors:

· discount rate

· expected return on plan assets

· health care cost trend rates

· rate of compensation increases

Other assumptions, such as retirement, mortality, and turnover, are evaluated periodically and updated to reflect actual experience.

Effect if Different Assumptions Used - The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:

	Pension Plans						Other Postretirement Benefits Plans
	+0.5%			-0.5%			+0.5%			-0.5%
	(in millions)
Effect on December 31, 2004 Benefit Obligations:
Discount Rate	$	(175	)	$	182		$	(133	)	$	142
Salary Scale		11			(11	)		4			(4	)
Cash Balance Crediting Rate		(20	)		20			N/A			N/A
Health Care Trend Rate		N/A			N/A			129			(121	)
Expected Return on Assets		N/A			N/A			N/A			N/A
Effect on 2004 Periodic Cost:
Discount Rate		-			1			(11	)		11
Salary Scale		2			(2	)		1			(1	)
Cash Balance Crediting Rate		3			(3	)		N/A			N/A
Health Care Trend Rate		N/A			N/A			19			(18	)
Expected Return on Assets		(17	)		17			(5	)		5

New Accounting Pronouncements

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC implemented FASB Staff Position (FSP) FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” effective April 1, 2004, retroactive to January 1, 2004. Under FSP FAS 106-2, the current portion of the Medicare subsidy for employers who qualify for the tax-free subsidy is a reduction of ongoing FAS 106 cost, while the retroactive portion is an actuarial gain to be amortized over the average remaining service period of active employees, to the extent that the gain exceeds FAS 106’s 10 percent corridor.

In December 2004, the FASB issued SFAS 123R, “Share-Based Payment.” SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. We will implement SFAS 123R in the third quarter of 2005 using the modified prospective method. This method requires us to record compensation expense for all awards we grant after the time of adoption and to 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 will be based on the grant-date fair value of the equity award. A cumulative effect of a change in accounting principle is recorded for the effect of initially applying the statement. We do not expect implementation of SFAS 123R to materially affect our results of operations, cash flows or financial condition.

We implemented FIN 46R, “Consolidated of Variable Interest Entities,” effective March 31, 2004 with no material impact to our financial statements. FIN 46R is a revision to FIN 46 which interprets the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties.

Other Matters

Seasonality

The sale of electric power in AEP subsidiaries’ service territories is generally a seasonal business. In many parts of the country, demand for power peaks during the hot summer months, with market prices also peaking at that time. In other areas, power demand peaks during the winter. The pattern of this fluctuation may change due to the nature and location of the AEP System’s facilities and the terms of power contracts into which AEP enters. In addition, AEP subsidiaries have historically sold less power, and consequently earned less income, when weather conditions are milder. Unusually mild weather in the future could diminish results of operations and may impact cash flows and financial condition.