American Electric Power

2001 Annual Report

Audited Financial Statements and
Management's Discussion and Analysis

CONTENTS

Glossary of Terms
Selected Consolidated Financial Data
Management's Discussion and Analysis of Results of Operations and Financial Condition
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
Notes to Consolidated Financial Statements
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
Schedule of Consolidated Long-term Debt of Subsidiaries
Management's Responsibility
Independent Auditors' Report

Common Stock and Dividend Information

The quarterly high and low sales prices for AEP common stock and the cash dividends paid per share are shown in the following table:

AEP common stock is traded principally on the New York Stock Exchange. At December 31, 2001, AEP had approximately 150,000 shareholders of record.

GLOSSARY OF TERMS

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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA

The consolidated financial statements give retroactive effect to AEP's merger with CSW, which was accounted for as a pooling of interests.

*Including portion due within one year
**Based on AEP historical dividend rate.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

This discussion includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These forward-looking statements reflect assumptions, and involve a number of risks and uncertainties. Among the factors both foreign and domestic that could cause actual results to differ materially from forward-looking statements are: electric load and customer growth; abnormal weather conditions; available sources of and prices for coal and gas; availability of generating capacity; risks related to energy trading and construction under contract; the speed and degree to which competition is introduced to our power generation business; the structure and timing of a competitive market for electricity and its impact on prices; the ability to recover net regulatory assets, other stranded costs and implementation costs in connection with deregulation of generation in certain states; the timing of the implementation of AEP's restructuring plan, new legislation and government regulations; the ability to successfully control costs; the success of new business ventures; international developments affecting our foreign investments; the economic climate and growth in our service and trading territories both domestic and foreign; the ability of the Company to comply with and to successfully challenge new environmental regulations and to successfully litigate claims that the Company violated the Clean Air Act; inflationary trends; litigation concerning AEP's merger with CSW; changes in electricity and gas market prices and interest rates; fluctuations in foreign currency exchange rates, and other risks and unforeseen events.

American Electric Power Company, Inc. (AEP) is one of the largest investor owned electric public utility holding companies in the US. We provide generation, transmission and distribution service to over 4.9 million retail customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our electric utility operating companies. We market and trade electricity and natural gas in the US and Europe.

We have a significant presence throughout the domestic energy value chain. Our US electric assets include:

• 38,000 megawatts of generating capacity (the largest US generation portfolio with a significant cost advantage in the Midwest and Southwest markets);
• 38,000 miles of transmission lines and
• 186,000 miles of distribution lines

Our natural gas assets include:

• 128 Bcf of gas storage facilities
• 6,400 miles of gas pipelines in Louisiana and Texas which provide a basis for market knowledge.

With our coal and transportation assets we:

• control over 7,000 railcars
• control over 1,800 barges and 37 tug boats
• operate two coal handling terminals with 20 million tons of capacity.
• produce over 7 million tons of coal annually in the US.

AEP is one of the largest traders of electricity and natural gas in the US:

• over 576 million MWH of electricity trades in 2001
• over 3,800 billion cubic feet (Bcf) of gas trades in 2001

In addition we:

• consume 80 million tons of coal annually
• consume 310 Bcf of natural gas annually

AEP's focus is in the US but we also have smaller footprints in other parts of the world:

• a growing energy trading operation in Europe based in the UK.
• 4,000 megawatts of generating capacity in the United Kingdom which represents 16% of the UK's total generation capacity.

Other foreign investments include distribution operations in the U.K., Australia, and Brazil. We have additional generating facilities in China and Mexico. We also offer engineering and construction services worldwide.

Business Strategy

Our strategy is a balanced business model of regulated and unregulated businesses backed by assets, supported by enterprise-wide risk management and a strong balance sheet. We have been focused on the wholesale side of the business since it provides the greater growth opportunities. But, this is complemented by a robust regulated business that has a predictable earnings stream and cash flows. Strong risk management and a disciplined analysis of markets protected us from the California energy crisis and Enron's bankruptcy filing.

Our balanced business model is one where AEP integrates its assets, marketing, trading and market analysis and resources to create a superior knowledge about the commodity markets which keeps us a step ahead of our competition. Our power, gas, coal, and barging assets and operations provide us with market knowledge and customer connectivity giving us the ability to make informed marketing and trading decision and to customize our products and services.

AEP provides investors with a balanced portfolio since it has:

• a growing unregulated wholesale energy marketing and trading business
• predictable cash flow and earnings streams from the regulated electricity business, and
• a high dividend yield relative to today's low-interest rate environment.

We are currently in the process of restructuring our assets and operations to separate the regulated operations from the non-regulated operations.

We filed with the SEC for approval to form two separate legal holding company subsidiaries of AEP Co. Inc., the parent company. Approval is needed from the SEC under the PUHCA and the FERC to make these organizational changes. Certain state regulatory commissions have intervened in the FERC proceedings. We have reached a settlement with those state commissions and are awaiting the FERC's approval before the SEC will make a final ruling on our filing.

We are implementing a corporate separation restructuring plan to support our objective of unlocking shareholder value for our domestic businesses. Our plan provides for:

• transparency and clarity to investors,
• a simpler structure to conduct business, and to anticipate and monitor performance,
• compliance with states' restructuring laws promoting customer choice, and
• more efficient financing.

The new corporate structure will consist of a regulated holding company and an unregulated holding company. The regulated holding company's investments will be in integrated utilities and Ohio and Texas wires. The unregulated holding company's investments will be in Ohio and Texas generation, independent power producers, gas pipe line and storage, UK generation, barging, coal mining and marketing and trading.

The risks in our business are:

• Margin erosion on electric trading as markets mature,
• Diminished opportunities for significant gains as volatility declines,
• Retail price reductions mandated with the implementation of customer choice in Texas and Ohio,
• Movement towards re-regulation in California through market caps and other challenges to the continuation of deregulation of the retail electricity supply business in the U.S.,
• The continued negative impact of a slowly recovering economy.

Our business plan considers these risks and we believe that we can deliver earnings growth of 6-8% annually across the energy value chain through the disciplined integration of strategic assets and intellectual capital to generate these returns for our shareholders.

Our strategies to achieve our business plan are:

• Unregulated

• Disciplined approach to asset acquisition and disposition
• Value-driven asset optimization through the linkage of superior commercial, analytical and technical skills
• Broad participation across all energy markets with a disciplined and opportunistic allocation of risk capital
• Continued investment in both technology and process improvement to enhance our competitive advantage
• Continued expansion of intellectual capital through ongoing recruiting, performance-linked compensation and the development of a structure that promotes sound decision-making and innovation at all levels.

• Regulated

• Maintain moderate but steady earnings growth
• Maximize value of transmission assets and protect revenue stream through RTO/Alliance membership
• Continue process improvement to maintain distribution service quality while enhancing financial performance
• Optimize generation assets through enhanced availability of off-system sale
• Manage regulatory process to maximize retention of earnings improvement

Our significant accomplishments in 2001 were :

• Adding the following assets to integrate with and support our trading and marketing competitive advantage:

• 4,200 miles of gas pipeline, 118 Bcf gas storage and related gas marketing contracts
• 1,200 hopper barges and 30 tugboats
• 4,000 megawatts of coal-fired generation in England
• 160 megawatts of wind generation in Texas
• coal mining properties, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia

• Entering into new markets through the acquisition of existing contracts and hiring key staff including 57 employees from Enron's London based international coal trading group in December 2001 and Enron's Nordic energy trading group in January 2002. We now trade power and gas in the UK, France, Germany, and the Netherlands and coal throughout the world
• Adding other energy-related commodities to our power and gas portfolio i.e. coal, SO2 allowances, natural gas liquids (NGLs) and oil
• Disposing of the following assets that did not fit our strategy:

• 120 MWs of generation in Mexico,
• Above market coal mines in Ohio and West Virginia,
• A 50 % investment in Yorkshire, a U.K. electric supply and distribution company,
• An investment in a Chilean electric company
• Datapult, an energy information data and analysis tool.

In addition we sold 500 MWs of generating capacity in Texas under a FERC order that approved our merger with CSW.

Our divesture of non-strategic assets is somewhat limited by the pooling of interest accounting requirements applied to the merger of CSW and AEP in June 2000. We are presently evaluating certain telecommunications and foreign investments for possible disposal and have not yet decided whether to dispose of such investments. Disposal of investments determined to be non-strategic will be considered in accordance with the pooling of interests restrictions which end in June 2002. We are committed to continually evaluate the need to reallocate resources to areas with greater potential, to match investments with our strategy and to pare investments that do not produce sufficient return and shareholder value. Any investment dispositions could affect future results of operations.

Outlook for 2002

Growth in 2002 will be driven in part by our continued strategic development of wholesale products and geographies, as demonstrated in recent months by our move into global coal markets and Nordic energy. A full year of operation of assets acquired in 2001 – Houston Pipe Line, Quaker Coal, the MEMCO barge line and two power plants in the United Kingdom – will also contribute to growth in 2002 earnings.

Although we expect that the future outlook for results of operations is excellent there are contingencies and challenges. We discuss these matters in detail in the Notes to Consolidated Financial Statements and below in this Management Discussion and Analysis. We intend to work diligently to resolve these matters by finding workable solutions that balance the interests of our customers, our employees and our shareholders.

As discussed above we expect to continue evaluating certain investments for possible disposal due to either their nonstrategic nature or limited future earnings potential for AEP. Any dispositions could result in gains or losses being recorded in our income statement.

Industry Restructuring

In 2000 California's deregulated electricity market suffered problems including high energy prices mainly due to short energy supplies and financial difficulties for retail distribution companies. This energy crisis has highlighted the importance of risk management and has contributed to certain state regulatory and legislative actions which have delayed the start of customer choice and the transition to competitive, market based pricing for retail electricity supply in some of the states in which AEP operates. Seven of the eleven state retail jurisdictions in which the AEP domestic electric utility companies operate have enacted restructuring legislation. In general, the legislation provides for a transition from cost-based regulation of bundled electric service to customer choice and market pricing for the supply of electricity. As legislative and regulatory proceedings evolved, six AEP electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in five of the seven states that have passed restructuring legislation have discontinued the application of SFAS 71 regulatory accounting for the generation business. The seven states in various stages of restructuring to transition power generation and supply to market based pricing are Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia. AEP has not discontinued its regulatory accounting for its subsidiaries doing business in Michigan and Oklahoma pending the effective implementation of the legislation. Restructuring legislation, the status of the transition plans and the status of the electric utility companies' accounting to comply with the changes in each of AEP's seven state regulatory jurisdictions affected by restructuring legislation is presented in the Note 7 of the Notes to Financial Statements.

RTO Formation

FERC Order No. 2000 and many of the settlement agreements with the FERC and state regulatory commissions to approve the AEP-CSW Merger have provisions for the transfer of functional control of our transmission system to an RTO. Certain AEP subsidiaries are participating in the formation of the Alliance RTO. Other subsidiaries are a member of ERCOT or SPP.

In 2001 the Alliance companies and MISO entered into a settlement addressing transmission pricing and other "seam" issues between the two RTOs. The FERC subsequently expressed its opinion that four large RTO regions serving the continental US would best support competition and reliability of electric service. Certain state regulatory commissions have taken exception to the FERC's RTO actions. Louisiana's commission ordered utilities it regulates, including SWEPCo, to show the advantage of large RTOs to their customers.

On December 19, 2001 the FERC approved the proposal of the Midwest ISO for a regional transmission organization and told the Alliance companies, which had submitted a separate RTO proposal, to explore joining the Midwest ISO organization. The FERC's order is intended to facilitate the establishment of a single RTO in the Midwest and to support the establishment of viable, for-profit transmission companies under an RTO umbrella and concluded that the RTO proposed by Alliance companies lacks sufficient scope to exist as a stand-alone RTO and thus directed the Alliance companies to explore how their business plan can be accommodated within the Midwest ISO.

Management is unable to predict the outcome of these transmission regulatory actions and proceedings or their impact on the timing and operation of RTOs, AEP's transmission operations or future results of operations and cash flows.

RESULTS OF OPERATIONS

In 2001 AEP's principal operating business segments and their major activities were:

• Wholesale:

• Generation of electricity for sale to retail and wholesale customers
• Gas pipeline and storage services
• Marketing and trading of electricity, gas and coal
• Coal mining, bulk commodity barging operations and other energy supply related business.

• Energy Delivery

• Domestic electricity transmission,
• Domestic electricity distribution

• Other Investments

• Foreign electric distribution and supply investments,
• Telecommunication services.

Net Income

Net income increased to $971 million or $3.01 per share from $267 million or $0.83 per share. The increase of $704 million or $2.18 per share was due to the growth of AEP's wholesale marketing and trading business, increased revenues and the controlling of our operating and maintenance costs in the energy delivery business, and declining capital costs. Also contributing to the earnings improvement in 2001 was the effect of 2000 charges for a disallowance of COLI-related tax deductions, expenses of the merger with CSW, write-offs related to non-regulated investments and restart costs of the Cook Nuclear Plant. The favorable effect on comparative net income of these 2000 charges was offset in part by current year losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.

The decline in net income to $267 million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999 was primarily due to the 2000 charges described above and an extraordinary losses from the discontinuance of regulatory accounting for generation in certain states.

A strong performance in the first nine months of 2001 was partially offset by unfavorable operating conditions in the fourth quarter. Extremely mild November and December weather combined with weak economic conditions in the fourth quarter, reduced retail energy sales and wholesale margins. Heating degree days in the fourth quarter were down 33% from the same period in 2000. Although the fourth quarter was disappointing, 2001 net income before extraordinary items and cumulative effect of accounting change reached the $1 billion mark.

Our wholesale business continues to perform well despite a slowing economy that reduced both wholesale energy margins and energy use by industrial customers. Our wholesale business, which includes generation, retail and wholesale sales of power and natural gas and trading of power and natural gas and natural gas pipeline and storage services, contributed to the earnings increase by successfully returning the Cook Plant to service in 2000 and by growing AEP's wholesale business.

Our energy delivery business, which consists of domestic electricity transmission and distribution services, contributed to the increase in earnings by controlling operating and maintenance expenses and by increasing revenues.

Capital costs decreased due primarily to interest paid to the IRS in 2000 on a COLI deduction disallowance and declining short-term market interest rate conditions.

Critical Accounting Policies

Revenue Recognition – Traditional Electricity Supply and Delivery Activities - As the owner of cost-based rate-regulated electric public utility companies, AEP Co., Inc.'s consolidated financial statements recognize revenues on an accrual basis for traditional electricity supply sales and for electricity transmission and distribution delivery services. These revenues are recognized in our income statement when the energy is delivered to the customer and include unbilled as well as billed amounts. In general, expenses are recorded when incurred. As a result of our cost based rate regulated operations, our 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. 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 in the same accounting period regulated expenses with their recovery through regulated revenues.

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 a regulatory commission order or passage of new legislation. If we determine that recovery of a regulatory asset is no longer probable, we write off that regulatory asset as a charge against net income. A write off of regulatory assets may also reduce future cash flows since there may be no recovery through regulated rates.

We discontinued application of SFAS 71 for the generation portion of our business in Ohio for OPCo and CSPCo in September 2000, in Virginia and West Virginia for APCo in June 2000, in Texas for CPL, WTU, and SWEPCo in September 1999 and in Arkansas for SWEPCo in September 1999 in recognition of the passage of legislation to transition to customer choice and market pricing for the supply of electricity. We recorded extraordinary losses when we discontinued the application of SFAS 71. See Note 2, "Extraordinary Items and Cumulative Effect" for additional information.

Wholesale Energy Marketing and Trading Activities - We engage in non-regulated wholesale electricity and natural gas marketing and trading transactions (trading activities). Trading activities involve the purchase and sale of energy under forward contracts at fixed and variable prices and buying and selling financial energy contracts which includes exchange futures and options and over-the-counter options and swaps. Although trading contracts are generally short-term, there are also long-term trading contracts. We recognize revenues from trading activities generally based on changes in the fair value of energy trading contracts.

Recording the net change in the fair value of trading contracts as revenues prior to settlement is commonly referred to as mark-to-market (MTM) accounting. It represents the change in the unrealized gain or loss throughout the contract's term. When the contract actually settles, that is, the energy is actually delivered in a sale or received in a purchase or the parties agree to forego delivery and receipt and net settle in cash, the unrealized gain or loss is reversed out of revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase. Therefore, over the term of the trading contracts an unrealized gain or loss is recognized as the contract's market value changes. When the contract settles the total gain or loss is realized in cash but only the difference between the accumulated unrealized net gains or losses recorded in prior months and the cash proceeds is recognized. Unrealized mark-to-market gains and losses are included in the Balance Sheet as energy trading and derivative contract assets or liabilities as appropriate.

The majority of our trading activities represent physical forward electricity and gas contracts that are typically settled by entering into offsetting contracts. An example of our trading activities is when, in January, we enter into a forward sales contract to deliver electricity or gas in July. At the end of each month until the contract settles in July, we would record any difference between the contract price and the market price as an unrealized gain or loss in revenues. In July when the contract settles, we would realize the gain or loss in cash and reverse to revenues the previously recorded unrealized gain or loss. Prior to settlement, the change in the fair value of physical forward sale and purchase contracts is included in revenues on a net basis. Upon settlement of a forward trading contract, the amount realized is included in revenues for a sales contract and realized costs are included in purchased energy expense for a purchase contract with the prior change in unrealized fair value reversed in revenues.

Continuing with the above example, assume that later in January or sometime in February through July we enter into an offsetting forward contract to buy electricity or gas in July. If we do nothing else with these contracts until settlement in July and if the commodity type, volumes, delivery point, schedule and other key terms match then the difference between the sale price and the purchase price represents a fixed value to be realized when the contracts settle in July. If the purchase contract is perfectly matched with the sales contract, we have effectively fixed the profit or loss; specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting for these contracts will have no further impact on operating results but has an offsetting and equal effect on trading contract assets and liabilities. Of course we could also do similar transactions but enter into a purchase contract prior to entering into a sales contract. If the sale and purchase contracts do not match exactly as to commodity type, volumes, delivery point, schedule and other key terms, then there could be continuing mark-to-market effects on revenues from recording additional changes in fair values using mark-to-market accounting.

Trading of electricity and gas options, futures and swaps, represents financial transactions with unrealized gains and losses from changes in fair values reported net in revenues until the contracts settle. When these contracts settle, we record the net proceeds in revenues and reverse to revenues the prior unrealized gain or loss.

The fair value of open short-term trading contracts are based on exchange prices and broker quotes. We mark-to-market open long-term trading contracts based mainly on Company-developed valuation models. These models 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 reserves to adjust for credit risk and liquidity risk. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due AEP. 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 trading contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, energy markets, especially electricity markets, are imperfect and volatile and unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and when contracts settle. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices do not correlate with the Company-developed price models.

We also mark to market derivatives that are not trading contracts in accordance with generally accepted accounting principles. Derivatives are contracts whose value is derived from the market value of an underlying commodity.

Our revenues of $61 billion for 2001 included $257 million of unrealized net gains from marking to market open trading and derivative contracts. AEP's net revenues, (revenues less fuel and energy purchases) excluding mark-to-market revenues totaled $8.3 billion and were realized during 2001. Unrealized net mark-to-market revenues are only 3% of total net revenues. A significant portion of the net unrealized revenues from marking to market trading contracts and derivatives included in our balance sheet at December 31, 2001 as energy trading and derivative contract assets and liabilities, will be realized in 2002.

We defer as regulatory assets or liabilities the effect on net income of marking to market open electricity trading contracts in our regulated jurisdictions since these transactions are included in cost of service on a settlement basis for ratemaking purposes. Changes in mark-to-market valuations impact net income in our non-regulated business.

Volatility in energy commodities markets affects the fair values of all of our open trading and derivative contracts exposing AEP to market risk causing our results of operations to be more volatile. See "Market Risks" section below for a discussion of the policies and procedures AEP uses to manage its exposure to market and other risks from trading activities.

Revenues

Our revenues have increased significantly from the marketing and trading of electricity and natural gas. The level of electricity trading transactions tends to fluctuate due to the highly competitive nature of the short-term (spot) energy market and other factors, such as affiliated and unaffiliated generating plant availability, weather conditions and the economy. The FERC's introduction of a greater degree of competition into the wholesale energy market, has had a major effect on the volume of wholesale power marketing and trading especially in the short-term market.

AEP's total revenues increased 66.9% in 2001 and 48.3% in 2000. The following table shows the components of revenues in millions.

*Certain revenues in Wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business.

The $25 billion increase in 2001 revenues was due to substantial increases in electric and gas trading volumes. The increase in sales of purchased power and purchased gas during the past two years reflect AEP's intention to be a leading national wholesale energy merchant. Wholesale natural gas trading volume for 2001 was 3,874 Bcf, a 178% increase from 2000 volume of 1,391 Bcf. Electric trading volume increased 48% to 576 million MWH. We have invested in resources required to optimize our assets and emerge as a leader in the industry. The maturing of the Intercontinental Exchange, the development of proprietary tools, and the increased staffing of energy traders have faciliated increased power and gas sales. Our June 2001 purchase of Houston Pipe Line enhanced our gas trading and marketing operation. Although we will trade and market only when we believe profitable opportunites exist, we expect the increased level of activity to continue.

While wholesale marketing and trading volumes rose, kilowatthour sales to industrial customers decreased by 5% in 2001. This decrease was due to the economic recession. In the fourth quarter, sales to residential, commercial and wholesale customers declined 9%. The recession reduced demand and wholesale prices especially in the fourth quarter.

While margins available from selling power that the company generates generally are higher than from selling purchased power, such sales are limited by the amount of generating assets owned. Furthermore, the profit available from simply selling excess generation is reduced by the inherent market transparency of such sales. The coordinated sales of excess generation in conjunction with trading and marketing activity optimizes assets, mitigates risk, and increases overall profit.

The $12 billion increase in 2000 revenues was primarily due to a 27% increase in wholesale electricity trading volume and increased retail fuel revenues as a result of higher gas prices used to generate electricity. The reduction in industrial revenues in 2000 is attributable to the expiration of a long-term contract on December 31, 1999. The significant increase in 2000 electricity trading volume, which accounted for a 66% increase in electricity trading revenues, resulted from:

• efforts to grow AEP's energy marketing and trading operations,
• favorable market conditions, and
• the availability of additional generation

Generation availability improved due to the return to service of one of the Cook Plant nuclear units in June 2000 and to improved outage management. The second Cook Plant unit which returned to service in December 2000 did not have a significant impact on 2000 revenues. Gas revenues increased in 2000 due to increased natural gas and gas liquid product prices.

Operating Expenses Increase

Changes in the components of operating expenses were as follows:

Our fuel and purchased energy expense in 2001 increased 84% due to increased trading volume and an increase in nuclear generation cost. The return to service of the Cook Plant's two nuclear generating units in June 2000 and December 2000 accounted for the increase in nuclear generation costs.

Fuel and purchased energy expense increased 67% in 2000 due to increased trading volume and a significant increase in the cost of natural gas used for generation. Natural gas usage for generation declined 5% while the cost of natural gas consumed rose 60%. Net income was not impacted by this significant cost increase due to the operation of fuel recovery rate mechanisms. These fuel recovery rate mechanisms generally provide for the deferral of fuel costs above the amounts included in existing rates or the accrual of revenues for fuel costs not yet recovered. Upon regulatory commission review and approval of the unrecovered fuel costs, the accrued or deferred amounts are billed to customers. With the introduction of customer choice of electricity supplier and a transition to market-based generation rates, the protection offered by fuel recovery mechanisms against changes in fuel costs was eliminated in Ohio effective January 1, 2001 and in the ERCOT area of Texas effective January 1, 2002. As a result, AEP's exposure to the risk of fuel price increases that could adversely affect future results of operations and cash flows is increasing. See Note 1 for applicability of fuel recovery mechanisms by jurisdiction.

Maintenance and other operation expense rose in 2001 mainly as a result of additional traders' incentive compensation and accruals for severance costs related to corporate restructuring.

The increase in maintenance and other operation expense in 2000 was mainly due to increased expenditures to prepare the Cook Plant nuclear units for restart following an extended NRC monitored outage and increased usage and prices of emissions allowances. The increase in Cook Plant restart costs resulted from the effect of deferring restart costs in 1999 and an increase in the restart expenditure level in 2000. Cook Plant began its extended outage in September 1997 when both nuclear generating units were shut down because of questions regarding the operability of certain safety systems. In 1999 a portion of incremental restart expenses were deferred in accordance with IURC and MPSC settlement agreements which resolved all jurisdictional rate-related issues related to the Cook Plant's extended outage. With NRC approval Unit 2 returned to service in June and achieved full power operation on July 5, 2000 and Unit 1 returned to service in December and achieved full power operation on January 3, 2001. The increase in emission allowance usage and prices resulted from the stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments, which became effective on January 1, 2000.

With the consummation of the merger with CSW, certain deferred merger costs were expensed in 2000. The merger costs charged to expense included transaction and transition costs not allocable to and recoverable from ratepayers under regulatory commission approved settlement agreements to share net merger savings. As expected merger costs declined in 2001 after the merger was consummated.

Depreciation and amortization expense increased in 2001 primarily as a result of the commencement of amortization of transition generation regulatory assets in the Ohio, Virginia and West Virginia jurisdictions due to passage of restructuring legislation, the new businesses acquired in 2001 and additional investments in property, plant and equipment.

Interest, Preferred Stock Dividends, Minority Interest

Interest expense deceased 15% in 2001 due to the effect of interest paid the IRS on a COLI deduction disallowance in 2000 and lower average outstanding short-term debt balances and a decrease in average short-term interest rates.

In 2001 we issued a preferred member interest to finance the acquisition of HPL and paid a preferred return of $13 million to the preferred member interest.

In 2000 interest increased by 17% due to additional interest expense from the ruling disallowing COLI tax deductions and AEP's effort to maintain flexibility for corporate separation by issuing short-term debt at flexible rates. The use of fixed interest rate swaps has been employed to mitigate the risk from floating interest rates.

Other Income

Other income increased $166 million in 2001. This increase was primarily caused by the sale in March 2001 of Frontera, a generating plant required to be divested under a FERC approved merger settlement agreement, which produced a pretax $73 million gain and the effect from the December 2000 impairment writedown of $43 million to reflect the pending sale of AEP's Yorkshire investment.

Other income decreased $66 million in 2000 primarily due to a loss in equity earnings from the 2000 write-down of the Yorkshire investment and losses from certain non-regulated subsidiaries accounted for on an equity basis. Other expenses increased in 2000 mainly from a charge for the discontinuance of an electric storage water heater demand side management program of the regulated business.

Income Taxes

Although pre-tax book income increased considerably, income taxes decreased due to the effect of recording in 2000 prior year federal income taxes as a result of the disallowance of COLI interest deductions by the IRS and nondeductible merger related costs in 2000.

Income taxes increased in 2000 over 1999 levels primarily due to the disallowance of the COLI interest deductions and the nondeductible merger related costs discussed above.

Extraordinary Losses and Cumulative Effect

In 2001 we recorded an extraordinary loss of $48 million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in 2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in the after tax extraordinary loss of $35 million.

New accounting rules that became effective in 2001 regarding accounting for derivatives required us to mark to market certain fuel supply contracts that qualify as financial derivatives. The effect of initially adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of tax, which is reported as a cumulative effect of accounting change.

FINANCIAL CONDITION

We measure the financial condition of the Company by the strength of its balance sheet, the liquidity provided by its cash flows and earnings.

Balance sheet capitalization ratios and cash flow ratios are principal determinants of the Company's credit quality.

Year-end ratings of the Company's subsidiaries' first mortgage bonds are listed in the following table:

The ratings at the end of the year for senior unsecured debt issued by the Company's subsidiaries are listed in the following table:

* The rating is for a series of senior notes issued with a Support Agreement from AEP.

The ratings are presently stable. The parent company's commercial paper program has short-term ratings of A2 and P2 by Moody's and Standard and Poor's, respectively.

AEP's common equity to total capitalization declined to 33% in 2001 from 34% in 2000. Total capitalization includes long-term debt due within one year, minority interests and short-term debt. Preferred stock at 1% remained unchanged. Long-term debt increased from 47% to 50% while short-term debt decreased from 18% to 13% and minority interest in finance subsidiary increased to 3%. In 2001 and 2000, the Company did not issue any shares of common stock to meet the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan.

We plan to strengthen the Company's balance sheet in 2002 by issuing common stock and mandatory convertible preferred stock and using the proceeds from asset sales to reduce debt. The issuance of common stock has the potential to dilute future earnings per share but will enhance the equity to capitalization ratio.

Rating agencies have become more focused in their evaluation of credit quality as a result of the Enron bankruptcy. They are focusing especially on the composition of the balance sheet (off-balance sheet leases, debt and special purpose financing structures), the cash liquidity profile and the impact of credit quality downgrades on financing transactions. We have worked closely with the agencies to provide them with all the information they need, but we are unable to predict what actions, if any, they may take regarding the Company's current ratings.

During 2001 cash flow from operations was $2.9 billion, including $971 million from net income and $1.5 billion from depreciation, amortization and deferred taxes. Capital expenditures including acquisitions were $4 billion and dividends on common stock were $773 million. Cash from operations less dividends on common stock financed 52% of capital expenditures.

During 2001, the proceeds of the $1.25 billion global notes issuance and proceeds from the sale of a UK distribution company and two generating plants provided cash to purchase assets, fund construction, retire debt and pay dividends. Major construction expenditures include amounts for a wind generating facility and emission control technology on several coal-fired generating units (see discussion in Note 8). Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coa