ML022890481

Annual Financial Reports for South Texas Project Electric Generating Station, Highlights of 2001 - Page E-17

ML022890481
Person / Time
Site:	South Texas
Issue date:	10/01/2002
From:	George Wilson South Texas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
-RFPFR, 31497337, G20, NOC-AE-02001413
Download: ML022890481 (117)

Text

pil not ensure success in toaays compeuxive environmer to respond better aand faster to changes in market condi nd 'to seizeb opportunities. We w ill use our strength and and increase shareholder value-.

iny it was 1O,-or *even'twoyears ago. We invite you to r rselves, andwho we aspire to be, on page 13'

• rward-looking statements within the meaning of Section 21E of the Securitn

-looking statements reflect assumptions, and involve a number of risks an othfoeiin and domestic, thfatco6fd cause actual results to differ mai rare:! z a

and customerltrowthr abnormal weather condior gei and as. avalablý y

.. t.fg enereting capacity, nsks related to energy tradi d'espeed aind degree to which comipetition is intro`ducd oiour power geni ngi oeciompetitive market forele'iri~c'ity ad its impact on pie;teai her stranded costs and implementation costs in connecs'on ithdereguati mimgof the implementation of AEP's restructuring plan.'new legislation and ccessfully control costso the success of new "usinesi ventures; initefiot6 Investsents; th economic chimate and gro tn ourservice and tradin te abitl of thecoopmnply

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successfully litigate claims that the 'company violated the Clean Air Act gAEP's merger with CSW; changes in electncity and gas market prices Scurrency exchange rates and other risks and unforeseen events, proud sponsor of Cirque du'Soleil 2002 Not Amercn Tour qw teauei 9 rqeSo

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prudent accounting, financial disclosure and risk management practices to the business. We evaluate these practices on an ongoing basis to ensure our financial integrity and minimize adverse effects on our business.

Last October we hosted a meeting for investors and analysts A Day in the Life of an AEP Energy Merchant-at our Columbus headquarters. For many attendees, it was their first air travel since September 11th. For us, it was the firsttime our whole sale business leaders met with the financial communityto talk about the breadth and depth of our energy marketing opera tions and the impressive assets that support them.

We wanted our guests to see firsthand how we have linked entrepreneurial talent, our technical and operational prowess and the strength of our assets, which include:

• More than 42,000 megawatts of worldwide electric generating capacity; including the largest generation tricity volume. Our domestic wholesale natural gas volume last year was 3,874 billion cubic feet, a 178 percent increase from 2000, and our electricity volume rose 48 percentto 576 million megawatt-hours.

2001 performance Our 2001 ongoing earnings of $3 38 per share represented a 25 percent increase over 2000. Earnings as reported totaled

$3 01 per share, reflecting - among other items - costs associated with the completion of AEP's merger with Central and South West Corp. and write-off of Enron obligations related to our purchase of Houston Pipe Line.

Cook Nuclear Plant added 61 cents per share to earnings over its 2000 contribution. Cook has been a very solid performer since returning to service in 2000, as expected, and has exceeded its capacity factor goals for 2001 Our~;'

tihlcnrle ikmngmn r~esshv contributed toor~track rcbird~of~consistentf.te~d.etun' fleet in America,

• 128 billion cubic feet of gas storage,

• 6,400 miles of natural gas pipeline,

• More than 7,000 rail cars,

• 1,800 barges and 37 tug boats, making us the nation's fourth-largest inland barge company, and

• The capability of producing 10 million tons of coal annually.

The benefits of this unique integration of resources are reflected in our 2001 results. The company's wholesale electricity and natural gas marketing activities contributed $968 million in gross margins in 2001, an increase of $290 million over 2000.

Cash realized during 2001 accounted for approximately 73 percent of that total, and we expect to receive more than half the balance this year.

In addition, AEP's nationwide ranking in natural gas volume rose dramatically last year and we remained a leader in elec-K We are seeking a 20-year extension of the two Cook units' operating licenses, which expire in 2014 and 2017.

Our stock price fell 6 4 percent from year-end 2000 to year-end 2001 and our total shareholder return (stock price plus the value of cash dividends) for 2001 was down 1 2 percent, compared with 54 9 percent growth in total return the prior year. But we performed better than the electric utility sector, which was down 8 2 percent the Standard & Poor's 500 Index, down 11.9 percent; and the NASDAQ, down 20 8 percent. AEP last year ranked 10th in total return among the 26 companies in the S&P Electric Utilities Index, up from 15th at the close of 2000.

Last year marked the first full year since completion of the merger with CSW We met our 2001 net merger savings target and are on track to meet our overall savings goal for post merger initiatives of $2 billion plus another $1 billion saved through process improvements.

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Priorities: credit quality, risk management Credit quality has always been a cornerstone of AEP's financial strength. We will strive to maintain our overall credit rating of A-/Baal by reducing debt, ensuring strong cash flows, closely monitoring risks and potential liabilities and maintaining liquidity Our tightly controlled risk management processes have contributed to our track record of consistent, steady returns In our wholesale marketing business, trading desk managers have prescribed risk limits and several independent risk over sight committees monitor overall activity.

Last spring we created the position of chief risk officer end appointed Scott Smith to take on that role. Scott brings years of senior-level risk management experience with various corporate and government entities to AER. He and his team are working to ensure that AEP makes informed and prudent risk management decisions around financial, strategic and operational matters.

Benefits of corporate separation A year ago, we predicted that the legal and functional separation of our regulated and unregulated businesses would be facilitated by industry deregulation. While progress on deregulation has slowed, due in partto concerns triggered by California's energy crisis, I am confident that we will complete our corporate separation soon.

Among the 11 states where AEP operates, only Ohio, Texas,

.Virginia and Michigan have implemented deregulation legislation Our unregulated generation capacity represents nearly half our domestic generation portfolio of more than 38,000 megawatts. We continue to support deregulation plans that offer benefits to all A

utility customers, shareholders and the industry overall Corporate separation will lead to the creation of two wholly owned subsidiaries, one containing AEP's unregulated businesses and the other housing our regulated businesses. The separation makes strategic sense for the company and its constituents It will allow AEP to comply with restructuring legislation in Ohio and Texas and better meet the wide-ranging needs of our various customer segments. It will also unlock shareholder value by helping investors more clearly assess each business, permit more efficient financing, and pave the way for future reorgani zation options We are working closely with the rating agencies to design appropriate capital structures to help us meet our goals, and we pledge to maintain our credit quality and our commitments to existing debtholders throughout the corporate separation process.

Extracting value along the energy chain AEP's wholesale business -which includes our generation and related assets and associated marketing activities coptributed $2.40 per share to ongoing earnings in 2001 before capital costs, up from $1.93 in 2000 This reflects Cook's return to service and the fast growth of our wholesale gas business Our wholesale strategy is simple. We are committed to extracting value all along the "energy chain," which starts with procuring, storing and transporting fuel and progresses to generating power, marketing energy and managing risk for our customers. Our wholesale acquisitions over the pastyear show the robust activity along this chain Our acquisition of Houston Pipe Line from

,Enron last June immediately gave us new information about the natural gas industry and expanded our gas business, which we launched in 1998 with the acquisition of Louisiana Intrastate Gas. Our gas assets

,and the market understanding they give us have helped catapult AEP nearly to the top rung in wholesale natural gas volume HPL's Bammel Gas Storage Facility, one of North K

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America's largest storage fields, gives us a competitive edge by allowing our marketers to buy large volumes at low prices and store until selling when prices are high In November we acquired MEMCO Barge Line, greatly expanding our transportation resources and, again, providing information to help maximize our merchant operations' effec tiveness In addition to transporting coal for our own plants, AEP barges move a wide variety of commodities for many other customers. We expect our fleet will move some 50 million tons of dry bulk commodities annually along the Ohio and lower Mississippi rivers and their tributaries, and along the Gulf Coast AEP sold its affiliate mining operations in Ohio and West Virginia last summer because they had become too costly to maintain. However, several months later we purchased the coal mining operations and associated facilities and reserves of Quaker Coal Co We were able to obtain these assets at a very attractive price through Quaker's bankruptcy reorganiza tion proceedings, and we are confident we'll be able to operate them at lower cost As you know, AEP has many decades of experience in the coal business Coal remains a critical asset for us, representing roughly 68 percent of our generation Atthe end of 2001 we completed the purchase of 4,000 megawatts of coal-fired generation in the United Kingdom Waiting to acquire the right properties at the right price has paid off. We paid approximately $200 per kilowatt for the Fiddler's Ferry and Ferrybridge generating stations, compared with more than $500 per kilowatt paid by the prior owner in 1999 These new AEP assets will link to our London-based wholesale trading and marketing organization, paralleling the relationship between our U S merchant organization and domestic generating and gas pipeline assets.

Another important transaction in December 2001 was the acquisition of Enron's international coal marketing operation, also based in London. The transaction included marketing offices and a 22-member staff with proven track records in the UK, Germany, Australia and China, and contracts in Europe, Australia, Africa and South America This January we hired 35 former employees of Enron Nordic Energy and assumed operation of existing energy marketing offices in Oslo and Stockholm This gives AEP ready-made capability for electricity and weather derivative trading, origina tion and portfolio management in five European nations where we didn't have a presence previously Our European operations now include power marketing in eight nations, natural gas marketing in the UK and gas and coal marketing throughout northwestern Europe Strong, agile, asset-backed and far-reaching -that's AEP's wholesale business The wholesale generation advantage We are recruiting the best and brightest for our wholesale marketing team and our plant operators continue to be reward ed for thinking like business people Our goal isto make sure information about plant availability and expected demand flows freely between the generating plant floor and the trading floor to permit decisive actions that ensure system reliability and optimize plant economics.

For example, at AEP's Mitchell Plant in West Virginia last November, plant operators applied keen technical knowledge and ingenuity to returning a generating unit to service several days earlier than projected This prompt action added about

$900,000 to AEP's bottom line w

In recent years, we have taken a contrarian approach to building new generating capacity.

We don't believe investing in new plants is the best use of investor capital Instead, we look for ways to participate in merchant plant development in specific markets or circum stances where we can earn adequate returns Some projects give us access to the excess megawatts not required by our business partners without having to invest our capital. We can sell this generation in the wholesale market just as we would if we owned the physical assets. The cogeneration projects that AEP Pro Serv, Inc, is developing for such cus tomers as Dow Chemical (900 megawatts) and Buckeye Power (510 megawatts) offer these benefits AEP Pro Serv provides engineering, environmental, maintenance and construction management services to external customers t,-

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• In 7hfact, AEP has become oneof the-largest wind generators in the nation.

AEP also is growing megawatts at reduced cost by repowerng older generating units, such as our 40-year-old, gas-fired Northeastern Station in Oologah, Oklahoma. By adding two gas combustion turbines and two heat-recovery steam generators, we were able to increase Northeastern's capacity from 160 megawatts to 475 megawatts The project was completed last fall at a cost of $135 million, or $428 per kilowatt.

The cost of building new gas-fired combined cycle capacity is $500 to $600 per kilowatt Natural gas fuels approximately 22 percent of C AEP's generating fleet Growth in renewable energy We don't expect our fuel mix to change appreciably, but one area that saw significant growth this year is our renewables generation.

2 In fact, AEP has become one of the largest wind generators in the nation for two more 1,300-megawatt units this year. Another five generating units have been approved for SCR installation.

All told, compliance with nitrogen oxide emission standards could cost the company an estimated $1 6 billion in capital expenditures Value creation in the wvires business' With its reasonably predictable earnings and cash flow, AEP's wires business provides a balance to our wholesale business that makes us even stronger.

Our wires business is focused on value cre ation, or identifying opportunities to do things better and smarter and then working with regulators to share the benefits with both customers and shareholders This business J

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'Commercial operation of AEP's Trent Mesa Wind Project near Abilene, Texas, began last summer. Output of the 150-megawatt project is committed to TXU Corp. We also purchased Sthe 160-megawatt Indian Mesa Wind Power Project from Enron Wind. City Public Service, the municipal electric utility for San Antonio, Texas, will buy all the power generated from the Indian Mesa turbines under long-term agreements Wind power now accounts for nearly 1 percent of AEP's generation.

We are evaluating other renewable technologies, such as solar energy and biomass, as well Emissions reduction Our abilityto meet federal standards to control nitrogen oxide emissions continues to focus on use of selective catalytic reduction (SCR) technology. We have installed the technology on two 1,300-megawatt units and SCR installation is scheduled

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contnbuted $2.30 per share to 2001 ongoing earnings before capital costs, up a dime from 2000 Greater revenue and flat operating and maintenance expenses led to the improvement Employees in our wires operations are ferreting out ways to reduce capital expenditures by $800 million and annual opera tion and maintenance expenses by $100 million over the next four years Our regulated businesses are coming up with innovative ways to trim costs, raise revenue and - atthe same time - improve service. For instance, wires employees are combining extensive training, the latest technology and years of experience to per form maintenance on energized power lines The more mainte nance that can be done safely on lines without removing them from service, the more trans mission capacity that's available to serve retail and wholesale customers.

Use of AEP lines for wholesale transactions with unaffiliated parties has also become a significant source of revenue for us, growing to $154 million in 2001 from $60 million five years ago. And our employees are generating revenue by teaching live-line maintenance procedures to contractors and line personnel from other utilities.

Maximizing return Maximizing the regulated return we can earn on our substantial transmission and distribution assets is an ongoing goal. Our 38,000-mile transmission network has a net book value of more than $3 4 billion and our regulated distribution assets have a net book value exceeding $5 8 billion.

As I mentioned in last year's letter, AEP believes for-profit man agement of the transmission portion of our wires business will enhance its value to investors while meeting customers' and regulators' requirements. In our view, this business model will bolster competitive generation markets by providing seamless, nondiscriminatory transmission access while encouraging capi tal investment for transmission improvements and expansion.

AEP has been very involved over the past few years in forming the Alliance RTO (regional transmission organization), which is based on this model We and our Alliance partners, at the Federal Energy Regulatory Commission's (FERC) direction, are exploring whether the for-profit entity can fit under another RTO's umbrella FERC has approved a wholly owned subsidiary of National Grid as the Alliance's independent managing mem ber National Grid has extensive background in successfully operating transmission systems in North America and the UK.

Adding to our track record I'm excited about our prospects for 2002 i AEP has demonstrated it has the resources, expertise and leadership to deliver value to shareholders in all economic conditions We expect our balanced portfolio of businesses to provide ongoing earnings per share of $3 60 to $3.75 in 2002. That estimate is based on some confidence the economy will recover and on our potential issuance of equity to sup port corporate separation, fund new growth and strengthen our balance sheet We anticipate our acquisitions of HPL, MEMCO Barge Line, Quaker Coal and the UK generating stations to add approxi mately 22 cents per share to 2002 earnings We are exploring options for our electric distribution and electric and gas supply subsidiary in southeast England (SEEBOARD) and our electricity distrnbution and retail sales subsidiary in Melbourne, Australia (CitiPower). We will evaluate possible divestiture of these investments, but any divestiture is not likely before the third quarter.

We expect AEP's unregulated wholesale business to contribute approximately 38 percent of total earnings before interest and taxes in 2002, with our regulated energy distribution business w

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contributing 26 percent regulated energy transmission business, 19 percent, and regulated generation business, 17 percent.

Continued strategic acquisitions and development of wholesale products and geographic regions will fuel much of our 6 percent to 8 percent projected growth. A full year of operation of assets we acquired in 2001 also will contribute heavily Improving our capital structure and reducing our short-term debt remain goals for 2002. At the close of 2001, short-term debt accounted for 13 percent of our capitalization, down from 18 percent a year earlier. We are targeting a consolidated equity ratio of at least 40 percent We're confident the challenge raised to Securities and Exchange Commission approval of the AEP-CSW merger in a federal appeals court will result in confirmation of the approval sometime this year, we hope.

Giving credit where credit is due In closing, I want to thank AEP employees for the dedication, energy and resilience they demonstrated in 2001. Without their efforts and successes, day in and day out, AEP would not be the strong, balanced and agile enterprise it has become. Our nearly 28,000 people worldwide are the face and spirit of AEP.

How very fitting that our employees' hard work was recognized last year with the Edison Electric Institute's Emergency Response Award. Two ice storms ravaged the western part of our service territory in the last few weeks of 2000, cutting power to several hundred thousand customers The EEl award honors the nearly 5,000 AEP employees, contractors, support personnel and visiting crews who worked around the clock to repair damage and restore electric service I appreciate the efforts of my senior management team in adjusting to the new duties many of them assumed last fall as part of AEP's management realignment Tom Shockley, vice chairman, has the new additional title of chief operating officer and has overall responsibility for AEP's regulated and unregulat ed businesses Susan Tomasky is now chief financial officer in addition to her responsibilities in the policy and strategy arena Henry Fayne, formerly chief financial officer, heads our regulated business, filling the very big shoes left by Bill Lhota's retirement late last year. Eric van der Walde oversees our wholesale line of business.

Bob Powers continues to have executive oversight for our nuclear operations while assuming new responsibilities in non-nuclear erngineering and research and development and Chris Bakken is chief nuclear officer based at the Cook plant site. Joe.Vipperman continues to oversee our shared services organization.

No expression of thanks would be complete without noting my appreciation for the contrib utions of our Board of Directors.

In particular, I want to recognize James Powell, who retires from the board this year. Jimmie joined our board when the AEP-CSW merger was completed and has served on the audit, policy, and directors and corporate governance committees He had served on CSWs board since 1987. We will miss Jimmie's wise counsel and informed guidance and wish him all the best in retirement Last but surely not least thank you to AEP's customers and investors Your role in our success cannot be overstated We will continue to work diligently to earn your business and your loyalty E. Linn Draper, Jr.

Chairman, President & Chief Executive Officer February 27,2002

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The following discussion is a summary analysis of AEP's results of operations for the year 2001 compared with 2000 and an overview of the company's business strategy, outlook, financial condition, revenue recognition policies and market risk. A complete analysis of the results of operations and discussion of the financial condi tion of the company can be found in the Management's Discussion and Analysis of Results of Operations and Financial Condition por tion of the Appendix A to the Proxy Statement Appendix A and Form 10-K also contain detailed discussions of major uncertainties, contingencies, significant accounting policies, risks and other issues that the company faces.

Business Strategy Our strategy is to deliver a balanced business model of regulated and unregulated businesses backed by assets, supported by enterprise-wide risk management and a strong balance sheet which delivers earnings growth of 6 to 8%. 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 regu lated business that has a predicable earnings stream and cash flows. Strong risk management and a disciplined analysis of mar kets 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 analytical 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 cus tomer connectivity, giving us the ability to make informed marketing and trading decisions and to customize our products and services AEP provides investors with a balanced portfolio composed of:

"* a growing unregulated wholesale energy marketing and trading business

"* a predictable cash flow and earnings stream 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 Public Utility Holding Company Act 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 com missions 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 Consolidated Condensed Balance Sheets At December 31 (In Millions)

Assets 2001) 2000)

Assets Cash and Cash Equivalents

- $ 333)

S 342)

Energy Trading and Derivative Contracts-Current 8,572) 15,497)

Other Current Assets 3,658) 5,062)

Property, Plant and Equipment 40,709) 38,088)

Accumulated Depreciation and Amortization

-1615 695)

Net Property, Plant and Equipment 24543)-

22_393)

Regulatory Assets 3,162) 3,698)

Other Assets 7013) 6-358)

Total K7,281)

$53.50)

CŽapitaliztion and Liabilities EnergyTrading and Derivative Contracts-Current

$8,311)

$15,671) qL-----

Other Current Liabilities 978---10,266)

Long-Tern Debt 9,753) 9,602)

Deferred Income Taxes and Investment Tax Crerldts n4 DAtQJ Minority Interest in Financing Subsidiary 750)

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Other Liabilities 4,980) 4193)

Total Uabilities 38,896) 45,135)

Cumulative Preferred Stocks of Subsidiaries

- 156) 161)

Common Shareholders' Equity

-AIM,8l-)

8_054)

Total 721)

$53,350)

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

The risks'in our business are:"

"* Margin erosion oin electric trading as markets mature,

"* Diminished oplportunities for significant gains as volatility

declines,

"* Retail price reductions mandated with the implementation of customer choice in Texas and Ohio,

"* Movement toward re-reguilation in California through market caps and other challenges to the continuation of deregulation of the retail'electricity supply business in the U.S, and

"* 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 valu~e 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 AEP's competitive advantages

"* Continued expansion of intellectual capital through ongoing reciuiting, performiance-linked compensation and the

,development of a structure and culture that promotes sound decision-making and innovitio n 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 improvementeto maintain distribution service quality while enhancing financial performiance

"* Optimize -eneration assets through enhanced availability of off-system sales

"* Manage th6 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, o 4,200 miles of gas pipeline, 118 Bcf gas storage and related gas marketing contracts o 1,200 hopper barges and 30 iugboats o '4,000 megawatts of coal-fired generation in England o 160 megawatts of wind generation in Texas o 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, SO, allowances, natural gas liquids (NGLs) and oil

"* Disposing of the following assets that did not fit our strategy.

"o 120 MWs of generation in Mexico, "o

Above-market coal mines in Ohio and West Virginia, "o

A 50 % investment in Yorkshire, a UK electric supply and distribution company, "o

An investment in a Chilean electric company, and "o

Datapult3M, 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 divestiture 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 preiently evaluating certain 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 reitrictions which end in June 2002.

We are committed to continually evaluate the need to reallocate resources to areas with greate'r potential, to mnatch invCestmenis with our strategy and to pare investrments that do not'produ6e suf ficient return and shareholder value. Any investment dispositions could affect 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 demon strated in recent months by our move into global coal markets and Nordic energy. A full year of dperation of assets acquired in 2001 Houston Pipe Line, Quaker Coal, the MEMCO barge line and two power plants in the United Kingdom - will also contriliute to growth in 2002 earnings.

Although we expectthat the future outlook for results of operations is excellent, there are contingencies and challenges.

We fully discuss these matters in the'Notes to Consolidated Financial Statements and in the Mainag~inent Discuisiion and Analysis in the Appendix A tothe Proxy. We intend to work diligently to resolve these-matters by finding workable solutions that balance the interests -of our custom-ers, our employees and our shareholde'rs.

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

"* Wholesale "o Generation of electricity for sale to retail and wholesale customers "o Gas pipeline and storage services "o

Marketing and trading of electricity, gas and coal "a

Coal mining, bulk commodity barging operations and other energy supply-related business

"* Energy Delivery o Domestic electricity transmission o Domestic electricity distribution

"* Other Investments "o Foreign electric distribution and supply investments "o Telecommunication services Revenue Recognition Porcies Traditional Regulated 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 thus 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.

Application of SFAS 71 for the generation portion of the business was discontinued in Ohio in September 2000, in Virginia and West Virginia in June 2000, and in Texas and Arkansas in September 1999 in recognition of the passage of legislation to transition to customer choice and market pricing for the supply of electricity These discontinuances of the application of SFAS 71 resulted in extraordinary losses from the stranding of certain net regulatory assets that are not recoverable under the restructuring legislation and competitive market pricing.

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 finan cial energy contracts which include exchange futures and options and over-the-counter options and swaps. Although trading con tracts 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 energytrading 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 accounting It represents the change in the unrealized gain or loss throughoutthe 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 con tract'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 electricity and gas contracts that are typically settled by entering into offset ting 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 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 com modity 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 a profit or loss, specifically it is the difference between the contracted settlement price of the two contracts. Mark-to-market accounting forthese 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 transac tions but enter into a purchase contract prior to entering into a sales contract It 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 changes in fair values.

Trading of electricity and gas options, futures and swaps repre sents 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 is 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 under lying 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 Consolidated Condensed Statements of Income Year Ended December 31 (In Millions-Except Per Share Amounts) 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 effects on future results of operations and cash flows if market prices do not correlate with the company-developed price curves 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 unreal ized net gains from marking to market open trading and derivative contracts AEPs net revenues (revenues less fuel and energy purchases) excluding mark-to-market revenues totaled $8 3 billion and were realized in cash during 2001. Unrealized net mark-to market revenues are only 3% of total net revenuei'Most of the 2001)"

2000)

% Change)

Revenues

$61,257)

£$36,706) 669)

Expenses:

Fuel and Purchased Energy T-52,753) 28,718) 837)

Maintenance and Other Operation 4,037) 3,841) 5.1)

Non-Recoverable Merger Costs

21) 203)

(897)

Depreciation and Amortization 1,383) 1,250) 106)

Taxes Other Than Income Taxes 668) 690)

(32)

Total Expenses 58,862) 34,702) 696)

Other Income (net) 172)'

55) 2127)

Income Before Interest, Preferred Dividends, Minority Interest and Income Taxes 2,5 67) 2,059)

• 24.7)

Interest, Preferred Dividends and Minority Interest 995) 1,160)

(142)

Income Taxes

, ý569) 597)

(47)

Income Before Extraordinary Items and Cumulative Effect 1,003) 302) 232.1)

Extraordinary Losses (net of tax):

Discontinuance of Regulatory Accounting for Generation (48)

(35) 37.1)

Loss on Reacquired Debt 7

(2).)

NM)

Cumulative Effect of Accounting Change

1.

8)

-)

NM)

Net Income

.... $S911)

$ 267) 263.7)

Average Number of Shares Outstanding 322) 322)

1)

Earnings Per Share:

Income Before Extraordinary Items and Cumulative Effect

$ -3.11)

$ 0.94) 2309)

Extraordinary Losses (0.16)-

(0.11) 45.5)

Cumulative Effect 006)

-)

NM)

Net Income 301)

$ 083) 262.7)

Cash Dividends Paid Per Share

_________2

40)

$ 24)

__)

N M =Not Meaningful

net unrealized revenues from marking to markettrading contracts and derivatives included in our balance sheet at December 31, 2001, as energy trading and derivative contract assets and liabilities, which net to $448 million before any regulatory deferrals, 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 us to market risk and causing our results of operations to be more volatile. See "Market Risks" section below for a discussion of the policies and procedures we use to manage our exposure to market and other risks from trading activities.

Net Income Net income increased to S971 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 market ing 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 certain 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 charges for severance accruals, losses from Enron's bankruptcy and extraordinary losses from the effects of deregulation and a loss on reacquired debt 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 eco nomic 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 changes 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 power 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 dis allowance and declining short-term market interest rate conditions Revenues For the Year Ended December 31 (In Millions)

Wholesale Business Residential Commercial Industrial Other retail customers Marketing and Trading-Electricity Marketing and Trading-Gas Unrealized MTM Income:

Electric Gas Other Less transmission and distribution revenues assigned to Energy Delivery*

Total Wholesale Business Energy Delivery Business:

Transmission Distribution Total Energy Delivery Other Investments:

SEEBOARD CitiPower Other Total Other Investments Total Revenues 2001) 2000)

S 3,553) 2,328)

Z388) 419) 35,339) 14,369) 210)

47) 632) f3.356) 55,929) 1,029) 2,327) 3,356) 1,451) 350) 171) 1,972)

S61 A7)

$3,511) 2,249) 2,444) 414) 18,858) 6,127)

38) 132) 838) 13,174) 31,437) 1,009) 2,165) 3,174) 1,596) 338) 161) 2,095)

$36706)

• Certain revenues in the wholesale business include energy delivery revenues due primarily to bundled tariffs that are assignable to the Energy Delivery business 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 favorable effect on the volume of wholesale power marketing and trading, especially in the short-term market.

Our total revenues increased 66 9% in 2001 due mainly to the growth of our wholesale marketing and trading operations The $25 billion increase in 2001 revenues was due to substantial increases in electric and gas trading volumes 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 The increase in gas trading volume is due to:

"* Continued expansion of our trading team,

"* The HPL acquisition on June 1, 2001, and

"* Expansion into new markets

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

Operating Expenses Increase Changes in the components of operating expenses were as follows:

For the Year Ended December 31 (In Millions)

Fuel and Purchased Energy Maintenance & Other Operation Non-recoverable Merger Costs Depreciation & Amortization Taxes Other Than Income Taxes Total 2001)

Increase(Decrease)

$24,035) 196)

(182) 133)

(L2)

$24,160) 837)

51)

(89.7) 10.6)

(32) 696)

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.

MIaintenance 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 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 the amortization of transition generation-related regulatory assets in the Ohio, Virginia and West Virginia jurisdictions due to passage of restruc turing legislation, the new busines-s*s acquired in 2001 and additional investments in'property,'plant and equipment Interest, Preferred Stock Dividends, Minority Interest Interest expense decreased 15% in 2001 due to the effect of interest paid to the IRS on a COLI deduction disallowance in 2000 and lower average outstandirng'short-term debt b'alances 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 mnember interest Other Income The sale in March 2001 of Frontera, a generating plant reqdLired'to be divested under a FERC-approved mergersettlement agreement, produced a pretax $73 million-gain which accounted for the increase in other income in 2001.

Income Taxes Although pre-tax book income increased considerably, income taxes decreased due to the effect of recording prior year federal income taxes as a result of the disallowance of COIl interest deductions by the IRS in 2000 and nondeductible merger-related costs in 2000 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 In 2000 we recorded an extraordinary loss from the discontinuance of the application of regulatory accounting for Ohio, Virginia and West Virginia jurisdictions of $35 million due to the passage of restructuring legislation.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 on July 1, 2001, was a favorable

$18 million, net of tax, which is reported as a cumulative effect of an accounting change.

Financial Condition We measure the financial condition of the company by the strength of its balance sheet and the liquidity provided by cash flows and earnings Balance sheet capitalization ratios and cash fiow ratios are principal determinants of the compan'y's credit'qiality.The-ratings are presently stable. Our year end ratings of subsidiaries' first mort gage bonds were: Moody's Al to Baal, S&P A to A-, Fitch A+ to BBB+. Our subsidiaries' year end ratings for senior unsecured debt were. Moody's A2 to Baal, S&P BBB+, Fitch A to BBB. 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 for financing increased to 3%. In 2001 and 2000, the company did not issue any shares of common stock to meeithe requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan.

We plan to strengther 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 earn ings per share but will enhance the equity to capitalization ratio Rating agencies have become more focused in their evaluation of credit quality as a resul*tof the Enron bankruptcY, They are focusing especially on the composition of-the balance sheet with particular interest in off-balance' shee't le'sses and debt and special purpo'se financiing structure's, the cash liquidity profile and the impact 6f credit quaity dowvngrades on financing transac tions We have worked closely with the agencies to'provide them with all the information they need,'but we are unable to predict W

Consolidated Condensed Statements of Cash Flows Year Ended December 31 (In Millons) 2001) 2000)

Operating Activities Net Income

$ 971)-

$ 267)

Adjustments for Noncash Items 1,982) 1,166)

Net Cash Flows from Operating Activities 2,953) 1,433)

Investing Activities Construction Expenditures-Worldwide (1,832)

(1,773)

Purchase of Houston Pipe Line (7271

-1)

Purchase of UK Generation (943)

-1)

Purchase of Quaker Coal Co (101)

--))

Purchase of MEMCO (266)

Purchase of Indian Mesa (175)

Sale of Yorkshire Sale of Frontera Other Net Cash Flows Used for Investing Activities S.....

Financing Activities Issuance of Common Stock Issuance of Minority Interest 383) 265)

-- )

(36)

19) 3-432-...........

3 2 )

(1,754)

10)

14) 747) _

Change in Long-term Debt (net)

Change in Short-term Debt (net)

Dividends Paid on Common Stock Other Net Cash Flows from Financing Activities Effect of Exchange Rate Change on Cash Net Decrease in Cash and Cash Equivalents Cash and Cash Equivalents January I Cash and Cash Equivalents December 31 S...

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 and new investments 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.

Asset purchases include HPL, coal mines, a barge line, a wind generating facility and two coal-fired generating plants in the UK 1.096)

(597)

(441) 1,308)

(805)

(773)

__ _(10)

(20) 473)

56)

(3) 3-(23)

(9) 1 242) 342) 584) 333)$

342)

These acquisitions accounted for the increase in total debt in 2001. During the third quarter of 2001, permanent financing was completed for the acquisition of HPL by the issuance of a minority interest which provided $735 million net of expenses. HPUs permanent financing increased funds available for other corporate purposes. Long-term financings for the other acquisitions will be announced as arranged. Long-term funding arrangements for specific assets are often complex and typically not completed until after the acquisition Earnings for 2001 resulted in a dividend payout ratio of 80%, a considerable improvement over the 289% payout ratio in 2000.

The abnormally high ratio in 2000 was the result of the adverse impact on 2000 earnings of the Cook Plant extended outage and related restart expenditures, merger costs, the COLI tax disal lowance and the write-off of non-regulated subsidiaries. We expect continued improvement of the payout ratio as a result of earnings growth in 2002 W

Capitalization Ratio 06%

SLong-Term Debt 1 Preferred Stock t* Common Equity 07%

2000 Minority Interest 0 Short-Term Debt Cash from operations and short-term borrowings provide working capital and meet other short-term cash needs. We generally use short-term borrowings to fund property acquisitions and construc tion until long-term funding mechanisms'ire arranged. Some acquisitions of existing business entities include the assumption of their outstanding debt and certain liabilities. Sources of long-term funding include issuance of AEP common stock, minority interest or long-term debt and sale-leaseback or leasing arrangements.

We operate a money pool and sell accounts receivables to pro vide liquidity for the domestic electric subsidiaries. Short-term borrowings irithe U.S. aee supp~orted by two revolving credit agreements At December 31, 2001, approximately $554 million remained available for short-term borrowings in the U S Subsidiaries thattrade energy commodities in Europe have a separate multicurrency revolving loan and letter of credit agree ment allowing them to borrow up to C150 million of which C42 million was available on December 31, 2001. In February 2002 they also originated a temporary second line of C50 million for three months, which is-expected to be" replaced with a E150 million line.

SEEBOARD, Nanyang and CitiPower, which operate in the UK, China and Australia, respectively, each have independent financing arrangements which provide for borrowing in the local currency.

SEEBOARD has a £320 million revolving credit agreement it uses for short-term funding purposes. At December 31, 2001, £203 million was available.

AEP issued $1.25 billion of global notes in May 2001 (with interme diate maturities). The proceeds were used to pay down outstand ing commercial paper. In 2001 CSPCo and OPCo, AEP's OhioDsub sidiaries, redeemed $295.5 million and $175 6 million, respectively, of first mortgage bonds in preparation for corporate separation'.

AEP Credit putrchases, without recourse, the accounts receivable of most of the domestic 'tility operating companies and certain non-affiliated electric utility'companies AEP Credi" financing for the purchase of receivables changed during 2001. Starting December 31, 2001, AEP Credit entered into a sale of receivables agreement with certain banks The agreement allows AEP Credit to sell certain receivables and receive cash, meeting the require ments for the receivables to be removed from the balance sheet The agreement with the banks expires in May 2002 and is expected to be renewed. At December 31, 2001, AEP Credit had $1.1 billion

'1 he!.

W sold under this agreement of which $590 million was a result of non-affiliate factoring A factoring of receivable agreement for a non-affiliated company was ended in January 2002.

In February 2002 CPL issued $797 million of securitization' notes that were approved by the PUCT a's part of Texas restiuctdring to help decrease rates and recover regulatory assets. The proceeds were used to reduce debt and equity through a dividend to CPL's parent company.

In 2002 the company plans to continue restructuring its debt for corporate separation, assuming receipt of all necessary regulatory approvals. Corporate separation will require the transfer of assets between legal entities With corporate separation, a newly created holding company for the unregulated business is expected to issue all debt needed to fund the wholesale business and unregu lated generating companies. The size and maturity lengths of the original offering is presently being determined The regulated holding company is expected to issue the debt needed bythe wires companies in Ohio a~nd Texas. The regulated integrated utility companies %ill continue their current debt structure until the state regulatory commissions approve changes.

At thattime, the regulated holding company may also issue the debt for the regulated companies' funding needs:

We have requested credit ratings for the holding companies consistent with our existing credit qu ality, but we cannot predict wIhat the outcome will be.

AEP uses a money pool to meet the short-term borrowings for certain of its subsidiaries, primarily the domestic electric utility operations. Following corporate separation, we will evaluate the advantages of establishing a money pool for the unregulated busi ness subsidiaries. The current money pool w hich was approved by the appropriate regulatory authorities will continue to service the regulated business'subsidiaries. Presently, AEP also funds the sh6rt-term debt requirements of other subsidiaries that are not included in the money pool. As of December 31, 2001, AEP had credit facilities totaling $3 5 billion to support its commercial paper program. At Decermber 31,2061, AEP had S2.9 billion outstanding in commercial paper borrowings subjectto these credit facilities.

Market Risks As a major power producer and trade" of wholesale electricity and natural gas, 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 imp-act us due to changes in the underlying market prices or rates.

Policies and procedures are established to-identify, assess and manage market risk exposures in'our day-to-day operations. Our risk policies have been reviewed with the Boaid of Directors, approved by a Risk Managernert Comnaittee and administered by a Chief Risk Officer. The Risk Management Committee establishes risk limits, approves risk policies, assigns responsibilities regarding the oversight and management of risk and monitors risk levels.

This committee receives daily, weekly and monthly reports regard ing compliance with policies, limits and procedures. The commit tee meets monthly and consists of the Chief Risk Officer, Chief

Credit Officer, V. R - Market Risk Oversight, and senior financial and operating managers.

We use a risk measurement model that calculates Value at Risk (VaR) to measure our commodity price risk. The VaR is based on the variance - covariance method using historical prices to estimate volatilities and correlations and assuming a 95% confidence level and a one-day holding period. Based on this VaR analysis, at December 31, 2001, 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 high, average, and low market risk as measured by VaR at December 31, (in Millions) 2001 2000 High Average Low High Average Low

$28

$14

$5

$32

$10

$1 We also 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 weekly prices The risk of potential loss in fair value attributable to AEP's exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $673 million at December 31, 2001, and $998 million at December 31, 2000.

However, since we would not expect to liquidate our entire debt portfolio in a one-year holding period, a near-term change in interest rates should not materially affect results of operations or consolidated financial position.

AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen The protection afforded by fuel clause recovery mecha nisms has either been eliminated by the implementation of cus tomer choice in Ohio (effective January 1, 2001) and in the ERCOT area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan and West Virginia To the extent all of the fuel supply of the generating units in these states is not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.

We employ physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropri ate However, we engage in trading of electricity, gas and to a lesser degree, coal, and as a result the company is subject to price risk The amount of risk taken by the traders is controlled by the management of the trading operations and the company's Chief Risk Officer and his staff When the risk from trading activities exceeds certain pre-determined limits, the positions are modified or hedged to reduce the risk to the limits unless specifically approved by the Risk Management Committee We employ fair value hedges, cash flow hedges and swaps to mitigate changes in interest rates on short-and long-term debt when management deems it necessary We do not hedge all interest rate risk We employ cash flow forward hedge contracts to lock in prices on purchased assets denominated in foreign currencies where deemed necessary. International subsidiaries use currency swaps to hedge exchange rate fluctuations in debt denominated in for eign currency. We do not hedge all foreign currency exposure AEP limits credit risk by extending unsecured credit to entities based on internal ratings. In addition, AEP uses Moody's Investor Service, Standard and Poor's and qualitative and quantitative data to independently assess the financial health of counterparties on an ongoing basis This data, in conjunction with the ratings infor mation, is used to determine appropriate risk parameters. AEP also requires cash deposits, letters of credit and parental/affiliate guarantees as security from certain below-investment grade counterparties in our normal course of business We trade electricity and gas contracts with numerous counterparties. Because our energy trading contracts are based on changes in market prices of the related commodities, our exposures change daily We believe that our credit and market exposures with any one counterparty are not material to financial condition at December 31, 2001 The following table approximates the counterparty credit quality and exposure expressed in terms of net mark-to-market assets at December 31, 2001. 5% of the net counterparties were below investment grade. Net mark-to-market assets is the aggregate difference (either positive or negative) between the forward market price for the remaining term of the contract and the contractual price Counterparty Credit Quality-.

December 31, 2001 AAA/Exchanges AA A

BBB Below Investment Grade Total Futures Forward &

Swap Contracts

$ 147 140 304 932 56

$1,579 Options (in millions) 4 7

34 23

$68 Total

$ 147 144 311 966 79

$1,647 We enter into transactions for electricity and natural gas as part of wholesale trading operations Electric transactions are executed over-the-counter with counterparties. Gas transactions are exe cuted through brokerage accounts with brokers, who are regis tered with the Commodity Futures Trading Commission. Brokers and counterparties require cash or cash-related instruments to be deposited on these transactions as margin against open positions.

The combined margin deposits at December 31, 2001 and 2000 was $11 million and $95 million. We can be subject to further margins should the related commodity prices change.

We recognize the net change in the fair value of all open trading contracts, a practice commonly called mark-to-market accounting, in accordance with generally accepted accounting principles and include the net change in mark-to-market amounts on a net discounted basis in revenues. Unrealized mark-to-market revenues totalled $257 million in 2001 The fair values of open short-term

trading contracts are based on exchange prices and broker quotes. The fair value of open long-term trading contracts is based mainly on company-developed valuation models. The valuation models produce an estimated fair value of open long term trading contracts This fair value is present valued and reduced by appropriate reserves by counterparty credit risks and liquidity risk The models are derived from internally assessed market prices with the exception of the NYMEX gas curve, where we use daily settled prices. Forward price curves are developed for inclusion in the model based on broker quotes and other avail able market data. The curves are within the range between the,

bid and ask prices. The end of the month liquidity reserve is based on the difference in price between the price curve and the bid price of the bid ask prices if we have a long position and the ask price if we have a short position. This provides for a conservative valuation net of the reserves The use of these models to fair value open long-term trading contracts has inherent risks relating to the underlying assump tions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models Significant adverse effects on future results of operations and cash flows could occur if market prices, atthe time of settlement, do not correlate with the company-developed price curves The effect o'n the Consolidated Statements of Income of marking to market open physical electricity trading contracts in the com ujany's regulated jurisdictions is deferred as regulatory assets or liabilities since these transactions are included in cost of service on a settlement basis for ratemaking purposes Unrealized mark to-market revenues impact earnings only for the nonregulated electric and gas businesses Unrealized mark-to-market gains and losses from trading are reported as trading and derivative contract assets or liabilities.

The following table shows net revenues (rev and purchased energy expense) and its relat mark-to-market revenues (the change in fair trading contracts).

Revenues including '

, I Mark-to-Market Net Adjustments Fuel and Purchased Energy Expense Net Revenue Net Mark-to-Market Revenues Percentage of Net Revenues Represented by Unrealized Mark-to-Market The net fair value of open energytrading contracts was a net asset of $448 million and $63 million at December 31, 2001 and 2000, respectively. The change in the net fair value of open energy trading contracts recognized in revenues resulting from mark-to market accounting and unrealized at December 31, 2001, was $257 million.

We have investments in debt and equity securities which are held in nuclear trust funds The trust investments and their fair value in these trust funds have not been included in the market risk calculation for interest rates as these instruments are marked to market and changes in market value of these instruments are reflected in a corresponding decommissioning liability. Any differ ences between the trust fund assets and the ultimate liability are expected to be recovered through regulated rates from our regulated customers and should not impact future earnings.

Inflation affects our cost of replacing utility plant and the cost of operating and maintaining plant. The rate-making process limits recovery to the historical cost of assets, resulting in economic losses when the effects of inflation are not recovered from customers on a timely basis However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses Contingencies '

As previously indicated, we have exposure to a number of significant contingencies including, but not limited to, the following matters, which are fully discussed in Management's Discussion and Analysis of Results of Operations and Financial Condition and the Notes to Consolidated Financial Statements contained in Appendix A to the Proxy Statement and Form 10-K:

- realization of expected merger cost savings, some of which are shared with customers under merger-related, state enues less fuel approved settlement agreements, tionship to unrealized

- the resolution of proposed new environmental standards, market value of open o litigation and other actions related to air quality and coal-fired generating plant emissions and the costto achieve ultimately required emission reductions; December 31

• the recovery of regulatory assets and other stranded cost 2001 2000 in Texas; (in millions)

• merger litigation concerning the requirements of the Public Utility Holding Company Act,

$ 61,257

$ 36,706

• completion of a transmission line in Virginia and West Virginia; 52,753 28,718

• resolution of complaints by certain wholesale customers in Texas,

$8,504

$ 7,988

• any further losses that could be incurred from Enron's 257 170 bankruptcy, and

• market risks for changes in energy commodity prices, interest rates, fuel prices, financial derivative instruments and foreign 10/.

10/

currency rates.

Investors should read our full financial statements and related disclosures included in Appendix A to the Proxy Statement and our Form 10-K filing with the SEC prior to making any investment decisions.

W

• J IU

• ,,'=1

Independent Auditors' Report To the Shareholders and Board of Directors of American Electric Power Company. Inc.:

We have audited the consolidated balance sheets of American Electric Power Company, Inc, and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, common shareholders' equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2001 Such consolidated financial statements and our report thereon dated February 22, 2002, expressing an unqualified opinion (which are not included herein) are included in Appendix A to the proxy statement for the 2001 annual meeting of share holders The accompanying condensed consolidated financial statements are the responsibility of the Company's management Our responsibility is to express an opinion on such condensed consolidated financial statements in relation to the complete consolidated financial statements In our opinion, the information set forth in the accompanying condensed consolidated balance sheets as of December 31, 2001 and 2000 and the related condensed consolidated statements of income and of cash flows for the years then ended is fairly stated in all material respects in relation to the basic consolidated financial statements from which it has been derived.

Columbus, Ohio February 22, 2002 W

Corporate Officers American Electric Power Company, Inc.

E. Linn Draper, Jr.

'Chairman, President and Chief Executive Officer Thomas V. Shockley, III Vice Chairman Henry W. Fayne

-Vice President Armando A. Pefia Treasurer Susan Tomasky Vice President, Secretary and Chief Financial Officer Joseph M. Buonaiuto Controller and Chief Accounting Officer American Electric Power Service Corporation E. Linn Draper, Jr.

Chairman, President and Chief Executive Officer Thomas V. Shockley. III Vice Chairman and Chief Operating Officer Henry W. Fayne Executive Vice President Robert P. Powers Executive Vice President Nuclear Generation and Technical Services Susan Tomasky Executive Vice President Policy, Finance and Strategic

Planning, and Assistant Secretary Joseph H. Vipperman Executive Vice President Shared Services Melinda S. Ackerman Senior Vice President Human Resources Nicholas J. Ashooh Senior Vice President Corporate Communications J. Craig Baker Senior Vice President Regulation and Public Policy A. Christopher Bakken, IIl Senior Vice President Nuclear Operations Joseph M. Buonaiuto Senior Vice President, Controller and Chief Accounting Officer Jeffrey D. Cross Senior Vice President, General Counsel and Assistant Secretary Thomas M. Hagan Senior Vice President Governmental Affairs

- Dale E. Heydlauff Senior Vice President Environmental Affairs Michael F. Moore Senior Vice President Information Technology and Chief Information Officer Richard E. Munczinski Senior Vice President Corporate Planning and Budgeting John F. Norris, Jr.

Senior Vice President Operations and Technical Services Armando A. Perla Senior Vice President Finance and Treasurer Scott N. Smith Senior Vice President and Chief Risk Officer AEP Energy Services, Inc.

Steven A. Appelt Executive Vice President Administration Eric J. van der Walde Executive Vice President Marketing and Trading

Dr E. Unn Draper. Jr, 60 Chairman, President

& Chief Executive Officer (1992) '

E. R. Brooks, 64 Retired Chairman

& Chief Executive Officer, Central & South West Corporation Granbury, Texas (2000) " N P Dr Donald M. Carlton, 64 Retired President

& Chief Executive Officer, Radian International, LLC Austin, Texas (2000) A,' N P John R DesBarres. 62 Investor/Consultant Park City, Utah (1997) E.eK P Robert W. Fri. 66 Director, National Museum of Natural History Smithsonian Institution Washington, D C.

(1995) H N.I William R. Howell, 66 Chairman Emeritus, J. C. Penney Company, Inc.

Dallas, Texas (2000) o.,H P Dr. Lester A. Hudson, Jr. 62 Professor of Business Strategy Clemson University Greenville, South Carolina 11987) Ako '

Leonard J. Kujawa. 69 International Energy Consultant Atlanta, Georgia (1997) D.P James L Powell, 72 Ranching and Investments Fort McKavett, Texas 120001 A. D P Dr. Richard L Sandor, 60 Chairman & Chief Executive Officer, Environmental Financial Products, LLC Chicago, Illinois (2000) D.F P Thomas V. Shockley, III, 56 Vice Chairman (2000)

Donald G. Smith, 66 Chairman, President

& Chief Executive Officer Roanoke Electric Steel Corporation Roanoke, Virginia (1994)H "t P Linda Gillespie Stuntz, 47 Partner, Stuntz, Davis &

Staffier, P.C Washington, D C.

(1993) D I.I P Dr. Kathryn D. Sullivan, 50 President & Chief Executive Officer Center of Science & Industry Columbus, Ohio (1997) A,NP Committees of the Board:

The chairman is listed in ()

A Audit (Carlton),

0 Directors and Corporate Governance (Hudson),

Executive (Draper),

F Finance (Stuntz),

"H Human Resources (DesBarres),

N Nuclear Oversight (Sullivan),

P Policy (Fril)

Dates in parentheses indicate year elected to Board W

Shareholder Information Annual Meeting - The 95th annual meeting of shareholders of American Electric Power Company will be held at 9 30 a m.

Tuesday, April 23, 2002, at The Ohio State University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio. Admission is by ticket only. To obtain a ticket, please note the instructions in the Notice of Annual Meeting mailed to shareholders or call the Company. If you hold your shares through a broker, please bring proof of share ownership as of the record date.

Shareholder Inquiries - If you have questions about your account, contact the Company's transfer agent, listed below. You should have your Social Security number or account number ready, the transfer agent will not speak to third parties about an account with out the shareholder's approval or appropriate documents Transfer Agent & Registrar EquiServe (formerly First Chicago Trust Company of New York)

RO. Box 2500 Jersey City, NJ 07303-2500 Telephone Response Group 1-800-328-6955; Internet address: www equiserve.com Hearing Impaired 1TDD: 201-222-4955 Internet Access to Your Account-If you are a registered shareholder, you can access your account information through the Internet at www.equiserve.com. Information about obtaining a password is available toll-free at 1-877-843-9327.

Replacement of Dividend Checks - If you do not receive your dividend check within five business days after the dividend lIay ment date, or if your check is lost, destroyed or stolen, you should notify the transfer agent for areplacement.

Lost or Stolen Stock Certificates - If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a 'stop transfer" order can be placed on the missing certificate. The transfer agent then will send you the required documents to obtain a replacement certificate.

Address Changes - It is important that we have your current address on file so that you do not become a lost shareholder.

Please contact the transfer agent for address changes for both record and dividend mailing addresses We also can provide automatic seasonal address changes Stock Transfer-Please contact the transfer agent if you have questions regarding the transfer of stock and related legal requirements.

Dividend Reinvestment and Direct Stock Purchase Plan A Dividend Reinvestment and Direct Stock Purchase Plan is avail able to all investors. It is an economical and convenient method of purchasing shares of AEP common stock. You may obtain the Plan prospectus and enrollment authorization form by contacting the transfer agent.

j Direct Deposit of Dividends-The Company does offer electronic deposit of your dividends Contact the transfer agent for details.

Stock Held in Brokerage Account ("Street Name") - When you purchase stock and it is held for you by your broker, it is listed with the Company in the broker's name or "street name." AEP does not know the identity of individual shareholders who hold their shares in this manner; we simply know that a broker holds a certain num ber of shares which may be for any number of customers If you hold your stock in street name, you receive all dividend payments, annual reports and proxy materials through your broker. Therefore, if your shares are held in this manner, any questions you may have about your account should be directed to your broker.

How to Consolidate Accounts - If you want to consolidate your separate accounts into one account, you should contact the trans fer agent to obtain the necessary instructions. When accounts are consolidated, it may be necessary to reissue the stock certificates.

How to Eliminate Duplicate Mailings - If you want to maintain more than one account but eliminate additional mailings of annual reports, you may do so by contacting the transfer agent, indicating the names you wish to keep on the mailing list for annual reports and the names you wish to delete. This will affect only these mail ings; dividend checks and proxy materials will continue to be sent to each account Stock Trading -The Company's common stock is traded principally on the New York Stock Exchange underthe ticker symbol AEP. In 1999, AEP stock had been traded on the NYSE 50 years Taxes on Dividends -The Company paid $2.40 in cash dividends in 2001, all of which are taxable for federal income tax purposes AEP has paid consecutive quarterly dividends since 1910 Shareholder Direct -An array of timely recorded messages about AEP, including dividend and earnings information and recent news releases, is available from AEP Shareholder Direct at 1-800-551-IAEP (1237) anytime day or night Hard copies of information can be obtained via fax or mail. Requests for annual reports, 10-K's, 10-W's, Proxy Statements and Summary Annual Reports should be made through Shareholder Direct.

Financial Community Inquiries - Institutional investors or securities analysts who have questions about the Company should direct inquiries to Bette Jo Rozsa, 614-223-2840, bjrozsa@aep corn, or Julie Sloat 614-223-2885, jsloat@aep corn, individual shareholders should contact Kathleen Kozero, 614-223-2819, klkozero@aep corn, or April Dawson, 614-223-2591, addawson@aep.com.

Internet Home Page - Information about AEP, including financial documents, SEC filings, news releases and customer service infor mation, is available on the Company's home page on the Internet at wwwaep.com Annual Report and Proxy Materials -You can receive future annual reports, proxy statements and proxies electronically rather than by mail, if you are a registered holder, log on to www.econsent.com/aep. If you hold your shares in street name, contact your broker.

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SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (Mark One)

SANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2001 AI'RANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT

-OF 1934 For the transition period from 1to _

Registrants; States of Incorporation; Address and Telephone Number AMERICAN ELECrRIC POWER COMPANY, INC. (A New York Corporation)

AEP GENERATING COMPANY (An Ohio Corporation)

APPALACHIAN POwE COMPANY (A Virginia Corporation)

CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation)

COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)

INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)

KENTUCKY POWER COMPANY (A Kentucky Corporation)

OHIO POWER COMPANY (An Ohio Corporation) -

'PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)

SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)

WEST TEXAS UTILITIES COMPANY (A:Texas Corporation)'

1 Riverside Plaza, Columbus, Ohio 43215 Telephone (614) 223-1000 I.R.S. Employer Identification Nos.

13-4922640 31-1033833 0124790 74-0550600 31-4154203 35-0410455

,61-0247775 31-4271000 73-0410895 72-0323455 75-0646790 Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes.?. No.

- Indicate by check mark if disclosure of delinquent filers with respect to American Electric Power Company, Inc. pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part mI of this Form 10-K or any amendmient to this Form 10-K. []

Indicate by check mark if disclosure of delinquent filers with respect to Appalachian Power Company.

Indiana Michigan Power Company or Ohio Power Company pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information siatements of Appalachian Power Comfipany or Ohio Power Company incorporated by reference in Part 11 of this Form 10-K or any amendment to this Form 10-K. ?

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

Commission File Number 1-3525 0-18135 1-3457 0-346 1-2680 1-3570 1-6858 1-6543 0-343 1-3146 0-340

Securities registered pursuant to Section 12(b) of the Act:

Registrant AEP Generating Company American Electric Power Company, Inc.

Appalachian Power Company Title of each class Name of each exchange on which registered None Common Stock,

$6.50 par value............................................

8-1/4% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026.........

8% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027.........

7.20% Senior Notes, Series A, Due 2038..............

7.30% Senior Notes, Series B, Due 2038...............

New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange Columbus Southern Power Company 8-3/8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025.......... New York Stock Exchange 7.92% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2027.......... New York Stock Exchange CPL Capital I Indiana Michigan Power Company Kentucky Power Company Ohio Power Company 8.00% Cumulative Quarterly Income Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security.............

8% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2026.........

7.60% Junior Subordinated Deferrable Interest Debentures, Series B, Due 2038...........

8.72% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025..........

8.16% Junior Subordinated Deferrable Interest Debentures, Series A, Due 2025..........

7.92% Junior Subordinated Deferrable New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange New York Stock Exchange Interest Debentures Series B, Due 2027........... New York Stock Exchange 7-3/8% Senior Notes, Series A, Due 2038............ New York Stock Exchange PSO Capital I 8.00% Trust Originated Preferred Securities, Series A, Liquidation Preference $25 per Preferred Security..............

New York Stock Exchange SWEPCo Capital I 7.875% Trust Preferred Securities, Series A, Liquidation amount $25 per Preferred Security........................................

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

Registrant Title of each class AEP Generating Company, American Electric Power Company, Inc.

Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company None None None 4.00% Cumulative Preferred Stock, Non-Voting, $100 par value 4.20% Cumulative Preferred Stock, Non-Voting, $100 par value None 4.125% Cumulative Preferred Stock, Non-Voting, $100 par value None 4.50% Cumulative Preferred Stock, Voting, $100 par value None 4.28% Cumulative Preferred Stock, Non-Voting, $100 par value 4.65% Cumulative Preferred Stock, Non-Voting, $100 par value 5.00% Cumulative Preferred Stock, Non-V6ting, $100 par value None AEP Generating Company American Electric Power Company, Inc.

Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Aggregate market value of voting and non-voting

.,common equity held.

by non-affiliates of the registrants at February 1, 2002 None

$13,478,213,062 None None None None None None None None None Number of shares of common stock

'outstanding of the registrants at February 1, 2002 1,000

($1,000 par value) 322,368,167

($6.50 par value)'

13,499,500 (no par value) 6,755,535

($25 par value) 16,410,426 (no par value) 1,400,000 (no par value)'

f,009,000

($50 par Value) 27,952,473..

(no par value) 9,013,000

($15 par value) 7,536,640

($18 par value) 5,488,560

($25 par value)

NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES American Electric Power Company, Inc. owns, directly or indirectly, all of the common stock of AEP Generating Company, Appalachian Power Company, Central Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company (see Item 12 herein).

DOCUMENTS INCORPORATED BY REFERENCE Part of Form 10-K Into Which Document Description Is Incorporated Portions of Annual Reports of the following companies for the Part II fiscal year ended December 31, 2001:

AEP Generating Company American Electric Power Company, Inc.

Appalachian Power Company Central Power and Light Company Columbus Southern Power Company Indiana Michigan Power Company Kentucky Power Company Ohio Power Company Public Service Company of Oklahoma Southwestern Electric Power Company West Texas Utilities Company Portions of Proxy Statement of American Electric Power Company, Part III Inc. for 2002 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2001 Portions of Information Statements of the following companies for Part III 2002 Annual Meeting of Shareholders, to be filed within 120 days after December 31, 2001:

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

TABLE OF CONTENTS Page Number Glossary of Terms.......................................................................................................

Forward-Looking Information...................................................................................

PART I Item

1. Business.............................................................................................

Item

2. Properties...........................................................................................

Item

3.

Legal Proceedings.....................................................................

"Item

4.

Submission of Matters to a Vote of Security Holders.....................

Executive Officers of the Registrants.....

PART 11 Item

5.

Market for Registrant's Common Equity and Related Stockholder Matters...................................................................

Item

6.

Selected Financial Data............................................................

Item

7.

Management's Discussion and Analysis of Results of Operaticns and Financial Condition...........................................

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.......

Item

8. Financial Statements and Supplementary Data................................

Item

9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....................................

PART ImI k'

Item 410.

Directors and Executive Officers of the Registrants........................

Item

11.

Executive Compensation..................................................................

Item

12.

Security Ownership of Certain B1nefi~ial Owners and Management.....................................................................

Item

13.

Certain Relationships'ýnd Related Transactions..............................

PART IV Item

14.

Exhibits, Financial Statement Schedules, and Reports on Form 8-K.:.......................................................................

i 1

2 35 39 40 40 42 42 42 43 43 43 43 44 45 46 46 Signatures......................................................................................................................

49 Index to Financial Statem ent Schedules..................................................................

S-1 Independent Auditors' Report........................................................................................

S-2 Exhibit Index.................................................................................................................

E-1

GLOSSARY OF TERMS The following abbreviations or acronyms used in this Form 10-K are defined below:

Abbreviation or Acronym Definition AEGCo............................................

AEP Generating Company, an electric utility subsidiary of AEP.

AEP................................................

American Electric Power Company, 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.

AFUDC.............................................

Allowance for funds used during construction. Defined in regulatory systems of accounts as the net cost of borrowed funds used for construction and a reasonable rate of return on other funds when so used.

APCo................................................

Appalachian Power Company, an electric utility subsidiary of AEP.

Btu....................................................

British therm al unit.

Buckeye.....................

Buckeye Power, Inc., an unaffiliated corporation.

C3.....................................................

C3 Communications, Inc.

CAA..................................................

Clean Air Act.

CAAA...............................................

Clean Air Act Amendments of 1990.

CCD Group.......................................

CSPCo, CG&E and DP&L.

CERCLA.........................................

Comprehensive Environmental Response, Compensation and Liability Act of 1980.

CG&E..............................................

The Cincinnati Gas & Electric Company, an unaffiliated utility company.

CO2............................

...................... Carbon dioxide.

Cook Plant......................

The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan.

CPL..............................................

Central Power and Light Company, an electric utility subsidiary of AEP.

CSPCo....................

Columbus Southern Power Company, an electric utility subsidiary of AEP.

CSW.................................................

Central and South West Corporation.

DOE..................................................

United States Department of Energy.

DP&L...............................................

The Dayton Power and Light Company, an unaffiliated utility company.

East Zone Companies of AEP.......... APCo, CSPCo, I&M, KEPCo and OPCo.

ERCOT.............................................

Electric Reliability Council of Texas.

EWG................................................

Exempt wholesale generator.

Federal EPA......................................

United States Environmental Protection Agency.

FERC................................................

Federal Energy Regulatory Commission (an independent commission within the DOE).

FUCO...............................................

Foreign utility company as defined by PUHCA.

I&M..................................................

Indiana Michigan Power Company, an electric utility subsidiary of AEP.

IURC................................................

Indiana Utility Regulatory Commission.

KEPCo..............................................

Kentucky Power Company, an electric utility subsidiary of AEP.

M TM.................................................

M ark-to-market.

N O....................................................

N itrogen oxide.

NPDES.............................................

National Pollutant Discharge Elimination System.

NRC..................................................

Nuclear Regulatory Commission.

Ohio EPA..........................................

Ohio Environmental Protection Agency.

OPCo................................................

Ohio Power Company, an electric utility subsidiary of AEP.

OVEC...............................................

Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a 44.2% equity interest.

PCBs.................................................

Polychlorinated biphenyls.

i

Abbreviation or Acronym Definition PSO...................................................

Public Service Company of Oklahoma, an electric utility subsidiary of AEP.

PUCO...............................................

The Public Utilities Commission of Ohio.

PUHCA.............................................

Public Utility Holding Company Act of 1935, as amended.

QF.....................................................

Qualifying facility as defined in the Public Utility Regulatory Policies Act of 1978.

RCRA...............................................

Resource Conservation and Recovery Act of 1976, as amended.

Rockport Plant..................................

A generating plant, consisting of two 1,300,000-kilowatt coal-fired generating units, near Rockport, Indiana.

SEC...................................................

Securities and Exchange Commission.

SEEBOARD.....................................

SEEBOARD Group plc, Crawley, West Sussex, United Kingdom.

Service Corporation..........................

American Electric Power Service Corporation, a service subsidiary of AEP.

SO2..............................

...................... Sulfur dioxide.

SO 2 Allowance..............

An allowance to emit one ton of sulfur dioxide granted under the Clean Air Act Amendments of 1990.

SPP...................................................

Southwest Power Pool.

STPNOC...........................................

STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of its joint owners including CPL.

SWEPCo...........................................

Southwestern Electric Power Company, an electric utility subsidiary of AEP.

TVA.................................................

Tennessee Valley Authority.

Vale...................................................

Empresa De Electricidade Vale Paranapanema SA, a Brazilian Electric Distribution Company.

VEPCo..............................................

Virginia Electric and Power Company, an unaffiliated utility company.

Virginia SCC....................................

Virginia State Corporation Commission.

West Virginia PSC...........................

Public Service Commission of West Virginia.

West Zone Companies of AEP......... CPL, PSO, SWEPCo and WTU.

WTU.................................................

West Texas Utilities Company, an electric utility subsidiary of AEP.

Zimmer or Zimmer Plant.................. Win. H. Zimmer Generating Station, a 1,300,000-kilowatt coal-fired generating unit commonly owned by CSPCo (25.4%), CG&E (46.5%) and DP&L (28.1%), and operated by CG&E.

ii

[THIS PAGE INTENTIONALLY LEFT BLANK]

FORWARD-LOOKING INFORMATION This reporftmade by AEP and certain of its subsidiaries includes forward-looking Istatements within the meaning of Section'21E of the Securities Exchange Act of 1934. The~e forward-looking statements reflect assumnptions 'and involve a number of iisks and uncertainties. Among the factors that could cause actual results to differ materially from forward-looking statements are:

?? Ele6tric load and customer growth.

?? Abnormal weather conditions.

?? Available sources of and prices for coal and gas.

?? IAvailability of generating capacity.

?? Litigation concei'ning AEP's merger with

CSW.

ýCsw.

?? Th6 timing of the implementation-ofAEP's restructuring plan.

Risks related to energy trading and construction under contract.

?? The speed and degree to which competition is introduced to our power generation

business.

?? The ability to recover net regulatory assets, other'stranded costs and implementation c6sti in connection withi deregulation of geneiation in certain states.

?? New legislation and government regulations.

,?? The structure and timing'of a competitive market for electricity and its impact on prices.

?? The ability of AEP to successfully control its costs.

?? The success of new business ventures.

'? International developments affecting AEP's foreign investments.

?? The effects of fluctuations in foreign currency exchange rates.

2? The economic climate and growth in AEP's service and trading territories, both domestic and foreign.

.? Theability of AEP to comply-with'or to challenge successfully new environmental regulations and to litigate successfully claims that AEP violated the CAA.

?? Inflationary trends.

?? Changes in electricity and gas market prices and interest rates.

?? Other risks and unforeseen events.'

I-

.r 1

PART I Item 1. Business General AEP was incorporated under the laws of the State of New York in 1906 and reorganized in 1925.

It is a public utility holding company which owns, directly or indirectly, all of the outstanding common stock of its domestic electric utility subsidiaries and varying percentages of other subsidiaries.

Substantially all of the operating revenues of AEP and its subsidiaries are derived from the marketing and trading of power and gas and the furnishing of electric service.

The service area of AEP's domestic electric utility subsidiaries covers portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia. The generating and transmission facilities of AEP's subsidiaries are physically interconnected, and their operations are coordinated, as a single integrated electric utility system.

Transmission networks are interconnected with extensive distribution facilities in the territories served. The electric utility subsidiaries of AEP, which do business as "American Electric Power,"

have traditionally provided electric service, consisting of generation, transmission and distribution, on an integrated basis to their retail customers.

At December 31, 2001, the subsidiaries of AEP had a total of 27,726 employees. AEP, as such, has no employees. The operating subsidiaries of AEP are:

APCo (organized in Virginia in 1926) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 917,000 retail customers in the southwestern portion of Virginia and southern West Virginia, and in supplying electric power at wholesale to other electric utility companies and municipalities in those states and in Tennessee.

At December 31, 2001, APCo and its wholly owned subsidiaries had 2,629 employees. Among the principal industries served by APCo are coal mining, primary metals, chemicals and textile mill products. In addition to its AEP System interconnections, APCo also is interconnected with the following unaffiliated utility companies:

Carolina Power & Light Company, Duke Energy Corporation and VEPCo. A comparatively small part of the properties and business of APCo is located in the northeastern end of the Tennessee Valley. APCo has several points of interconnection with TVA and has entered into agreements with TVA under which APCo and TVA interchange and transfer electric power over portions of their respective systems.

CPL (organized in Texas in 1945) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 689,000 customers in southern Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, CPL had 1,374 employees. Among the principal industries served by CPL are oil and gas extraction, food processing, apparel, metal refining, chemical and petroleum refining, plastics, and machinery equipment.

CSPCo (organized in Ohio in 1937, the earliest direct predecessor company having been organized in 1883) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 678,000 customers in Ohio, and in supplying electric power at wholesale to other electric utilities and to municipally owned distribution systems within its service area. At December 31, 2001, CSPCo had 1,222 employees. CSPCo's service area is comprised of two areas in Ohio, which include portions of twenty-five counties. One area includes the City of Columbus and the other is a predominantly rural area in south central Ohio.

Among the principal industries served are food processing, chemicals, primary metals, electronic machinery and paper products. In addition to its AEP System interconnections, CSPCo also is interconnected with the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison Company.

2

1.

I I&M (organized in Indiana in 1925) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 567,000 customers in northern and eastern Indiana and southwestern Michigan, and in supplying electric po4 6 'er at wholesale to other electric utility

-companies, rural electric cooperatives and municipalities. At December 31, 2001, I&M had "2,851 employees. Among the principal industries served are primary metals, transportation equipment,-electrical and electronic machinery, "fabiicated metal products, rubber aid'

-miscellafio-u"plastic products and chemicals and allied products. Since 1975, I&M has leased and operated the aýsets of the municipal system of the City of Fort Wayne, Indiana. In addition to its AEP System interconnections, I&M also is interconnected Writh the following unaffiliated "utility companies:, Central Illinois Public Service Company, CG&E, Commonwealth Edison I

Company, Consumers Energy Company, Illinois Power Company, Indianapolis Power & Light Company, Louisville Gas and Electric Company, NWrthem Inidiana Public Service Company, PSI Energy Inc. and Richmond Power & Light Company.

KEPCo (organized in Kentucky in 1919) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 173,000 customers in an area in eastern Kentucky, and in supplying electric power at wholesale to other utilities and municipalities in Kentucky. At December 31, 2001, KEPCo had 427 employe~s. In addition to its AEP System interconnections, KEPCo also is interconnected

-with the following unaffiliated utility companies:

Kentucky Utilities Company and East Kentucky Power Cooperative Inc. KEPCo is also interconnected with TVA.

Kingsport Power Company (organized in Virginia in 1917) provides electric service to approximately'45,000 customers in Kingsport and eight neighboring communities in northeastern' Tennessee. Kingsport Power Company has no generating facilities of its owffn:'It purchases electric power'distributed to its customers from APCo. At December 31,2001, Kingsp6rt Power Company had 58 employees.

OPCo (organized in Ohio in 1907 and re incorporated in 1924) is engaged in the,

generation, sale, purchase, transmission and distribution of electric power to approximately 698,000 customers in the northwestern, east central, eastern and southern sections of Ohio, and in supplying electric power at wholesale to other electric utility companies and municipalities.- At December 31, 2001, OPCo and its wholly owned subsidiaries had 2,297 employees. Among the principal industries served by OPCo are primary metals, rubber and plastic products, stone, clay, glass and concrete products, petroleum refining and chemicals. In addition to its AEP System interconnections, OPCo also is interconnected with the following unaffiliated utility companies:

CG&E, The Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company, The Toledo Edison Company and West Penn Power Company.

PSO (organized in Oklahoma in 1913) is engaged in the generation, sale, purchase, ý transmission and distribution of electric power to approximately 502,000 customers in eastern and southwestern Oklahoma, and in supplying "

electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 31, 2001, PSO had 989 employees.

Among the principal industries served by PSO are natural gas and oil production, oil refining, steel processing, aircraft maintenance, paper manufacturing and timber products, glass,

!chemicals, cement, plastics, aerospace manufacturing, telecommunications, and rubber goods.

fSWEPCo (organized in Delaware in.1912) is engaged in the generation, sale; purchase, - :

transmission and distribution of electric power to approximately 431,000 customers in northeastern Texas, northwestern Louisiana, and western Arkansas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. -At December 31, 2001, SWEPC6 had 1,375 employees. Among the principal industries served by SWEPCo are natural gas and oil production, petroleum 3

refining, manufacturing of pulp and paper, chemicals, food processing, and metal refining.

The territory served by SWEPCo also includes several military installations, colleges, and universities.

Wheeling Power Company (organized in West Virginia in 1883 and reincorporated in 1911) provides electric service to approximately 41,000 customers in northern West Virginia. Wheeling Power Company has no generating facilities of its own. It purchases electric power distributed to its customers from OPCo. At December 31, 2001, Wheeling Power Company had 64 employees.

WTU (organized in Texas in 1927) is engaged in the generation, sale, purchase, transmission and distribution of electric power to approximately 189,000 customers in west and central Texas, and in supplying electric power at wholesale to other utilities, municipalities and rural electric cooperatives. At December 3 1, 2001, WTU had 689 employees. The principal industry served by WTU is agriculture. The territory served by WTU also includes several military installations and correctional facilities.

Another principal electric utility subsidiary of AEP is AEGCo, which was organized in Ohio in 1982 as an electric generating company. AEGCo sells power at wholesale to I&M and KEPCo.

AEGCo has no employees.

See Item 2 for information concerning the properties of the subsidiaries of AEP.

The Service Corporation provides accounting, administrative, information systems, engineering, financial, legal, maintenance and other services at cost to the AEP System companies. The executive officers of AEP and its public utility subsidiaries are all employees of the Service Corporation.

The AEP System is an integrated electric utility system and, as a result, the member companies of the AEP System have contractual, financial and other business relationships with the other member companies, such as participation in the AEP System savings and retirement plans and tax returns, sales of electricity, transportation and handling of fuel, sales or rentals of property and interest or dividend payments on the secunties held by the companies' respective parents.

AEP-CStVWAerger On June 15, 2000, CSW merged with and into a wholly owned merger subsidiary of AEP with CSW being the surviving corporation. The merger was pursuant to an Agreement and Plan of Merger, dated as of December 21, 1997, that AEP and CSW had entered into. As a result of the merger, each outstanding share of common stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW) was converted into 0.6 of a share of common stock, par value $6.50 per share, of AEP.

CSW's four wholly-owned domestic electric utility subsidiaries are CPL, PSO, SWEPCo and WTU.

AEP is complying or intends to comply with the following conditions imposed by the FERC as part of the FERC's order approving the merger.

2?

Transfer operational control of AEP's east and west transmission systems to fully functioning, FERC-approved regional transmission organizations. See Transmission Services for Non-Affiliates.

?? Two interim transmission-related mitigation measures consisting of market monitoring and independent calculation and posting of available transmission capacity to monitor the operation of AEP's east transmission system. AEP implemented these measures upon the consummation of the merger.

?? Divestiture of 550 MW of generating capacity comprised of 300 MW of capacity in SPP and 250 MW of capacity in ERCOT.

AEP must complete divestiture of the SPP capacity by July 1, 2002. AEP has completed divestiture of the ERCOT capacity.

The FERC found that certain energy sales of SPP and ERCOT capacity would be reasonable and effective interim mitigation measures until completion of the required SPP and ERCOT divestitures. As required by the FERC, the proposed interim energy sales were in effect when the merger was consummated.

4

Litigation: On January 18, 2002, the U.S.

Court of Appeals for the District bf Columbia ruled that the SEC failed to prove that the merger met the requirements of PUHCA and remanded the case to the SEC for frtther review:' The court held that the SEC mus*texplain its'conclusion that the merger met PUHCA r~quirements that uitilities be "physically interconnected" and justify its finding that the merger will result in a combined entity that is confined to a "single area or region."

In its June 2000 ipproval of the merger, the SEC agr~ed 'with AEP that AEP's anid CSW's systems are inter6onbiecied becaiuse they have' transmissi6n access rights to a single high-voltage line through Misiouri and also'meet the PUHCA's single region requirement because it is now "technically possible to centiall, control the output of powei plants across many'states. -In its ruling, the court held that the SEC failed to explain its conclusions that the transmission integration and single region reqtiiiehienis are satisfied.

Managefiient b~lieves that the merger meets the requirements of PUHCA and expects the matter to be resolved fav6rably.

Regulation General AEP and its subsidiaries are subject to the broad regulatory'provisions of PUHCA administered by the'SEC. The public utility

'subsidiaries' retail rates and certain other matters are subject to regulation by the public utility commissions of the states in which they operate.

Such subsidiaries are also subject to regulation by the FERC under the'Federal Power Act in respect of rates for interstate sale at wholesale and transmission of electric power, accounting and other matters and construction and operation of hydroelectric projects. I&M and CPL are subject to regulation by the NRC under the Atomic Energy Act of 1954, as amended, with respect to the operation of the Cook Plant and STP, respectively.

Possible Change to PUHCA The provisions of PUHCA, administered by the SEC, regulate all aspects of a registered holding company system, such as the AEP System. PUHCA requires that the operations of a registered holding company system be limited to a single integrated public utility system and such other businesses as are incidental or necessary to the operations of the system.'In addition; PUHCA governs, among other things, financings, sales or acquisitions of assets and intra-system transactions.

On June 20, 1995, the SEC released a report from its Division of Investment Management recommending a conditional repeal of PUHCA, including its limits on financing and on geographic and business diversification. Specific federal authority, however, would be preserved over access to the books and records of registered holding company systems, audit aithority over registered holding companies and their subsidiaries and oversight over affiliate transactions.,This authority would be transferred to the FERC. Following the report, legislati6n was introduced in Congress to repeal PUHCA and transfer'certain federal authority to the FERC as recommended in the'SEC report.

Since 1997, such PUHCA repeal language has been reintroduced in each session ofCongress both as a separate bill and as part of broader legislation regarding changes in the electric industry.,,

Legislative hearings were held but neither the House of Representatives nor the Senate passed any PUHCA repeal legislation. A number of bills contemplating PUHCA repeal separately and with the restructuring of the electric utility industry have been introduced in the current Congress. See Competition and Business Change. If PUHCA is repealed, registered holding company systems, including the AEP System, will be able to comrpe'te in the chafiging industry without the constrainti of PUHCAI Management of AEP believes that removfal 6f these coristraints,'ýould be beneficial to the AEP System.

PUHCA and the rules and orders'6f the SEC currently ritquire that tralisactions between associated co'npanies in a registered holding company iystem be performed at cost with limited ex~eptiofis.- Over the years, th'eAEP System has developed niiineroiis affiliated e'vice,'sales and construction relationships 5d, in some cases, invested significant capital and developed significant opeiationis in reiiance upon the ability to recover it6 full cokts under these provisions.

5

Conflict of Regulation Public utility subsidiaries of AEP can be subject to regulation of the same subject matter by two or more jurisdictions. In such situations, it is possible that the decisions of such regulatory bodies may conflict or that the decision of one such body may affect the cost of providing service, and so the rates, in another jurisdiction. In a case involving OPCo, the U.S. Court of Appeals for the District of Columbia held that the determination of costs to be charged to associated companies by the SEC under PUHCA precluded the FERC from determining that such costs were unreasonable for ratemaking purposes. The U S. Supreme Court also has held that a state commission may not conclude that a FERC approved wholesale power agreement is unreasonable for state ratemaking purposes. Certain actions that would overturn these decisions or otherwise affect the jurisdiction of the SEC and FERC are under consideration by the U.S. Congress and these regulatory bodies. Such conflicts of jurisdiction often result in litigation and, if resolved adversely to a public utility subsidiary of AEP, could have a material adverse effect on the results of operations or financial condition of such subsidiary or AEP.

Rates The rates charged by the electric utility subsidiaries of AEP are approved by the FERC or one of the state utility commissions as applicable.

The FERC regulates wholesale rates and the state commissions regulate retail rates. In recent years the number of rate increase applications filed by the operating subsidiaries of AEP with their respective state commissions and the FERC has decreased.

Under current rate regulation, if increases in operating, construction and capital costs exceed increases in revenues resulting from previously granted rate increases and increased customer demand, then it may be appropriate for certain of AEP's electric utility subsidiaries to file rate increase applications in the future.

Generally the rates of AEP's operating subsidiaries are determined based upon the cost of providing service including a reasonable return on investment, except for the states of Ohio, Texas and Virginia as noted below. Certain states served by the AEP System allow alternative forms of rate regulation in addition to the traditional cost-of service approach. However, the rates of AEP's operating subsidiaries in those states continue to be cost-based. The IURC may approve alternative regulatory plans which could include setting customer rates based on market or average prices, price caps, index-based prices and prices based on performance and efficiency.

AEP is exposed to risk from changes in the market prices of coal and natural gas used to generate electricity where generation is no longer regulated or where existing fuel clauses are suspended or frozen. The protection afforded by fuel clause recovery mechanisms has either been eliminated by the implementation of customer choice in Ohio (effective January 1, 2001) and in the ERCOT power grid area of Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana, Michigan, and West Virginia. To the extent the fuel supply of the generating units in these states is not under fixed price long-term contracts, AEP is subject to market price risk. AEP continues to be protected against market price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.

AEP cannot predict the timing or probability of approvals regarding applications for additional rate changes, the outcome of action by regulatory commissions or courts with respect to such matters, or the effect thereof on the earnings and business of the AEP System. In addition, current rate regulation may, and in the case of Ohio, Texas and Virginia has been, subject to significant revision. See Competition and Business Change and the footnote to the financial statements entitled Customer Choice and Industry Restructuring.

6 I

Classes of Service The principal classeý of service from whichlthe domestic electric utility subsidiaries of AEP derive AEP system(a)

Wholesale Business:

'Res idenl Commercial.....................................................

Industrial..........................................................

Other Retail Customers.........................................

Energy Deliry..-......:......................................

Total Retai.............................................................

Marketing and Trading-Electricity.............................

Marketing and Trading-Gas......................................

Unrealized MTM Income:.......................................

Electric~~

~~

Other...................

STotal Wholesale Business...................................

Energy Delivery Business'....

Transmission:......

,Distribution.........................................................

,Total Energy Dehve'y...........

Other Investments.:

SEEBOARD....................

CitiPower............

Other.................

Total Other Investments....

Total Revenues...........

S 3,553,216 2,328,383 2,388,354 419,232 (3,356,000) 5,333,185 35,339,641 14,368,857 209,660

,46,990 631,016 55,929,349 1,029,000 2,327,000 3,356,000 1,451,233 349,773 170,645 1,971,6510 revenues and the amount of such revenues during the year ended December 31, 2001 are as follows:

AEGCo APCo,

(in thousands) 0 0

0 0

0 0 227,338 0

0 227,548 20 0*

0, 0

0 0

0 0

1i227.4

$ 587,062 267,312 353,070 77,258 (575.036) 709,666 5,571,750 0

29,334' 0

113644 6,424,394 180,244 394,792 575,036 0

0 0

0 CPL S 660,884 473,337 345,071 49,007 (473.182) 1,055,117 1,671,686 0

19,930 0

101,812 2,848,545

- 162,734 310,448 473,182 0 0 0

0 CSPCo

$ 477,341 426,444 141,583 46,948 (483,219)

S609,097 3,117,136 0

16,730

_0 73,681° S3,816,644 109,824 373,395 483,219 0

0 0

0 SA2929 l&M Wholesale Business Residential.............................,..........

Commercial......

Industrial...............................................................

Other Retail Customers.....

Energy Delivery....................

Total Retail......................

Marketing and Trading-Electricity 2.......

Marketing and Trading-Gas..............

Unrealized MTM Income:..................

Electric........................

Gas.............. L..:.............

Gas.---

Total Wholesale Business.

Energy Delivery Business.

$ 350,600

-218,818 323,157 59,983 (314,410) 638,148 3,783,302 0

0 0

67.765

-4.489,215 Transmission.L-..

2......................

i.,45 Ds buion.....................---.............

192065 Total Energy Delivery.........................

314.410 Other Investments:

SEEBOARD......

0 StiPower........................

0 "Other

-0 Total Other Investm~ients................... :..........

Total Revenues.--------.....

43 KEPCo

$109,882 47,369 92,215 16,058 (134,619) 130,905 1,364,877 0

,0 "0

28,994 1,524,776 53,697 80,922 134,619 0

0 0

0 OPCo PSO (in thousands)

$ 444,418 235,220 526,431 68,968 (552.713) 722,324 4,848,386 0

23,139 0 115,84M 5,709,689 167,399 385,314 552713 0

0 0

0

$ 381,515 305,525 215,038 12,746 (261.877 652,947 1,258,861 0

0 0

27,564 1,939,372 63,045

'1198.832 261.877

-0 0

0 02DL4 SVEIPCo

$ 321,022 226,946 273,096 33,271 (333.004) 521,331 1,653,208 0

10,830 0

56.075

, 2,241,444

'81,324'

' °';251.68 333,004 0

0 0

0 (a)

Includes revenues of other subsidiaries not shown and elimination of mtercompay transactions 7

WTU

$160,520 98,153 60,032 44,318 (169.036) 193,987 648,527 0

4,390 0

48.331

-~895,235 75,443 0

0 0

0

Sale of Power AEP's electric utility subsidiaries own or lease generating stations with total generating capacity of approximately 38,300 megawatts. See Item 2.

Properties, for more information regarding the generating stations. They operate their generating plants as a single interconnected and coordinated electric utility system and, in the east zone, share the costs and benefits in the AEP System Power Pool.

As discussed below under AEP System Power Pool, after corporate separation, the public utility subsidiaries that are no longer regulated at the state level will participate in a separate power pool. Most of the electric power generated at AEP's generating stations is sold, in combination with transmission and distribution services, to retail customers of AEP's utility subsidiaries in their service territories. See Regulation-Rates. Some of the electric power is sold at wholesale to non-affiliated companies.

AEP System Power Pool APCo, CSPCo, I&M, KEPCo 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, KEPCo and OPCo have been parties to the AEP System Interim Allowance Agreement which provides, among other things, for the transfer of SO 2 Allowances associated with transactions under the Interconnection Agreement. As part of AEP's restructuring settlement agreement filed with the FERC, CSPCo and OPCo would no longer be parties to the Interconnection Agreement and certain other modifications to its terms would also be made.

See Competition and Business Change-AEP Restructuring Plan.

Power marketing and trading transactions (trading activities) are conducted by the AEP Power Pool and shared among the parties under the Interconnection Agreement. Trading activities involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and the trading of electricity 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. The regulated physical forward contracts are recorded on a gross basis in the month when the contract settles.

In addition, the AEP Power Pool enters into transactions for the purchase and sale of electricity options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System's traditional marketing area.

The following table shows the net credits or (charges) allocated among the parties under the Interconnection Agreement and Interim Allowance Agreement during the years ended December 3 1, 1999, 2000 and 2001:

APCo............

CSPCo............

I&M............

KEPCo...........

OPCo......

1999(a) 2000(a)

(in thousands)

$(89,100)

$(274,000)

(184,500)

(250,400)

(61,700) 93,900 23,700 (21,500) 311,600 452,000 2001(a)

$(256,700)

(251,200) 166,200 (27,600) 369,300 (a)

Includes credits and charges from allowance transfers related to the transactions.

CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement). The CSW Operating Agreement requires the operating companies of the west zone to maintain specified annual planning reserve margins and requires the subsidiaries that have capacity in excess of the required margins to make such capacity available for sale to other AEP subsidiaries as capacity commitments. The CSW Operating Agreement also delegates to AEP Service Corporation the authority to coordinate the acquisition, disposition, planning, design and construction of generating units and to supervise the operation and maintenance of a central control center. As part of AEP's restructuring settlement agreement filed with the FERC, CPL and WTU would no longer be parties to the CSW Operating Agreement and certain other 8

modifications to its terms would also be made. See Competitioh i'nd Business Change--AEP Restructuring Plan.

WVholesale Sales ofPower to Non-Affiliates AEP's electric utility subsidiaries also sell electric power on a wholesale' basis to' nbn-'affiliated electric utilities and power marketers. Such sales are either inade'(i) by individual corhp6inies pursuant to various long-term power agreements or (ii) under the Interconnection Agreement (AEP Power Pool) or the CSW Operating Agreement.

Sales niade under the Interconnection Agreement are allocated armong the'East Zone subsidiaries based on member-16oad ratios.. Sales made under the CSW Operating Agreement are all6cated among the West Zone-s sidiaries based on participation ratios.

Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to AEP's long term agreements to sell power.

Transmission Services.

,. AEPs electric utility subsidiaries own and operate transmnission and distribution lines and other facilities to deliver electric ibwer. See Item 2 for more nfobrmati 6n'reg'arding the tiransmission and distributin lines. 'AEP's electric utility subsidiaries

.operte-their tranmniiqsion lines as-a single interconnected and coordinated system and share the cost and benefits inthe AEP System Trmsimission Pool. Most of the transmission and distributioii" services are sold, in combination with electric power, to retail cus-tomeir' of AEP's utility subsidiaries in their service territories. These sales are made at rates that are established by the public utility commissions of the state in which' they operate.: See Regulation Rates' -A~s discussed below, some transniission services also are separately sold to non-affiliated companies.

AEP System Transmission Pool APCo, CSPCo, I&M, KEPCo 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." See Sale of Power.

The following table showvs,the n'et (credits) or charges allocatea among the pIrties to the" Transmission Agreement during the years ended December 31, 1999, 2000 and 2001:'

1999 APCo..........

CSPCo.......

I&M............

KEPCo.......

OPCo..........

$( 8,300),

39,000 (43,900)

(4,300) 17,500 2000 (in thousands)

$( 3,400),

38,300 (43,800)

( 6,000)

"14,900 2001

$(3,100)

'40,200 (41,300)

(4,600) 8,800 CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a TranimissionI Coordination Agreement originally dated as of Janiiary 1, 1997 (TCA). 'The TCA establishes a coordinating committee, which is charged with the responsibility of overseeing the oordinated planning of the transmission facilities of th west zone operating subsidia'ies, iichiding the pei'formanrice of transmission planning studies, the'inteifactionf of such subsidiaries with independent system boperit6or (ISO) and other regional bodies interested in transmission planning arid c6rnpliance with the termsof the Open Access Transniission Tiriff (OATT) filed with the FERC and the rules of the FERC relating to such tariff.

Undler'the TCA, th&'%ýest zone opeaiting subsidiai'is have'delegated to AEP Service Corporation the'responsibility of monitoring the reliability of their trarismissiori systems and -*

ridministering the OATr on their behalf. The TCA als6 pioVides for the' allo'cation among the w'st zone operating subsidiaries of revenues collected fof'"

transmission and ancillary services provided under the OATT.

Transmission Services for Non-Affiliates "AEP's electric utility subsidiaries and other System companies also provide traismissioni services foi non2affiliated companies.

9

- I

On April 24, 1996, the FERC issued orders 888 and 889. These orders require each public utility that owns or controls interstate transmission facilities to file an open access network and point-to-point transmission tariff that offers services comparable to the utility's own uses of its transmission system. The orders also require utilities to functionally unbundle their services, by requiring them to use their own tariffs in making off-system and third-party sales. As part of the orders, the FERC issued apro-forma tariff which reflects the Commission's views on the minimum non-price terms and conditions for non discriminatory transmission service. In addition, the orders require all transmitting utilities to establish an Open Access Same-time Information System (OASIS) which electronically posts transmission information such as available capacity and prices, and require utilities to comply with Standards of Conduct which prohibit utilities' system operators from providing non-public transmission information to the utility's merchant employees. The orders also allow a utility to seek recovery of certain prudently incurred stranded costs that result from unbundled transmission service.

In December 1999, FERC issued Order 2000, which provides for the voluntary formation of regional transmission organizations (RTOs), entities created to operate, plan and control utility transmission assets. Order 2000 also prescribes certain characteristics and functions of acceptable RTO proposals.

On July 9, 1996, the AEP System companies filed a tariff conforming with the FERC'spro-forma transmission tariff.

Since 1998 AEP has engaged in discussions with a group of Midwestern utilities regarding the development of the Alliance RTO which may take the form of an ISO or an independent transmission company (Transco), depending upon the occurrence of certain conditions. The Transco, if formed, would operate transmission assets that it would own, and also would operate other owners' transmission assets on a contractual basis.

In 2001 the Alliance companies filed with the FERC a proposed business plan for the Alliance RTO. In December 2001, the FERC issued an order approving the proposal of the Midwest ISO (an independent operator of transmission assets in the Midwest) for an RTO and rejecting the Alliance RTO's business plan and finding that the Alliance RTO lacks sufficient scope and regional configuration to exist as a stand-alone RTO. The FERC directed the Alliance companies to negotiate with the Midwest ISO and others to explore possible combinations. Following such discussions, on March 5, 2002, the Alliance RTO filed with the FERC a request for a declaratory order seeking resolution of these issues.

Coordination of East and West Zone Operating Subsidiaries AEP's System Integration Agreement provides for the integration and coordination of AEP's east and west zone operating subsidiaries, joint dispatch of generation within the AEP System, and the distribution, between the two operating zones, of costs and benefits associated with the System's generating plants. It is designed to function as an umbrella agreement in addition to the AEP Interconnection Agreement and the CSW Operating Agreement, each of which will continue to control the distribution of costs and benefits within each zone for all regulated subsidiaries.

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 zone operating subsidiaries. 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.

?? The allocation of third-party transmission costs and revenues and System dispatch costs.

The Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.

10

If Certain Power Agreements OVEC AEP, CSPCo and several unaffiliated utility companies jointly own OVEC, which supplies the power requirements of a uranium enrichment plant near' Portsmouth, Ohio, 6wnedl by' th6 DOE. The aggregate equity participationi of AEP and CSPCo in OVEC is 44.2%. The aggregate power Iparticipation ratio ofAPCo, CSPCo, I&M and OPCo is 42.1%.

The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs and to provide a return on its equity capital. On September 29, 2000, DOE issued a notice of cancellation of the DOE/OVEC power agreement, such cancellation to be effective no latei than April 30, 2003. In conjunctionwivith'this notice, DOE released all fture rights to OVEC's generating capacity, effective September 1, 2001.IDOE was therefore not entitled to any OVEC capacity beyond August 31,2001, and the sponsoring companies became entitled to receive and pay for all OVEC capacity (approximately 2,200MW) in proportion to their power participation ratios at that time.

Buckeye

_Contractual arrangements among OPCo, Buckeye and other investor-2 owned electric utility companies in Ohio provide for the transmission and delivery,'over ficilities of OPCo and of other investor-bwned utility companies, of power' generated by the two units at the Cardinal Station owned by Buckeye and back-up p'over'to6 which',

Buckeye is entitled fromi OPCo under siich

,contractual arrangemnents, to facilities ownedby 25 of the rural electric cooperatives which operate m the State of Ohio at 337 delivery points.! Buckeye is

'entitled underesuch'aange'ments to receive,' and is obligated to pay for,'the excess of itniir imunum oine hour coincident peak demand Plus a 15% ieserve margin over the 1,226,500 kilowatts of capacity of the generating units which Buckeye currently owns in the Cardinal Station" Such demand, which occurred on August 8, 2001, was recorded at 1,344,315 kilowatts.

Reference is made to Wh-olesaleBusiness Operations -' Structured Arrangements lnvolving Capacity, En'erg', and Ancillary Services for a discussion of'an agreement wvith an affiliate of Buckeye to construct and operate a gas-fired electric generating'pleng facility:.

Century Aluminum Century Aluriiinum of West Virginia, Inc.

(formeily Ravenswood'Jlumiinuni Corporation),.

operates a major iluinifium'ieductibhi plant in the' Ohio River Valley at Riiv~ns',ood, West Virginia.

The power requirement of such plant'pesently is approximately 357,000 kilowatts. OPCo is,

providing electric service pursuant to a contract approved by the PUCO forthe period July 1, 1996 through July 31, 2003.

AEGCo Since its formation in 1982, AEGCo's business has consisted of the owrnership -and fmancing of its

'50% inteiest in the Rockport Plant and, since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The operating jevenues of AEGCo are derived from the sale of capacity'and energy associated w-ith its interest in the Rockport Plant to I&M anid KEPCo pursuant to unit power agreements. Pursuant to these unit power agreements; AEGCo is entitled to recover its full cost of service from thepurchaseis anid will ble entitled to recover fuiture increases in such costs, including increases in fuel and capital 6osts. See Unit Power Agreements. Pursuant to a capital funds agreement, AEP has agre'ed to provide cash' calital contributions, or in certain circumstances suboidinated loans, to AEGCo, to the extent necesIsary to enable AEGCo, among" other thinigs, to pro.idi its p'roportionate share of fuiids required to permit contiruation 6f the commnircial operation of the R6ckport Plant and to perform ail of its obligations, 1ovenanits 'and agrieeiments under, among other things, all'lo6a-i'g'rmenets, leases and related Sdocifteiits to wrhichAEGC6 isobibecbmiis a party.

"Se6 Caipital Fzinds Agieement.

Unit PowverAgreements

-A unit powei adgreeifient between AEGCo and

'I&M (the I&M Po"wer Agreemeht) provides for the sale by.AEGCo to I&M of all the power (and the energy associated ther'ewith) arailable to AEGCo 'at the Rockport Plant. I&M is obligated, whthler oi" 1l

ý I

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) 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 FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the date that the last of the lease terms of Unit 2 of the Rockport Plant has expired unless extended in specified circumstances.

Pursuant to an assignment between I&M and KEPCo, and a unit power agreement between KEPCo and AEGCo, AEGCo sells KEPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KEPCo 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 KEPCo unit power agreement expires on December 31, 2004. As part of AEP's restructuring settlement agreement pending with the FERC, the KEPCo unit power agreement would be extended to December 31, 2009 for Unit 1 and December 7, 2022 for Unit 2. See Competition and Business Change-AEP Restructuring Plan.

Capital Funds Agreement AEGCo and AEP have entered into a capital funds agreement pursuant to which, among other things, AEP has unconditionally agreed to make cash capital contributions, or in certain circumstances subordinated loans, to AEGCo to the extent necessary to enable AEGCo to (i) maintain such an equity component of capitalization as required by governmental regulatory authorities, (ii) provide its proportionate share of the funds required to permit commercial operation of the Rockport Plant, (iii) enable AEGCo to perform all of its obligations, covenants and agreements under, among other things, all loan agreements, leases and related documents to which AEGCo is or becomes a party (AEGCo Agreements), and (iv) pay all indebtedness, obligations and liabilities of AEGCo (AEGCo Obligations) under the AEGCo Agreements, other than indebtedness, obligations or liabilities owing to AEP. The Capital Funds Agreement will terminate after all AEGCo Obligations have been paid in full.

Seasonality Sales of electricity by the AEP System tend to increase and decrease because of the use of electricity by residential and commercial customers for cooling and heating and relative changes in temperature.

Franchises The operating companies of the AEP System hold franchises to provide electric service in various municipalities in their service areas. These franchises have varying provisions and expiration dates. In general, the operating companies consider their franchises to be adequate for the conduct of their business.

Competition and Business Change General The public utility subsidiaries of AEP, like many other electric utilities, have traditionally provided electric generation and energy delivery, consisting of transmission and distribution services, as a single product to their retail customers.

Proposals are being made and/or legislation has been enacted in Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia and West Virginia that would also require electric utilities to sell distribution services separately. These measures generally allow competition in the generation and sale of electric power, but not in its transmission and distribution. However, movement toward retail deregulation in certain of these states is slowing as a consequence of, among other things, adverse developments related to deregulation of the electric industry in California.

Competition in the generation and sale of electric power will require resolution of complex issues, including who will pay for the unused generating plant of, and other stranded costs incurred by, the utility when a customer stops buying power from the utility; will all customers 12

have access to the benefits of competition; how will the rules of competition be established; what will happen to conservation and other regulatory imposed programs; how will the reliability of the transmission system be ensured; and how will the utility's obligation to serve be changed. As competition in generation and sale of electric power is instituted, the public utility subsidiaries of AEP believe that they have a favorable competitive.

position because of their relatively low costs. If stranded costs are not recovered from customers,

,however, the public utility subsidiaries of AEP, like all electric utilities, will be required by existing accounting standards to recognize any stranded

,investment losses.

Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters and the footnote to the financial statements entitled Customer Choice and Industry Restructuring incorporated by reference in Items 7 and 8, respectively, for further information with respect to competition and business change.

AEP Position on'Competition AEP favors freedom for customers to purchase "electricpower from anyone that they choose.

Geneiration' and sale of electric powerwould be in the competitive marketplace. To facilitate reliable, safe and efficient service, AEP supports creation of independent system operators to operate the transmission system in a region of the United States.

AEP's working model for industry'restructuring envision's a progressive transition to full customer choice., Implementation of thes&'neasures would require !egislative changes and regulatory approvals.

The legislatures'and/orthe regulatory commissions in many states' includifg some in AEP's service territory, are considering or have adopted "retail customei choice" which, in general terms, means the transmission by an electric utility of electricpowýer'generate~d by an entity of the customer's choice over its transmission and distributi6n'systen i&6 a retail customer in such utility's seivice teiritory A requirement to transmit directly to retail customers would have the result of permitting retail customers to purchase electric power, at the election of such customers, not only from the electric utility in whose service area they are located but from another electric utility, an independent power producer or an intermediary, such as a power marketer., Although AEP's power generation would have competitors under some of these proposals, its transmission and distribution would not. -As competition develops in retail power generation, the public utility subsidiaries of AEP believe that they should have a favorable competitive position because of their relatively low costs.

nholesale The public utility subsidiaries of AEP, like the electric industry generally, face increasing competition to sell available power on a wholesale basis, primarily to other'public utilities and also to power marketers. The Energy Poli6y Act of 1992 was designed, among other things, to foster competition in the wholesale market (a) throughl amendments to PUHCA, facilitating the ownership and operation of generating facilities by "exempt wholesale generators" (which may include independent power producers as well as affiliates of electric utilities) and (b) through amendments to the Federal Power Act, authorizing the FERC under certain conditions to order utilities which own transmission facilities to provide wholesale transmission services for other utilities and entities generating electric power. The principal factors in competing for such sales are price (including fuel costs), availability of capacity and reliability of service. The public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors.,, '

However, because of the availability of capacity of other utilities and the lower fuel prices in recent years, price competition has been, and is expected for the next few years to be, particularly important.

FERC orders 888 a5d 889, issued in April 1996, provide that utilities must functionally unbundle their transmission'services, by requiring them' to use their own tariffs'in making off-system and third-party _.

sales. See Transmission Services. The public utility subsidiaries of AEP have functionally separated their wholesale power sales from their transmission functions, as required by orders 888 and 889.

13

Retail The public utility subsidiaries of AEP have the exclusive right to sell electric power at retail within their service areas in the states of Arkansas, Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia. Furthermore, while customer choice commenced in Michigan on January 1, 2002, I&M does not have any competing suppliers active in its Michigan service territory at this time. However, AEP's public utility subsidiaries do compete with self-generation and with distributors of other energy sources, such as natural gas, fuel oil and coal, within their service areas. The primary factors in such competition are price, reliability of service and the capability of customers to utilize sources of energy other than electric power. With respect to self generation, the public utility subsidiaries of AEP believe that they maintain a favorable competitive position on the basis of all of these factors. With respect to alternative sources of energy, the public utility subsidiaries of AEP believe that the reliability of their service and the limited ability of customers to substitute other cost-effective sources for electric power place them in a favorable competitive position, even though their prices may be higher than the costs of some other sources of energy.

Significant changes in the global economy in recent years have led to increased price competition for industrial companies in the United States, including those served by the AEP System. Such industrial companies have requested price reductions from their suppliers, including their suppliers of electric power. In addition, industrial companies which are downsizing or reorganizing often close a facility based upon its costs, which may include, among other things, the cost of electric power. The public utility subsidiaries of AEP cooperate with such customers to meet their business needs through, for example, various off peak or interruptible supply options and believe that, as low cost suppliers of electric power, they should be less likely to be materially adversely affected by this competition and may be benefited by attracting new industrial customers to their service territories.

AEP Restructuring Plan As a result of deregulating legislation that has been enacted or is being considered in several of the states in which the AEP public utility subsidiaries provide service, AEP has reassessed the corporate ownership of its public utility subsidiaries' assets.

Deregulating legislation in some of the states requires the separation of generation assets from transmission and distribution assets. On November 1, 2000, AEP filed with the SEC under PUHCA for approval of a restructuring plan in part to meet the requirements of this legislation. This application is pending.

On July 24, 2001, AEP filed with the FERC for approval of the restructuring plan and on December 21, 2001, a settlement agreement with six state regulatory commissions and other major parties was filed with the FERC. The settlement agreement is pending approval. FERC approval is necessary before the SEC will issue its order.

AEP's restructuring plan is designed to align its legal structure and business activities with the requirements of deregulation. AEP's plan contemplates the formation of two first tier subsidiaries that would hold the following public utility assets:

?? A subsidiary would hold the assets of public utility subsidiaries that remain subject to regulation as to rates by at least one state utility commission. AEP intends for this subsidiary ultimately to hold all transmission and distribution assets.

?9 A subsidiary would hold (i) public utility and non-utility subsidiaries that derive their revenues from competitive activity and (ii) foreign utility subsidiaries and other investments.

AEP intends for this subsidiary to ultimately hold all generation assets not subject to regulation.

WPholesale Business Operations AEP's wholesale business operations focus on value-driven asset optimization at each link of the energy chain through the following activities:

?? A diversified portfolio of owned assets and structured third party arrangements, including:

14

?? Power generation facilities and renewable energy sources.

?? Natural gas pipeline, storage and processing facilities.

?? 'oal -mines and relafted facilities.

?? Barge, rail afid other fuel transportation

.related assets.

?? Trade and market energy commodities, including electric power, natural gas, natural gas liquids, oil, coal, and S02 allowances in North America and Europe.

?? 'Prke-riik maniairment iervices anud "liquiditP through a variety of ehiergy-related financial instruments, including exchange "traded futures and oveA-t-counter forward, "option, and swap agreements.

?? Long-term transactions to buy or sell capacity, energy, and ancillary services of electric generating facilities, either existing or to be constructed, at various locations in North America and Europe.

Power. Generation Facilities and Renewable Energy Sources j In addition to approximately 38,300 MW listed under Item 2. Properties, AEP has ownership interests in the generating facilities listed under AEP-Other Generation of approximately 1,900 MW.

domestically and 6,700 MW internationally, of which approximately 1,100 MW is from renewable energy sources.

'Natural Gas Pipeline, Storage andProcessing Facilities In June 2001, AEP acquired Houston Pipe Line Company (HPL) and Lodisco LLC for $727 million from Enron Corp. The acquired assets include: (i) a 4,200-mile intrastate gas pipeline in Texas with,.

capacity of approximately 2.4 billion cubic feet per day; (ii) the exclusive right (for 30 years with an additional 20-year extension) to the underground Bammel Storage Facility (one of the largest natural gas storage facilities in North America) with 118 billion cubic feet of storage capacity and appurtenant pipelines including the Bammel Loop, Houston City Loop and the Texas City Loop; and (iii) certain gas marketing contracts.

AEP ac4uired Louisiana Intrastate Gas Company, LLC ("LIG") in 1998. LIG's midstream gas assets include: (i) a 2,000-mile intrastate gas pipeline in Louisiana with capacity of approximiiately 800 million-cubic feet per day; (ii) five Aatural gas processing plants that straddle the pipeline; And (iii) a ten billion cubic foot' underground natural gas storage facility directly connected to the Henry Hub, one of the most active gas trading areas in North America.

Coal Mines and Related Facilities In October 2001; toenhanc'e its coal trrding and marketing *activities,'AEP acquired substantially all the assets of Quaker Coal Company as part ofa bankruptcy proceeding restructuring.- AEP paid

$101 million to Quaker's creditbrs and assumed additional liabilities of approximately $58 million.'

Tlie acquisition included property, coal reserves, mining operations and royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West Virginia.

AEP will continue to operate the mines and facilities which have approximately.800 employees.

Barge,.Rail and Other Fuel Transportation Related Assets In November 2001, AEP acquired MEMCO Barge Line Inc: foi $270 million as part of its overall isset optimization progiam. MEMCO is engaged in the ti~ankoirtati6n of coal and dry bulk commodities, primarily on'the Ohio, Illinois, and Lower Mississippi rivers.' MEMCO o'vns or leases 1,200 hoppei barges.hnd 30 towboats. The addition of MEMCO's barge assets to AEP's iiisting fleet places AEP among the leading barge operators in' the country. See Fuel Supply-Coal and Lignite for other barges and towboats leased by I&M and OPCo.

Trading and Marketing ofEnergy Commodities Sales: Based upon volumetiic sales in the U.S.,

Power Markets Weekly ranked AEP's wholesale traiirig business No. 2 in electric sales for the first, second and thirdquarters'of 2001. Platts Gas Daily ranked AEP Nos. 14, 10 and 2 in gas sales for thý 15

first, second and third quarters, respectively, of 2001.

ICEM: To gain access to additional liquidity trading points, AEP acquired an interest in the internet-based electronic trading system, Intercontinental Exchange, L.L.C. (ICEX), in 2000 that enables participants to initiate, negotiate, and execute trades in the crude oil, natural gas, and spot and forward energy markets. Other investors include global energy companies and leading investment banking firms.

Structured Arrangements Involving Capacity, Energy, and Ancillary Services AEP has entered into an agreement with The Dow Chemical Company to construct a 900 MW cogeneration facility at Dow's chemical facility in Plaquemine, Louisiana. Commercial operation is expected in 2003. AEP is entitled to 100% of the facility's capacity and energy and has contracted to sell the power from this facility to an unaffiliated party.

In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an affiliate of Buckeye, entered into an agreement relating to construction and operation of a 510 MW gas-fired electric generating peaking facility to be owned by NPC.

From the commercial operation date (expected in 2002) until the end of 2005, OPCo will be entitled to 100% of the power generated by the facility, and responsible for the fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled to 80% and 20%, respectively, of the power of the facility, and both parties will generally be responsible for the fuel and other costs of the facility. OPCo will also provide certain back-up power to NPC.

International Electric Other international holdings of AEP include the following.

Australia: CitiPower Pty. is an electric distribution and retail sales company in Victoria, Australia. CitiPower serves approximately 240,000 customers in the city of Melbourne. With about 3,100 miles of distribution lines in a service area that covers approximately 100 square miles, CitiPower distributes about 4,800 gigawatt-hours annually. AEP acquired CitiPower in 1998 for U.S.S1.1 billion.

UK: SEEBOARD, headquartered in Crawley, West Sussex and acquired as part of AEP's merger with CSW, is one of the 12 regional electricity companies formed as a result of the restructuring and subsequent privatization of the United Kingdom electricity industry in 1990. CSW acquired indirect control of SEEBOARD in April 1996.

SEEBOARD's principal businesses are the distribution and supply of electricity. In addition, SEEBOARD is engaged in other businesses, including gas supply, electricity generation, and electrical contracting. SEEBOARD has approximately 2,000,000 customers and its service area covers approximately 3,000 square miles in Southeast England with the majority of its customers in Kent, Sussex and parts of Surrey.

Possible Divestitures: On February 3, 2002, AEP announced the appointment of investment banks to advise AEP on the prospects for divestment of CitiPower and/or SEEBOARD. Because of pooling of interests accounting restrictions, imposed as part of AEP's merger with CSW and which expire in June 2002, any possible divestment of CitiPower and/or SEEBOARD is not anticipated until after these restrictions lapse.

Pro Serv Pro Serv offers engineering, construction, project management and other consulting services for projects involving transmission, distribution or generation of electric power both domestically and internationally.

AEP Communications AEP Communications markets wholesale, high capacity, fiber optic services, colocation, and wireless tower infrastructure services under the C3 brand with operations in Arkansas, Kansas, Louisiana, Oklahoma and Texas.

AEP Communications joined with several other energy and telecommunications companies to form AFN Communications, LLC. (AFN). AFN is a 16

super regional telecommunications company that provides long haul fiber optic capacity to competitive local exchange carriers, wirelesi' carriers and long distance companies. AFN does business in New-York, Pennsylvania, Virginia, West Virginia, OhioIndiana, Michigan, Illinois, and Kentucky and has approximately 10,000 route niies of fiber optic network.

C3, an entity that was acquired through the merger with CSW, is engaged in providing fiber optic and c6llocation services ini Texas, Louisiana, Oklahoma, Arkansas, and Kansas. C3 does business

,as C3 Networks and has approximately 5,300 route miles of fiber optic network.

Management is evaluating certain of AEP's telicomiriunications investments'for possible disposal.

Construction Program General

,The AEP.Systern is continuously involved in assessing the adequacy of its generation, transmission, distribution and other facilities to plan and provide for the reliable supply of electric power and energy to its customers. In this assessment process, assumptions.are continually being reviewed as new information becomes available, and assessments and plans are modified, as appropriate.

,Thus, System reinforcement plans are subject to change, particularly with the restructuring of the electric utility industiy and the move to increasing competition in the marketplace. See Competition and Business Change.

Generation Committed or anticipated capability changes to the AEP System's generation resources includes the expiration of the Rockport Unit 2 sale of 250 megawatts to Carolina Power & Light Company, an unaffiliated company, on December 31, 2009. See AEP-CSWMerger for a discussion of the divestiture of generating capacity as-part of the merger.

Apart froni these' changes and temporaryi power purchased that caii be' arranged, there are no'specifiý comrnitmefits for additions of new geýn6rition" resources on ihe AEP System. Given'the '

restructuring taking place in the industry, the extent of the need of AEP's operating companies for any iidditional gen'eration resources in the foreseeable' future'is highly uncertain.'-'

Proposed Transmission Facilities On Septnber 30, 1997;,'APCo refiled applications in Virginia and West Virginia fori certificates to build a Wyoming-Cloverdale 765,000 volt Project. The preferrdroutefor this linewas approximately 132 miles in length, con'necting '

APCo's Wyoming Station in southern West Virginiai to APCo's Cloverdale Station near Roanoke, Virginia.

APCo originally aniouncedd this project in 1990. Since then it has been in the process of trying to obtain'federal perinits and'state ceitificates. At the federal level, the U.S. Forest Service (Forest Service) is directing the preparation of an Environmental Impact Statement (EIS), which is required prior to granting permits for crossing lands under federal jurisdiction. Permits are needed from the (i) Forest Service to crossifederal forests, (ii)

Arny Corp's of Engineers to cross the New River and a watershed near the Wyoming Stationl and (iii)

National Park Service or Forest Service to cross the Appalachian National Scenic Trail.

In June 1996, the Forest Service released a Draft EIS and preliminarily 'identified a "No Action Alternative" as its preferred alternative for the original Wyoming-Cloverdale Project. If this alternative were incorporated into a Final EIS, APCo would not be authonze'd to cross federal forests administered by the F6rest Service." The Forest Service stated that it wvnild-rnot prepare ihe-"

Final EIS until after Virginia and West Virginia determined need and routing issues on non-federal lands.

West Virginia: On May 27, 1998, the West

'Virginia PSC issued an 6rder grahnting APCo's application for a certifi&ite'fo construct thý "

Wyoming-Cloverdale 765,000-volt Project. On March 13, 2002, the West Virginia PSC issued an order granting APCo's request to construct the line with a termiinus'at Jacksons Ferry'substation in Virginia instead of th C16overale'substation as discussed below under Virginia.

17

Virginia: Following several procedural delays and Hearing Examiner's rulings, APCo filed a study in May 1999 identifying the Wyoming-Jacksons Ferry Project as an alternative project to the Wyoming-Cloverdale Project. The Jacksons Ferry Project proposes a line from Wyoming Station in West Virginia to APCo's existing 765,000-volt Jacksons Ferry Station in Virginia. APCo estimates that the Wyoming-Jacksons Ferry line would be 90 miles in length, including 32 miles in West Virginia previously certified. In May 2000, the Virginia SCC held an evidentiary hearing to consider both projects. On October 2, 2000, the Hearing Examiner's report to the Virginia SCC recommended approval of the Wyoming-Jacksons Ferry Alternative Project. On May 31, 2001, the Virginia SCC issued an order granting APCo's application for a certificate to construct the Wyoming-Jacksons Ferry 765,000-volt Project.

Proposed Completion Schedule and Estimated Cost: Subsequent to Virginia and West Virginia granting certificates to construct the Project, the Forest Service restarted the EIS process and is scheduled to complete and release a supplement to the Draft EIS in April 2002. The Final EIS process should continue for the balance of 2002, with a decision on the federal permits anticipated in Spring 2003. APCo has also begun required consultation with the U.S. Fish and Wildlife Service under the Endangered Species Act, which should be completed concurrently with the EIS process.

Given the status of the Project permitting process, and assuming that the projected schedule of the EIS process will be met, management estimates that the Wyoming-Jacksons Ferry 765,000-volt Project cannot be completed before Summer 2006.

Depending upon the outcome of the EIS permitting process by the Forest Service, APCo's estimated cost for the Wyoming-Jacksons Ferry Project ranges from $250 to $280 million, assuming a Summer 2006 in-service date.

Construction Expenditures The following table shows construction expenditures during 1999, 2000 and 2001 and current estimates of 2002 construction expenditures, in each case including AFUDC but excluding assets acquired under leases.

1999 Actual AEP System (a).. $1,679,600 AEGCo.......

8,300 APCo......

211,400 CPL.......

255,800 CSPCo.......

115,300 I&M........

165,300 KEPCo.......

44,300 OPCo........

193,900 PSO.........

104,500 SWEPCo.....

112,900 WTU........

52,600 2000 Actual (in

$1,773,400 5,200 199,300 199,500 128,000 171,100 36,200 254,000 176,900 120,200 64,500 2001 Actual housands)

$1,832,000 6,900 306,000 194,100 132,500 91,100 37,200 344,600 124,900 112,100 39,800 2002 Estimate

$1,820,400 45,600 258,200 172,300 145,400 205,400 128,800 349,700 80,600 111,900 51,800 (a)

Includes expenditures of other subsidianes not shown.

Reference is made to the footnote to the financial statements entitled Commitments and Contingencies incorporated by reference in Item 8, for further information with respect to the construction plans of AEP and its operating subsidiaries for the next three years.

The System construction program is reviewed continuously and is revised from time to time in response to changes in estimates of customer demand, business and economic conditions, the cost and availability of capital, environmental requirements and other factors. Changes in construction schedules and costs, and in estimates and projections of needs for additional facilities, as well as variations from currently anticipated levels of net earnings, Federal income and other taxes, and other factors affecting cash requirements, may increase or decrease the estimated capital requirements for the System's construction program.

From time to time, as the System companies have encountered the industry problems described above, such companies also have encountered limitations on their ability to secure the capital necessary to finance construction expenditures.

Environmental Expenditures: Expenditures related to compliance with air and water quality standards, included in the gross additions to plant of the System, during 1999, 2000 and 2001 and the current estimate for 2002 are shown below.

Substantial expenditures in addition to the amounts set forth below may be required by the System in future years in connection with the modification and 18

addition of facilities at generating plants for environmenial'quality controls in order to,6oomply with air and water quality standards which have been 6r may be adopted.

outstanding pollution control revenue bonds issued before August 16, 1986.

NeN, pirojects uidertaken by AEP's unregulated subsidiaries aie geneially, financed through equity funds provided by AEP, non-recoirse debt incurred on a project-specific basis, debt issued by such subsidiaries'or through a combination thereof. See Wholesale Business Operations and Item 7 for additional inform'ation concerning AEP's unregulated subsidiaries.:

1999 2000 2001 2002 Actual.

, Actual Actual Estimate

-i (in thousands)

AEGCo................

8 S'

70 S

3,500-27,700 APCo.........

24,500 2,100 99,200 86,500 CPL...................

(a)

(a) 2,500 200 CSPCo............

10,600 6,600 22,500 25,500 I&M..................

4,500, 1,900 700 28,500 KEPCo........-..........

1900 400 11,200 60,200 OPCo.......................

37,400 91,200 125,300 103,900

-PSO.....................

(a)

(a) 400 400 SWEPCo.............

(a)

(a) 9,200 9,600 NTwU.....

(

a) 8 3000 AEP System (a) :. $78.908 *

$73

,(a)

Amounts not available for west zone companies of AEP prior to AEP-CSW merger.

Financing Itbhas been the practice of AEP's operating subsidiaries to finance current construction expenditures in excess of available internally generated fu'ids by initially issuing unsecured short term debt, principally commercial paper and-bank loans, at times up to levels authorized by regulatory agencies,'and then to reduce the short-term debt

'with the proceeds of subsequent sales by such' subsidiaries of long-'term debt securities and cash'

'cipital contributions by AEP. If onef or more of the subsidiaries are unable to'continue*ethe issuance and siile'of securities on an'orderly basis, such company or companies will be required to consider the curtailment of construction and other outlays or the use of altenative financing arrangements, if available, which may be more costly.

AEP's subsidiaries have'also utilized, and expect to continue to utilize, additional financing arrangements, such as uisecured debt and leasing arrangements, imcluding the leasing of utility asets and coal mining and transportation 6quiprment and facilities. Pollution control'revenue bonds have been used in the past and may be used in the future in'connection with the constructi6n of pollution control facilities; hovwever, Federal tax law has limited the utilization of this type of financing' except for purposes of certain financing of solid waste disposal faclities and of certain'refunding of 19 AEP's revolving credit agreements include covenants and events of default typikal for this type of facility, including a maximum debt/capital test and a $50 millioni cross-acceleration provision. At December 31, 2001, AEP whs in compliance with its debt covenants. With tlhe'ex66ption of-a....

voluntary bankruptcy or insolvency, any event of default has either or both 'cure p-eriod or n6tice requirement before teiininatioii of the aigeemints.'

A voluntary bankruptcy orinsolvency would be considered an immediate teihiiination event.

Reference is made to Management's Discussion and Analysis of Results of Operations and Managenient's Discuýsion and Analysis of Financial Condition, Contingencies and Other

'Mattei-s incoiporated by reference in Item 7 for information with respect to AEP's plans'to restrcticre its debt to implement corporate separation. See Competition and Busineis Change---LAEP Restructudng Plan herein.

Fuel Supply The following table shows the sources'of "power generated by the AEP System:

S"-1997 1998 1999 2000 2001 Coil........

T76%

79%

79%

. 78%

74%

Gas

.12%

14%

15%

13%,

12%

Nuclear..................

8%

3%

3%

5%.

11%

Hydroelectric and other...

4%

4%

3%

4%

3%

"Variations in the generation of nuclear power' are primarilýr related to refueling outages and, in 1997 through 2000, the shutdown of the Cook Plant to respond to issues raised by the NRC.

Natural Gas AEP consumed over 240 billion cubic feet of natural gas during 2001 for the system operating companies. A majority of the gas fired electric generation plants are connected to at least two natural gas pipelines, which provides greater access to competitive supplies and improves reliability.

Natural gas requirements for each plant are supplied by a portfolio of long-tern and short-term purchase and transportation agreements that are acquired on a competitive basis and based on market prices.

Coal and Lignite The Clean Air Act Amendments of 1990 provide for the issuance of annual allowance allocations covering sulfur dioxide emissions at levels below historic emission levels for many coal fired generating units of the AEP System. Phase I of this program began in 1995 and Phase II began in 2000, with both phases requiring significant changes in coal supplies and suppliers. The full extent of such changes, particularly in regard to Phase II, however, has not been determined. See Environmental and Other Matters -

Air Pollution Control -

Title IV Acid Rain Program for the current compliance plan.

In order to meet emission standards for existing and new emission sources, the AEP System companies will, in any event, have to obtain coal supplies by entering into additional supply agreements, either on a long-term or spot basis, at prices and upon terms which cannot now be predicted.

Although AEP believes that in the long run it will be able to secure coal of adequate quality and in adequate quantities to enable existing and new units to comply with emission standards applicable to such sources, no assurance can be given that coal of such quality and quantity will in fact be available.

No assurance can be given either that statutes or regulations limiting emissions from existing and new sources will not be further revised in future years to specify lower sulfur contents than now in effect or other restrictions. See Environmental and Other Matters herein.

The FERC has adopted regulations relating, among other things, to the circumstances under which, in the event of fuel emergencies or shortages, it might order electric utilities to generate and transmit electric power to other regions or systems experiencing fuel shortages, and to rate-making principles by which such electric utilities would be compensated. In addition, the Federal Government is authorized, under prescribed conditions, to allocate coal and to require the transportation thereof, for the use of power plants or major fuel burning installations.

System companies have developed programs to conserve coal supplies at System plants which involve, on a progressive basis, limitations on sales of power and energy to neighboring utilities, appeals to customers for voluntary limitations of electric usage to essential needs, curtailment of sales to certain industrial customers, voltage reductions and, finally, mandatory reductions in cases where current coal supplies fall below minimum levels. Such programs have been filed and reviewed with officials of Federal and state agencies and, in some cases, the state regulatory agency has prescribed actions to be taken under specified circumstances by System companies, subject to the jurisdiction of such agencies.

Western coal purchased by System companies is transported to AEP generating stations by rail and via an affiliated river terminal for subsequent transloading to barges for final delivery. CPL, PSO and SWEPCo own (in the aggregate) 2,982 coal hopper cars and APCo, I&M and OPCo lease (in the aggregate) an additional 4,066 coal hopper cars to be used in unit train movements. I&M and OPCo lease (in the aggregate) 15 towboats, 454 jumbo barges and 143 standard barges. Certain subsidiaries of AEP also own or lease coal transfer facilities at various other locations.

See Wholesale Business Operations-Barge, Rail and Other Fuel Transportation Related Assets herein for information with respect to the acquisition of MEMCO Barge Line Inc. in 2001.

The System generating companies procure coal through purchases pursuant to long-term contracts or spot purchases from affiliated and unaffiliated producers. The following table shows the amount of coal delivered to the AEP System during the past five years, the proportion of such coal which was 20 L__

obtained either from coal-mining subsidiaries, from unaffiliated suppliers under long-term contracts or, through spot or short-term purchases, and the Total coal delivered to AEP operated plants (thousands of tons)............................

Sources (percentage):

Subsidiaries........................................................................

Long-term contracts..............................................................

Spot or short-term purchases.................................................

Average price per ton of spot-purchased coal.........................

(a)

Includes cast zone companies only.

The average cost of coal consumed during the past five sears by all AEP System companies is shown below. AEP System companies' data for average delivered price of spot coal purchased by System commpanies:

1997(a)

L99988(a) 19999(a) 2000 iool 54,292 54,004 54,306 73,259 73,889 14%_

66%

20%

$24.38 14%

66%

20%

$25.05 12%

64%

24%

$27.18 9%

67%

24%

$24.03 4%

68%

28%

$27.30 1997 includes only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.

,,1997 AEP System Com panies....................................................

$ 29.68 AEGCo..........................................................................

19.30 A PCo.............................................................................

36.09 CPL.................................................................................

26.93 CSPCo............................................................................

31.69 I& M..................................................................

23.68 KEPCo............................................................................

26.76 OPCo..............................................................................

36.00 PSO................................................................................

21.11 SWEP~o..................

2.1 SWEPCo..

23.16 WVTU....'.............. :...............................................................

18.19 1997 AEP System Com panies...................................................

140.13 AEGCo...........................................................................

115.21 A PCo.............................................................................

146.54 CPL 136.40 CSPCo...........................................................................

134.44 I& M................................................................................

123.36 K EPCo............... :.............................................................

110.37 O PCo........5........1.66........................................................

151.66 PSO.........................................

120.91 SW EPCo........................................................................

152.79 W

109.13 1998 1999 2000 Dollars per Ton

$29.87

$30.01

$31.39 19.37 20.79 20.65 34.81 33.29 32.84 26.93 26.49 25.95 31.63 29.94 28.50 22.61 24.54 23.44 27.42 26.76 25.35*

38.94 40.56 46.52 20.37 20.94 21.21 j 23.02 21.34 22.59 21.37 21.72 22.26

199_8:.

1999 -',,

2000 Cents per Million BTU's 142.17 141.95 149.12 112.63 116.90 A'116.23'

,141.76, 135.40 134.86,,

"137.00

'135.78 137.86 134.15 127.42 120.83 118.02 A121.90 117.99 112.15

. 109.91:

104.88 164.44 169.23 T'194.77

,116.73 119.54 121.83 "150.62'.143.34 144.96.

126.22 129.13 131.56 21 2001

$ 28.55 21.01 32.41 26.78 30.63 23.57 25.02 35.06 "20.45 24.22 23.81 2001 136.85 118.89 135.88

'140.22 131.64 121.27,

,104.97 146.87

.116.33 153.88 143.21

The coal supplies at AEP System plants vary from time to time depending on various factors, including customers' usage of electric power, space limitations, the rate of consumption at particular plants, labor unrest and weather conditions which may interrupt deliveries. At December 31, 2001, the System's coal inventory was approximately 41 days of normal System usage. This estimate assumes that the total supply would be utilized by increasing or decreasing generation at particular plants.

The following tabulation shows the total consumption during 2001 of the coal-fired generating units of AEP's principal electric utility subsidiaries, coal requirements of these units over the remainder of their useful lives and the average sulfur content of coal delivered in 2001 to these units. Reference is made to Environmental and Other Matters for information concerning current emissions limitations in the AEP System's various jurisdictions and the effects of the Clean Air Act Amendments.

Total Consumption During 2001 (In Thousands of Tons)

Estimated Require ments for Remainder of Useful Lives (In Millions of Tons)

Average Sulfur Content of Delivered Coal Pounds of SOý By Weight Per Million Btu's AEGCo (a)............................

APCo.................................

C PL....................................................

CSPCo.....................................

I&M (c)...........

K EPCo...............................................

OPCo........................

PSO.........................

SW EPCo............................................

WTU.....................................

(a)

Rcflects AEGCo's 50% interest in the Rockport Plant.

(b) Includes coal requirements for CSPCo's interest in Beckjord, Stuart and Zimmcr Plants (c)

Includes I&M's 5001. interest in the Rockport Plant (d) Total does not include OPCo's portion of Spom Plant AEGCo: See Fuel Supply -

I&M for a discussion of the coal supply for the Rockport Plant.

APCo: Substantially all of the coal consumed at APCo's generating plants is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis.

The average sulfur content by weight of the coal received by APCo at its generating stations approximated 0.7% during 2001, whereas the maximum sulfur content permitted, for emission standard purposes, for existing plants in the regions in which APCo's generating stations are located ranged between 0.78% and 2% by weight depending in some circumstances on the calorific value of the coal which can be obtained for some generating stations.

CPL: CPL has coal supply agreements of one year or less duration with two coal suppliers and various coal trading firms for the delivery of approximately 2,400,000 tons of coal for the year 2002. Approximately one half of the coal delivered to Coleto Creek is from Wyoming with the other half from Colorado. Both sources supply low sulfur coal with a limit of 1.2 lbs/MMBtu.

CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the delivery of approximately 3,780,000 tons in 2002. Some of this coal is washed to improve its quality and consistency for use principally at Unit 4 of the Conesville Plant.

CSPCo has been informed by CG&E and DP&L that, with respect to the CCD Group units partly owned but not operated by CSPCo, sufficient coal has been contracted for or is believed to be available for the approximate lives of the respective units operated by them. Under the terms of the operating agreements with respect to CCD Group 22 4,829 10,529 2,470 5,637 7,026 2,981 19,392 4,049 12,254 1,370 215 375 36 213(b) 244 80 546(d) 41 117 32 0.3%

0.7%

0.3%

2.4%

0.6%

0.9%

2.1%

0.4%

0.6%

0.4%

0.7 1.2 0.7 4.1 1.2 1.5 3.5 0.9 1.6 0.8

uhits, each operating company is contractually responsible for obtaining the needed fuel.

"I&M. I&M has histornially received coal under *;o coal supply agreemnents with unaffiliated Wyoming suppliers for low sulfur coal from su'rface mines principally for consumption at the Rockport Plant. As a result of litigation involving future deliveries from one of these gupplieri, there 'will not be anfy coal deliered under this contract in 2002.

Under the other agreement, the supplier will sell to I&M, for consumption by I&M at the Rockport Plant or consignment to other System companies, coal with anr average sulfur content not exceeding 1.2 pounds of sulfur dioxide per million Btu's of heat input.: This contract, which expires on December 31, 2004, has remaining deliveries of approximately 22,800,000 tons.

'All of the 66al'c6nsumed at I&M's Tanners Creek Plant is obtained from unaffiliated suppliers under long-term contracts and/or on a spot purchase basis.

"KEPCo: Sfibstantially all of the coal consumed at KEPCo's Big Sandy Plant is obtained from unaffiliated suppliers under l6ng-term contracts and/or on a spot purchase basis. KEPCo has coal supply agreements with unaffiliated suppliers pursuant to which KEPCo will receive approximately 648,000 tons of coal inr 2002. To'the extent that KEPCo haý additional coal requirements, it may purchase coal from the spot market'and/or suppliers undei coritract to supply other System companies. "

OPCo: The coal consumed at OPCo's generating plants has historicallý beeh supplied from both affiliated -and unaffiliated suppliers. AS a result of the 2001 iale of AEP's coal mines in Ohio and West Virginia and an agreement to purchase approximately 34,000,000 tons of coal through 2008 from the purchaser of the minescoal consumed at

,OPCo's plants in 2002 V'vill be supplied from','

unaffiliated suppliers under l6ng-term contracts' and/or on a spot purchase baiis.'.

PSO: PSO takes all its coal from one'coal supplier under a contract that provides for the entire plant requiremients with at least 16,830,000 ions remaining to be delivered between 2002 and 2007.'

The coal is supplied from Wyoming and has a maximum sulfur'content of 1.2 lbs. SO 2 per.

MMBtu.

SWEPCo: SWEPCo receives coal at its plants under a combination of agixem dnts, including 'ne long-tern c6al contract with'a Wyoming producer, one affiliate'minie-moiith lignite olfeiation and agreements' with various produers'anad coal trading firms. SWEPCo's lohg-tehii coal Supply contract

'provides approxinfately half 6f the requireihnehts for both coal plants. SWEPCo niiist take delivery of

,25,625,000 tons of coal through 2006, with the*

remainder 6f its coail requirements met thr6ugh short-term spot agreemerxis foi low sulfu+ (less ihan 1.2 lbs' S02 per MMBti) coal with various Wyoming coal supplieiis and trading coimip'anies.,

WTUY7 WTU has.ne long-term coal supply contract that provides approximhtely tw5'-thirds of the coal requirements for the-Oklaunion Power Station. This contiract has ippr6ximitely, 9,180,000 tons of coal £remaining to be delivered between 2002 and mid-2006. The remaining coal requirements for Oklaunion are being purchased under short-term agreements with various Wyoming coal suppliers and coal trading firms, with such coal being'low sulfur (less than 1.2 lbs. S02 per MMBtu).

'Nuclear I&M and STPNOC have& made conmmit m-ents to meet certain of the nuclear fuel requirements of the Cook Plant and STP, respectively., Th6 mnclear fuel cycle consists of:

?? Mining and milling of uranium ore to

-uranium concentrates.,

.. Conversion of uranium concentrates to uranium hexafluoiide.

?? Enrichment of uraniurii hexaflu6ride'

'?? Fabrication of fuel assemblies.

?? Utilizatioifoffiuclear'fuel iri the reactor'.

.?? Disposition of spent fuel.

7 Steps currently are being taken, based upon the planned fuel cycles' for theCook Plant, to review and evaluate I&M's requiren'en'ts for'the-supily'of nuclear fuel. I&M has made and will make 23

purchases of uranium in various forms in the spot, short-term, and mid-term markets until it decides that deliveries under long-term supply contracts are warranted.

CPL and the other STP participants have entered into contracts with suppliers for 100% of the uranium concentrate sufficient for the operation of both STP units through Spring 2006 and with an additional 50% of the uranium concentrate needed for STP through Spring 2007. In addition, CPL and the other STP participants have entered into contracts with suppliers for 100% of the nuclear fuel conversion service sufficient for the operation of both STP units through Spring 2003, with additional flexible contracts to provide at least 50% of the conversion service needed for STP through 2008.

CPL and the other STP participants have entered into flexible contracts to provide for 100% of enrichment through Fall 2004, with additional flexible contracts to provide at least 50% of enrichment services through Fall 2008. Also, fuel fabrication services have been contracted for operation through 2028 for Unit 1 and 2029 for Unit

2.

For purposes of the storage of high-level radioactive waste in the form of spent nuclear fuel, I&M has completed modifications to its spent nuclear fuel storage pool. AEP anticipates that the Cook Plant has storage capacity to permit normal operations through 2012.

STP has on-site storage facilities with the capability to store the spent nuclear fuel generated by the STP units over their licensed lives.

The costs of nuclear fuel consumed by I&M and CPL do not assume any residual or salvage value for residual plutonium and uranium.

Nuclear Waste and Decommissioning Reference is made to Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the financial statements and Commitments and Contingencies in the footnotes to these statements that are incorporated by reference in Items 7 and 8, respectively, for information with respect to nuclear waste and decommissioning and related litigation.

The ultimate cost of retiring the Cook Plant and STP may be materially different from estimates and funding targets as a result of the:

?? Type of decommissioning plan selected.

?? Escalation of various cost elements (including, but not limited to, general inflation).

?? Further development of regulatory requirements governing decommissioning.

?? Limited availability to date of significant experience in decommissioning such facilities.

?? Technology available at the time of decommissioning differing significantly from that assumed in these studies.

9? Availability of nuclear waste disposal facilities.

Accordingly, management is unable to provide assurance that the ultimate cost of decommissioning the Cook Plant and STP will not be significantly greater than current projections.

Low-Level Waste: The Low-Level Waste Policy Act of 1980 (LLWPA) mandates that the responsibility for the disposal of low-level waste rests with the individual states. Low-level radioactive waste consists largely of ordinary refuse and other items that have come in contact with radioactive materials. To facilitate this approach, the LLWPA authorized states to enter into regional compacts for low-level waste disposal subject to Congressional approval. The LLWPA also specified that, beginning in 1986, approved compacts may prohibit the importation of low-level waste from other regions, thereby providing a strong incentive for states to enter into compacts.

Michigan, the state where the Cook Plant is located, was a member of the Midwest Compact, but its membership was revoked in 1991. As a result, Michigan is responsible for developing a disposal site for the low-level waste generated in Michigan.

Although Michigan amended its law regarding low-level waste site development in 1994 to allow a 24

volunteer to host a facility, little progress has been made to date. ý A bill was introduced in 1996 to further address the issue but no action was taken.

Development of r~quired legislation and progress with the site selection process has been inhibited by many factors, and management is unable to predict when a new disposal site for Michigan low-level waste will be available.

Texas is a member of the Texas Compact, which includes the states of Maine and Vermont.

Texas had identified a disposal site in Hudspeth County for construction of a low-level waste disposal facility. During the licensing process for the Hudspeth site, that sitewas found to be unsuitable. No additional site has been considered.

Management is unable to predict when a disposal site for Texas low-level waste will be available.

On July l, 1995, the disposal site in South Carolina reopened to accept waste from most areas of the U.S., including Michigan and Texas. This was the first opportunity for the Cook Plant to dispose of low-level waste since 1990. To the extent practicable, the waste formerly placed in storage and thewaste presently generated by the Cook Plant and STP are now being sent to the disposal site.

Under state law, the amounts of low-level.

radioactive waste being disposed of at the South Carolina facility from non-regional generators, such as the Cook Plant and STP, are limited and being reduced. Non-regional access to the South Carolina facility is currently allowed through the end of fiscal year 2008.*

Environmental and Other Matters AEP's subsidiaries aie subject to regulation by federal, state and local authorities with regard to air and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions.

It is expected that:

?? Costs re'lated to envirormaental requirements will eventually be reflected in the rates of AEP's electric utility subsidiaries, or Where states are dei-egulating generation,'unbundled transition period generation rates, stranded cost wires charges and future market prices for electricity.

?? AEP's electric utility subsidiaries will be able to provide for required environmental controls.

However, some customers may curtail or cease operations as aIconsequencý of higher eneirgy.'costs.

There can be no assurance that all such costs will be recovered. Moreov'er, legislation adopted by certain states and proposed at the siiea' and federal level governing restructuring 6fthe electric utilit industry may also affect the recovery of certain costs. See Competition and Business Change.

Except as noted herein,'AEP's subsidiaries that own or operate generating, traismission and distribution facilities are in substantial compliance with pollution'contr6l laws and regula tions.

AEP's inteimnational operations are subject to regulation with res~pect'to air, -waste and witer quality st'anpdds and 6ther environmental matters byvarious authorities Withini the host countries.

Under certain circumnstaifices, ihrese authoirities may "require modificatiouis to these facilities and operations or impose fines and other costs for vi6lations of applicable stitutes,;nd regulations.

From time to tim6, these 6p~i'atirns are -made aware of various environmental issues oi are named as parties to various legal claims,'actionis, complaints or other proceedings related to environmental matters. Management does not expect disposition of any such pending environmental prbceeilings to have a material adverse effect on AEPFs consolidated results of operations or finan'6ial condition.

Reference is made to Management's Discussion and Analysis of Results 6f Operations and Management's Discussion and Analysis of Financial Condition, Continge'n'cies and Other Matters aAd the footnote'to the firLancial statrmefits entitled 25

Commitments and Contingencies incorporated by reference in Items 7 and 8, respectively, for further information with respect to environmental matters, including discussion of legislative proposals under consideration by the Administration and Congress focused on reductions in emissions of CO2, NO.,

S02, mercury and other constituents.

Air Pollution Control For the AEP System operating companies, compliance with the CAA is requiring substantial expenditures that generally are being recovered through the rates of AEP's operating subsidiaries.

Certain matters discussed below may require significant additional operating and capital expenditures. However, there can be no assurance that all such costs will be recovered. See Construction Program -

Construction Expenditures.

Title I National Ambient Air Quality Standards Attainment: In July 1997, Federal EPA revised the ozone and particulate matter National Ambient Air Quality Standards (NAAQS), creating a new eight hour ozone standard and establishing a new standard for particulate matter less than 2.5 microns in diameter (PM2.5). In addition to the potential financial consequences discussed above, both of these new standards have the potential to affect adversely the operation of AEP System generating units. In May 1999, the U.S. Court of Appeals for the District of Columbia Circuit remanded the ozone and PM 2.5 NAAQS to Federal EPA. In February 2001, the U.S. Supreme Court issued an opinion reversing in part and affirming in part the Court of Appeals decision. The Supreme Court remanded the case to the Court of Appeals for further proceedings, including a review of whether adoption of the standards was arbitrary and capricious and directed Federal EPA to develop a policy for implementing the revised ozone standard in conformity with the CAA. The Court of Appeals held oral argument on the remanded issues in December 2001.

NOX SIP Call: In October 1998, Federal EPA issued a final rule (NO, transport SIP call or NO, SIP Call) establishing state-by-state NO. emission budgets for the five-month ozone season to be met beginning May 1, 2003. The NO, budgets originally applied to 22 eastern states and the District of Columbia and are premised mainly on the assumption of controlling power plant NO, emissions projected for the year 2007 to 0.15 lb. per million Btu (approximately 85% below 1990 levels), although the reductions could be substantially greater for certain State Implementation Plans. The SIP call was accompanied by a proposed Federal Implementation Plan, which could be implemented in any state that fails to submit an approvable SIP. The NO, reductions called for by Federal EPA are targeted at coal-fired electric utilities and may adversely impact the ability of electric utilities to construct new facilities or to operate affected facilities without making significant capital expenditures.

In October 1998, the AEP System operating companies joined with certain other parties seeking a review of the final NO. SIP Call rule in the U.S.

Court of Appeals for the District of Columbia Circuit. In March 2000, the court issued a decision upholding the major provisions of the rule. The court subsequently extended the date for submission of SIP revisions until October 30, 2000, and the compliance deadline until May 31, 2004. In March 2001, the U.S. Supreme Court denied petitions filed by industry petitioners, including AEP System operating companies, seeking review of the Court of Appeals decision.

In May 1999 and March 2000, Federal EPA finalized the NO, budget allocations to be implemented through the NO, SIP Call. AEP and other parties filed petitions for review in the U.S.

Court of Appeals for the District of Columbia Circuit and in June 2000 the court issued an opinion remanding the budget determinations for further consideration of certain growth factor assumptions made by Federal EPA. In December 2000, Federal EPA issued a determination that eleven states, including certain states in which AEP System operating companies have sources covered by the NO, SIP Call rule, had failed to submit complying SIP revisions. AEP System operating companies and unaffiliated utilities appealed this determination to the U.S. Court of Appeals for the District of Columbia Circuit and the court has stayed the proceeding pending Federal EPA action on the remand of growth factor issues.

26

In April 2000, the Texas Natural Resouirce ConsercVation Comimissioni adopted rules requiring significant reductions in NO. emissions from utility sources, incliding those of CPL and SWEPCo. The rule cibmiliafice date is May 2003 for CPL and Ma' 2005 for SWEPCo.

Management's estimates indicate that comiplianc6 with the r'vised NO, SIP Call rule, and SIP re'visiolns already adopted, couild result in requiied capital expenditures for'the AEP System of approximately $1.6 billion, of which approximately

$450 million has been expended through Deýember 31,l2001. Reference is made to the footnote io the fma'ncial statements entitled Commitments and Contingencis in6orp*oiated by refeience in Item 8 for information withý respect to AEP registrant - - '

subsidiari6s' 6compliance'cost estimates and amounts exlended.

• In MaM 2001, OPCo completed a $175 million installatio'n' of s'elective catalytic reduction (SCR) technology to reduce NO. emissions on its two-unit 2,600 MW Gavin Plant and, during the 2001 ozone seasofi (iMay'throutig September), operated the SCR units. Construction'of selective catalytic reduction technology o6n Amojs Plant Unit 3, which is jointly owned byOPCo and APCo. and on APCo's Mountaineer Plant, began in 2001. The Amos and Mountaineer projects (expected to be completed in 2002) are esti'Mated to cost a total of $230 million.

Managerment has-undertaken the Gavin, Amos and Mountaineer projects to meet applicable NO.

emiision ieduiction reqcuirements. Additional expenditures of approximately $7 miillion are planrind or undertakýn to address certain operational issues arising during initial operation 6f the Gavin' SCRunits.

Since compliance costs cannotbe estimated with certainty, the actual costs to comply could be significantly different from management's estimates depending upon the compliance alternatives selected to achieve reductions in NO. emissions. Unless capital and operatinj costs 6f ny additional pollution control equipment niec~essary for compliance are recovered from customers through regulated rates and market prices for electricity, they could have a material adverse effect on future results of operations, cash flows and possibly financial condition of AEP and its affected subsidiaries.

Seciion 126 Petiio'ns: In JanuaryX2000, Federal EPA adopted a revised rule granting petitions filed by certain'northeaitem 'states under Secti6n 126 of the CAA. The petitions sought significant reductions in nitrogen oxide emissions from utility and industrial sources. The rule imposed 'emission reduction requirements compapble td theINO. SIP CAl rule beginning May 1, 2003, for most of AEP's coal-fired generating units. Cirtain-AEP System operating companies and other utilities filed petitions for review in the U.S. Court of Aippeals for the District of Columbia Circuit. In May 2001, the court issued an opirioh,which upheld substantially the entire rule: The court did not agree that Federal EPA had properly ýupported the growth factors for the NO. allowanice budgets' 'In August 2001, the court issued an order tolling the Maý 1,2003, "

compliance date pending iesolution of the remand of the growth factor issues. In Jafiiary 2002,'

Federal EPA'advised thai it intends to e tablish May 31, 2004,-as the final compliance date for'the'Irule.,

Cost estimates for *compliance with S~ction 126 are projected to be somewhat less than those-set'forth above for the NO. SIP Call rule reflecting the fact that Section 126 does not apply to AEGCo's and I&M's Rockport Plant.'

West Virginia SO2 Limits. West Virginia' promulgated SO 2 limitations, which'Federl EPA approved in February 1978. The ejiission'"

limitations for OPCo's Mitchell Plant hive been approved by Federal EPA for primary ambient air quality (health-related) Atandards only. West' Virginia is obligated to rianalyze SO 2 emission' limits for the Mitchell Plant with respect to secondary ambient air quality (welfare-related) siandards. Because the CAA providesno 'specific" deadline for approval of emission limits to achieve secondary ambient air quality standards, it is not certain when Federal EPA Will take dispositive action regarding the Mitchell Plant.,':

In August 1994; Fedial EPA issued a Notice of Violattion to OPCo alleging ihat Kanimer Plant was opeiaiing in violation of the applicable federally enforceable SOjemission limit. In May 1996, the, Notice'of Violation and an enforcement action subsequently filed by Federal EPA were resolved through the entrý of a conseint decree in the 1 27

U.S. District Court for the Northern District of West Virginia. Kammer Plant has achieved and maintained compliance with the applicable SO2 emission limit for a period in excess of one year, pursuant to the provisions of the consent decree. In May 2001, the court terminated the consent decree.

Short Term S0 2 Limits: In January 1997, Federal EPA proposed a new intervention level program under the authority of Section 303 of the CAA to address five-minute peak SO 2 concentrations believed to pose a health risk to certain segments of the population. The proposal establishes a "concern" level and an "endangerment" level. States must investigate exceedances of the concern level and decide whether to take corrective action. If the endangerment level is exceeded, the state must take action to reduce SO2 levels. In January 2001, Federal EPA published a Federal Register notice inviting comment with respect to its decision not to promulgate a five-minute S02 NAAQS and intent to take final action on the intervention level program by the summer of 2001.

The effect of this proposed intervention program on AEP operations or financial performance cannot be predicted at this time.

Hazardous Air Pollutants: Hazardous air pollutant (HAP) emissions from utility boilers are potentially subject to control requirements under Title III of the CAAA which specifically directed Federal EPA to study potential public health impacts of HAPs emitted from electric utility steam generating units. In December 2000, Federal EPA announced its intent to regulate emissions of mercury from coal and oil-fired power plants, concluding that these emissions pose significant hazards to public health. A decision on whether to regulate other HAPs emissions from these sources was deferred.

Federal EPA added coal and oil-fired electric utility steam generating units to the list of "major sources" of HAPs under Section 112 (c) of the CAA, which compels the development of "Maximum Achievable Control Technology" (MACT) standards for these units. Listing under Section 112 (c) also compels a preconstruction permitting obligation to establish case-by-case MACT standards for each new or reconstructed source in the category. MACT standards for utility mercury emissions are scheduled to be proposed by December 2003 and finalized by December 2004.

The Utility Air Regulatory Group (which includes AEP System operating companies as members) filed a petition with Federal EPA seeking reconsideration of the decision to regulate mercury emissions from power plants under Section 112(c) of the CAA.

In addition, Federal EPA is required to study the deposition of hazardous pollutants in the Great Lakes, the Chesapeake Bay, Lake Champlain, and other coastal waters. As part of this assessment, Federal EPA is authorized to adopt regulations to prevent serious adverse effects to public health and serious or widespread environmental effects. In 1998, Federal EPA determined that the CAA is adequate to address any adverse public health or environmental effects associated with the atmospheric deposition of hazardous air pollutants in the Great Lakes. The potential impact of adverse developments in these programs on AEP operations or financial performance cannot be predicted at this time.

Title IVAcid Rain Program: The Acid Rain Program (Title IV) of the CAAA created an emission allowance program pursuant to which utilities are authorized to emit a designated quantity of SO2, measured in tons per year.

Phase II of the Acid Rain Program, which affects all fossil fuel-fired steam generating units with capacity greater than 25 megawatts imposed more stringent SO2 emission control requirements beginning January 1, 2000. If a unit emitted SO 2 in 1985 at a rate in excess of 1.2 pounds per million Btu heat input, the Phase II allowance allocation is premised upon an emission rate of 1.2 pounds at 1985 utilization levels. Future SO2 requirements will be met through accumulation or acquisition of allowances, the use of controls or fuels, or a combination thereof. See Fuel Supply-Coal and Lignite.

Title IV of the CAAA also regulates emissions of NO,. Federal EPA has promulgated NO, emission limitations for all boiler types in the AEP System at levels significantly below original design, which were to be achieved by January 1, 2000 on a unit-by-unit or System-wide average basis. AEP sources subject to Title IV of the CAAA are in 28

compliance with the provisions thi~ot.

'Regional Haze: dIn July 1999, Federal EPA, finalized liles to regulate regional haze attributable to anthropogenic emissions.' The primary goal of the'new regional haze progra'm is to address visibility impairment in and around "Class I" protected areas, such as national parks and wilderness-areas. ' Because regional haze precursor emissions are belie'ved by Federal EPA to travel long distances, the rules address the pbtential regulation'of such'precursor emissions in every state. Under the rule, each state must develop a regional haze control program that imposes controls necessary tosteadily reduce visibility impairment in Class I area-os n'the worst days and that ensures that visibility remains good on the best days.- In addition, Federal EPA intends to require Best,

Available Retrofit Technology (BART) for power plants and othei large emission sources constructed between 1962 and 1977.

In January 2001; Federal EPA proposed guidelines for states to use in setting BART emission limits for power plants arid other large emission sources and in determining which sources" are subject to those limits. The proposed rule calls for te~chnologiei which Federal EPA estimates are capable of reducing SO 2 emissions by 90 to 95 percent. The proposed rule also contemplates that other visibility-impairing emissions must be reduced: Emission tiading'piograms could be used in lieu of unit-by-urit BART requirements under the proposal, provided they yield greater visibility improvement and enjission reductions.

The AEP System is a significant emitter of fine particulate matter and other precursors of regional haze and a number of AEP's generating units could be subject to BART. controls. Federal EPA's regional haze rule may have an adverse financial, impact on, AEP as it may trigger the requirement to' install costly new pollution control de&ces to control emissioris of fine particula*te matter and iti',

precurioi's (includiig S02 and NO.). The actual' impact of the regional haze regulations canfiot be determined at this time' 'AEP System 6perating companies and other utilities filed a petition seeking a review of the regional haze rule in the U.S. Court of Appeals for the District of Columbia Circuit in August 1999.

Permitting and Enforcement: The CAAA expanded the enforcement authority of the federal government by:

?? Increasing the range of civil and criminal penalties for violations of the CAA and enhancing administrative civil prov'isions:

? -Imposing a national operating permit

-, system, emissioi fee program and enhanced monitoring, recordkeeling and reporting requirements.

Section 103 of CERCLA'and Section 304 of the Emeigency Planning and Community Right-to-r Know Act require notification to state and federil authorities of releases of reportable quantities (RQs) of hazardous and extremely hazardous substances.

A number of these substances'are emitted by AEP's power plants and othei s6urces.; Until recently,'

emissions of thesesubstances, whither expressly limited in a permit or otherwise subject to fede'al review or waiver (e.g., mercury), were deemed "federally permitted releases" which did not require emergency notification. In December 1999, Fedeial EPA published interim guidance in the Federal Register, which provided that any hazardous' substance-or'extremely hazardous substance'not expressly and individually liinit~d in a lermit must be reported if they are emitted at levels above an RQ. Specifically, constitents of regulated' pollutants (e.g.- metals contained in particulate matter) were not deemed to be federally permitted.

AEP System operatingcompanies hame provided sufpplemental information regarding air releases from their facilities and are submitting follow-up reports. Federal EPA suspended its December 1999 guidance as it considers ceritin revisions to the')

guidance. Settlement discussions regarding the guidance are underway.

Global Clima:te'Change: In Deceruiber 1997, delegates frofn 167-hations, including the U.S.,

agreed to a'treaty, known as the "Kyoto Protocol,"

establishing legally-binding emission reductions for gases s'uspected of ca'u'sing climate change. The' Protocol requires ratification by at least 55 nati6ns that account for'at least 55% of developed countries' 1990 emissions of CO2 to enter into force."

k'Although' the U.S.Isigned the treaty on November 12, 1998, it was not sent to the Senate for

,29

its advice and consent to ratification. In a letter dated March 13, 2001 from President Bush to four U. S. senators, he indicated his opposition to the Kyoto Protocol and said he does not believe that the government should impose mandatory emissions reductions for CO 2 on the electric utility sector.

Despite U.S. opposition to the treaty, at the Seventh Conference of the Parties to the United Nations Framework Convention on Climate Change, held in Marrakech, Morocco in November 200 1, the parties finalized the rules, procedures and guidelines required to facilitate ratification of the treaty by most nations, and entry into force is expected by 2003.

Since the AEP System is a significant emitter of carbon dioxide, its results of operations, cash flows and financial condition could be materially adversely affected by the imposition of limitations on CO2 emissions if compliance costs cannot be fully recovered from customers. In addition, any program to reduce CO 2 emissions could impose substantial costs on industry and society and erode the economic base that AEP's operations serve.

However, it is management's belief that the Kyoto Protocol is highly unlikely to be ratified or implemented in the U.S. in its current form. AEP's 4,000 MW of coal-fired generation in the United Kingdom acquired in 2001 may be exposed to potential carbon dioxide emission control obligations since the U.K. is expected to be a party to the Kyoto Protocol. AEP is developing an emissions mitigation plan for these plants to ensure compliance as necessary.

On February 14, 2002, President Bush announced new climate change initiatives for the U.S. Among the policies to be pursued is a voluntary commitment to reduce the "greenhouse gas intensity" of the economy by 18% within the next ten years. It is anticipated that the Administration will seek to partner with various industrial sectors, including the electric utility industry, to reach this goal. AEP is unable to predict at this time the effect that this program will have upon its operations or financial performance in the future.

New Source Review: In July 1992, Federal EPA published final regulations governing application of new source rules to generating plant repairs and pollution control projects undertaken to comply with the CAA. Generally, the rule provides that plants undertaking pollution control projects will not trigger New Source Review (NSR) requirements.

The Natural Resources Defense Council and a group of utilities, including five AEP System operating companies, filed petitions in the U.S. Court of Appeals for the District of Columbia Circuit seeking a review of the regulations. In July 1998, Federal EPA requested comment on proposed revisions to the New Source Review rules, which would change New Source Review applicability criteria by eliminating exclusions contained in the current regulation. The Administration and Congress are considering initiatives to reform the NSR requirements, but no regulatory revisions have been proposed to date.

New Source Review Litigation: On November 3, 1999, following issuance by Federal EPA of substantial information requests to AEP System operating companies, the Department of Justice (DOJ), on Federal EPA's behalf, filed a complaint in the U.S. District Court for the Southern District of Ohio that alleges AEP made modifications to generating units at certain of its coal-fired generating plants over the course of the past 20 years that extend unit operating lives or restore or increase unit generating capacity without a preconstruction permit in violation of the CAA.

The complaint named OPCo's Cardinal Unit 1, Mitchell, Muskingum River, and Spom plants and I&M's Tanners Creek plant. Federal EPA also issued Notices of Violation to AEP alleging similar violations at certain other AEP plants.

In March 2000, DOJ filed an amended complaint that added allegations for certain of the AEP plants previously named in the complaint as well as counts for APCo's Amos, Clinch River, and Kanawha River plants, CSPCo's Conesville Plant, and OPCo's Kammer Plant. In addition to the allegations regarding New Source Review and New Source Performance Standard violations, DOJ included allegations regarding visible particulate emission violations for Cardinal and Muskingum River plants.

A number of northeastern and eastern states have been allowed to intervene in the litigation, and 30

-1~

a number of special interest groups filed a separate c6mplaint based oii substantially sirrmilar allegations, which has beenf consolidated with the DOJ complaint. -In additi6n to'the plants named by the government ind special interest groups, the intervenor states have included allegations concerning 'OPCo's Gavin Plant.

In May 20.00, AEP~filed a motion to'dismiss with'the'District Court, which, if granted, would dispose of most of the claims of the government and intervenors.

In February 2001, the plaintiffs filed a motion foi partial summary judgment seeking a determination that four projects undertaken on: units at Spre,' Cardinal, and Clinch River Plants do not constitute "routine niaintenmhce*,'repair and replacemnxit" as used nIlthe NSR progIrams. In August 2001, the court issued an order denying the plaintiffs' motion as premature. Management believes its mainteAance, repair and replacement activities were in conformity with the CAA'and initends to vigorou'sly pursue its defensL.

A number of unaffiliated utilities have also received notices of violation, complaints, or administrative orderý relating to NSR. A notice'of violation was issued in June 2000 to DP&L with respect to its ownership interest in Stuart Station, in which CSPCo also &vný a 26 percent interest.' W.C.

Beckjord Unit 6, operated by CG&E, in which CSPCo owns a 12.5 piercent interest, is also the "subject of an enforcement action. Cinergy Corp.;

the parent company of CG&E, has entered into an agreement in principle' with the DOJ in an attemipt to resolve'the litigation relating to W.C. Beckjord Unit 6 and other plants owned or o*perated by Cinergy' and its subsidiarks. This agreement in princijple also covers the Zimmer Plant wýhich has not been the subject of anenforcement action. VEPCo has also entered into a similaf agreement inprinciple.*

Neither CG&E nor VEPCo have reached final agreements with the DOJ. Two other unaffiliated utilities, Tampa Electric Corminy anid PSEG Fossil, LLC, have reached settlements with the Federal government.

InNovember 2000, several eni'iroumental groupg filed a petition with Ohio EPA seeking to',

have the draft Title V operating permits for OPCo's Cardinal and Muskingum River plants as well as the Beckjord Plant and it plant owned by an unaffiliated utility, modified t6 incorporate recquiifments and timetables for compliance with New" Source Review requirements. In December 2000, a petition was filed by these groups with the "A*ministrator of Federal EPA seeking a similar modification'of the final Title V permit for CSPCo's Conesville Plant.

Ohio EPA has refused to consider these petiti0ons outside the'regular Title V permit processing procedures or to interfer& with the resolution of these issues by the District Court.

The CAA'aiithorizes'civil penalties of up to

$27,500 per day per violation at each geneiating unit ($25,000 per da'y prioi to January 30,'1997). In Mrch 2001, the District Couit issued orders

'holding that claims for civil peinalties based on alleged ýactivities that occurred mbre thani five years prior to the filing of the comipliint are barred.'

Although the plaintiffs' claims for injunctive relief are not barred, the court noted that the nature of the' relief ordered may be impacted by the plaintiffs' delay in filing the complaints.

Management is unable to estimate the loss or range of loss related to the contingent liability for

'civil lenalties undei the CAA proceedings and unable to predict the timing 6f resblution of these matters due to the number.of alleged violations and issues td be determined by the court. In the event' the AEP Systemj companies'd6 not prevail, any capital and operating costs'of additional polliiti6n control equipmentthai inay bW required as well as any penalties imposed could miaterially adversely affect futur6 results of operations,'ash'flows iind.

-possibly financialcondition unless such costs can be re6overed'through regulated rates and niarket prices

'f& electricity.

Water Pollution Conti:ol The Cleai WVate A&t prohibits the discharge of lollutanits to' watei bf the United States from point sources' except pursuiant to an' NPDES permit issued by Feddral EPA or i state under a federally authorized state program.

Under the'Clean Water Act; effluent limitations requiring a'pplication otfth6 best available' technology econofnically aclhievable are t6'be-

"31

-- I applied, and those limitations require that no pollutants be discharged if Federal EPA finds elimination of such discharges is technologically and economically achievable.

The Clean Water Act provides citizens with a cause of action to enforce compliance with its pollution control requirements. Since 1982, many such actions against NPDES permit holders have been filed. To date, no AEP System plants have been named in such actions.

All AEP System generating plants are required to have NPDES permits and have received them.

NPDES permit conditions and effluent limitations are reviewed during the permit renewal process.

Under Federal EPA's regulations, operation under an expired NPDES permit is authorized provided an application is filed at least 180 days prior to expiration. Renewal applications are being prepared or have been filed for renewal of NPDES permits that expire in 2002.

The NPDES permits generally require that certain thermal impact study programs be undertaken. These studies have been completed for all System plants. Thermal variances are in effect for all plants with once-through cooling water. The thermal variances for CSPCo's Conesville and OPCo's Muskingum River plants impose thermal management conditions that could result in load curtailment under certain conditions, but the cost impacts are not expected to be significant. Based on favorable results of in-stream biological studies, the thermal limits for both Conesville and Muskingum River plants were raised in the renewed permits issued in 1996. Consequently, the potential for load curtailment and adverse cost impacts was further reduced. In early 2002, AEP submitted a petition to Ohio EPA requesting additional less stringent thermal loading limitations for these plants.

Section 316(b) of the Clean Water Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. Federal EPA issued final regulations defining BTA for new sources that were published in the Federal Register on December 18, 2001. New sources are those commencing construction after January 17, 2002. On February 28, 2002, Federal EPA issued a proposed rule addressing BTA for intake structures at existing plants. This proposal is expected to be published in the Federal Register for comment in April 2002.

Under a previous court-established schedule, Federal EPA is required to issue final regulations for existing plants by August 2003. Federal EPA's rulemaking could result in a definition of BTA that could ultimately require retrofitting of certain existing plant intake structures. Such changes would involve costs for AEP System operating companies, but the significance of these costs cannot be determined at this time.

Certain mining operations conducted by System companies as discussed under Fuel Supply are also subject to federal and state water pollution control requirements, which may entail substantial expenditures for control facilities, not included at present in the System's construction cost estimates set forth herein.

Section 303 of the Federal Clean Water Act requires states to adopt stringent water quality standards for a large category of toxic pollutants and to identify specialized control measures for dischargers to waters where it is shown that water quality standards are not being met. In order to bring these waters back into compliance, total maximum daily load (TMDL) allocations of these pollutants will be made, and subsequently translated into discharge limits in NPDES permits. Federal EPA has also directed that states take action to adopt enhanced anti-degradation of water quality requirements. In October 2001, Federal EPA issued a rule delaying until April 30, 2003, the effective date of its TMDL rule issued in July 2000, the effective date of which had been previously delayed by Congress. Implementation of these provisions could result in significant costs to the AEP System if biological monitoring requirements and water quality-based effluent limits and requirements are placed in NPDES permits.

In March 1995, Federal EPA finalized a set of rules that establish minimum water quality standards, anti-degradation policies and implementation procedures for more stringently controlling releases of toxic pollutants into the Great Lakes system. This regulatory package is called the Great Lakes Water Quality Initiative (GLWQI).

The most direct compliance cost impact could be 32

related to I&M's Cook Plant. Based on Federal EPA's current policy on intake credits and site specific variables and Michigai's implementation strategy, management does not presently expect the GLWQI will have a significant ad&erse impact on Cook Plant'op3erations. If Indiana ýnd Ohio 1

eventually adopt the GLWQI criteria foi statewide application, AEP System plants locatet in those states could be adveisely affected, although the significance depends on the implementation strategy of those states.

1. Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain facilities that, due to oil storage volume,- and location, could reasonably be expected to cause significant and substantial harm to the environment by dischargingjoil. Such facilities must operate urder approved spill response 'plans and implement spill response training and drill programs. OPA imposes substantial penalties for failure to comply: AEP System operating companies v'ith oil handling and storage facilities meeting the OPA criteria have in place required response plans, training and drill programs.

'Solid iand Hazardous Waste Section 311 of the' Clean Water Act impose's substantial penalties for spills of Federal EPA-listed hizaraoiis substances into water and for failure to' report such spills. CERCLA expanded the repbrting requirement to cover the release of hazardous substances generally into the environiment, including water, land and air. 'AEP's subsidiaries itore and Use some of these hazardous substances, including PCBs contained in-certain capacitors and transformers,'but the occurrence and ramifications of a spill or release of such substances cannot be predicted.

CERCLA, RCRA and similar state laws provide'governmental ageiciies with the auithority to require cleanup 'of hazardous waste sites and releases of hazardous substances into the environment and to seek compensation for damages to natural resources ' Since liability under CERCLA is strict, joint and several, 'and cani be applied retroactively, AEP System operating companies which previously disposed of PCB-containing electrical 'e*quipment anid other hazardous substances may be required io pairtieipate inremedial activities at such disposal sites should environmental problems result.

AEP System operating companies are identified as Potentially Responsible Parties (PRPs) for five federal sites where remediation has not been completed, including APCo at one site, CSPCo at one site, I&M at two sites; and OPCo at one site.

AEP has also been named a PRP at two sites under state law. iManagement's present estimates do not inticipate material clean-up costs for identified sites for which AEP subsidiaries have been declared PRPs., In addition,'AEP subsidiary companies are engaged in certain remedial projects at various locations, the costs of which are'not expected to be material. However, if significant costs are incurred for cleanup, future results of operations and possibly financial condition could be adversely affected.

unless the costs can be recovered through rates and/or future market prices for electricity where generation is deregulated.

Regulations issued by Federal EPA under the Toxic Substances Control Act govern the use,, -,

distribution and disposal of PCBs, including PCBs in electrical equipment. Deadlines for removing certain PCB-containing electrical equipment from service have been met.- '

"In addition to handling hazardous substances, the System'companies generate solid waste - !,

associated with the combustion of coal, the vast majority of which is fly ash, bottom ash and flue gas desulfurization wastes. These wastes presently are considered to be non-hazardous under RCRA and applicable state law and the wastes are treated and disposed of in surface impoundments or landfills in accordance with 'state permits or authorization or are beneficially utilized. As required by RCRA, Federal EPA evaluated whether high volume coal combu-stiori wastes (such as fly ash, bottom ash and flue gas desulfurization wastes) should be regulated as hazardous waste. In August 1993, Federal EPA issuied a regulatory determination that such high volume coal combustion wastes should not be regulated as hazardous waste: Federal EPA chose to address separately the issue 'of low volume wastes (such as metal and boiler cleaning wastes) "

associated with burnifig coal and other fossil fuels.

In May 2000, Federal EPA issued a regulatory-,

determination that such low volume wastes are also 33

excluded from regulation under the RCRA hazardous waste provisions when mixed and co managed with high volume fossil fuel combustion wastes.

All presently generated hazardous waste is being disposed of at permitted off-site facilities in compliance with applicable federal and state laws and regulations. For System facilities that generate such wastes, System companies have filed the requisite notices and are complying with RCRA and applicable state regulations for generators. Nuclear waste produced at the Cook Plant and STP and regulated under the Atomic Energy Act is excluded from regulation under RCRA.

Underground Storage Tanks: Federal EPA's technical requirements for underground storage tanks containing petroleum required retrofitting or replacement of an appreciable number of tanks.

Compliance costs for tank replacement were not significant. Some limited site remediation associated with tank removal is ongoing, but these costs are not expected to be significant.

Electric and Magnetic Fields (EMF)

EMF is found everywhere there is electricity.

Electric fields are created by the presence of electric charges. Magnetic fields are produced by the flow of those charges. This means that EMF is created by electricity flowing in transmission and distribution lines, electrical equipment, household wiring, and appliances.

A number of studies in the past several years have examined the possibility of adverse health effects from EMF. While some of the epidemiological studies have indicated some association between exposure to EMF and health effects, the majority of studies have indicated no such association.

The Energy Policy Act of 1992 established a coordinated Federal EMF research program which ended in 1998. In 1999, the National Institute of Environmental Health Sciences (NIEHS), as required by the Act, provided a report to Congress summarizing the results of this program. The report concluded that "the probability that...EMF is truly a health hazard is currently small" and that the evidence that exists for health effects is "insufficient to warrant aggressive regulatory actions."

Nevertheless, the NIEHS identified several areas where further research might be warranted. AEP has supported EMF research through the years and continues to fund the Electric Power Research Institute's EMF research program, contributing over

$400,000 to this program in 2001, and intending to contribute a similar amount in 2002. See Research and Development.

AEP's participation in these programs is a continuation of its efforts to monitor and support further research and to communicate with its customers and employees about this issue.

Residential customers of AEP are provided information and field measurements on request, although there is no scientific basis for interpreting such measurements.

Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. No state which the AEP System serves has done so.

Management cannot predict the ultimate impact of the question of EMF exposure and adverse health effects. If further research shows that EMF exposure contributes to increased risk of cancer or other health problems, or if the courts conclude that EMF exposure harms individuals and that utilities are liable for damages, or if states limit the strength of magnetic fields to such a level that the current electricity delivery system must be significantly changed, then the results of operations and financial condition of AEP and its operating subsidiaries could be materially adversely affected unless these costs can be recovered from ratepayers.

Research and Development AEP and its subsidiaries are involved in over 100 research projects that focus on:

?? Exploring new methods of generating electricity, such as through renewable sources (e.g., wind, solar).

?? Enhancing energy trading infrastructure.

?? Developing more efficient methods of operating generating plants.

34

?? Optimizing and efficiently mahagirig

'generation and other energy-related assets.

Reducing einssions resulting from the burning of fossil fuels (coal and natural gas).

_??

improvink the efficiency', utilization and P reliability of the transmission and

,idlstribution'systems.

??. Exploring the application of new EPRI's members include investor owned and public utilities, independent power producers, international organizations arid others.'

AEP participates in EPRI programs that meet its research and development objectives. Total AEP dues to EPRI were $9,000,000 for 2001, 35$17,000,000 for 2000 and $22,000,000 for 1999. Of these amounts, the former CSW System paid,

approximately $7,000,000 in 2000 and $8,000,000 in 1999 for EPRI programs.

technologies.

APEP System operiting companies are members Total research and development expenditures of the Electric Power Research Institute (EPRI), an by AEP and its subsidiaries, including EPRI dues, organization founded in 1973 that manages science,

were approximately $15,000,000 for 2001, and te-h"nology initiatives on behalf of its members.

$20,000,000 for 2000 and $25,000,000 for 1999.

Item 2.i Properties I

-At December 31,2001, the AEP System owned (or leased where indicated) generating plants with net power capabilities (east zone subsidiaries-winter rating; west zone subsidiaries-summer rating) shown in the followi'ig, table:

Coal Natural Gas Hydro Nuclear Lignite Other Total Company Stations MW MW MW MW MW MW MW AEGCo I 1(a) 1,300 1,300 APCo6 17(b) 5,081 777 1,5,858_'

CPL 12(c)(d) 686

,3,175 6

630 4,497 CSPCo 6(e) 2,595

_-2,595 I&M 10(a) 2,295 11 2,110 4,416 KEPCo 1'

1,060 1,060 OPCo 8(b)(f)

,8,464 48

-842 25(g)

-8,512' PSO 8(c) 1,043 3,169 25(g)

-4,237' SWEPCo 9

1,848

"'1,797 4,487 WTU 12(c) 377 999

'"16(g),.

1,392' Totals:

84 24,749 9,14061 842 2,740 842 41 38,354 (a) -Unit 1 of the Rockport Plant is owfied`666-halfbyjAEGCo and one-half by I&M. Unit 2of the lockport'Plant is leased one-half by AEGCo and one-half by l&M. The leases terminate in 2022 unless extended.

• . v (b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by OPCo.

j (c) CPL, PSO, and WTUjointly own the Oklaunion pbower station. Their respective 6ýnesihip interests ar; iefleeied in this table.

(d) Reflects CPL's interest in STP.

(e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership interest of 1,330 MW is reflected in this table.

(f) The scrubber facilities at the General James M. Gavin Plant are leased. The lease terminates in 2010 unless extended.

(g) PSO and WTU have 25 MW and 10 MW respectively of facilities designed primarily to bum oil. WTU has one 6 MW wind farm facility.

35

AEP-Other Generation: In addition to the generating facilities described above, AEP has ownership interests in other electrical generating facilities, both foreign and domestic. Information concerning these facilities at December 31, 2001 is listed below (except for Bajio which went into commercial operation in March 2002).

Capacity Ownership Facility Fuel Location Total MW Interest Status Brush II Natural gas Colorado 68 47.75%

QF Eastex Natural gas Texas 440 50%

QF Indian Mesa Wind Texas 161 100%

EWG Mulberry Natural gas Florida 120 46.25%

QF Newgulf Natural gas Texas 85 100%

EWG Orange Cogen Natural gas Florida 103 50%

QF Sweeny Natural gas Texas 480 50%

QF Thermo Cogeneration Natural gas Colorado 272 50%

QF Trent Wind Farm Wind Texas 150 100%

EWG Total U.S.

1,879 Bajio Natural gas Mexico 605 50%

FUCO Bakun Hydro Philippines 70 10%

FUCO Codrington Wind Australia 18 20%

FUCO Ferrybridge Coal United Kingdom 2,000 100%

FUCO Fiddler's Ferry Coal United Kingdom 2,000 100%

FUCO Medway Natural gas United Kingdom 675 37.5%

FUCO Nanyang Coal China 250 70%

FUCO Ord Hydro Hydro Australia 30 20%

FUCO Southcoast Natural gas United Kingdom 380 50%

FUCO Vale Hydro/Thermal Brazil 665 (a)

FUCO Victoria Hydro Australia 10 20%

FUCO Total International 6,703 (a)

AEP has varying minority interests which aggregate to 168 MW.

See Item 1 under Fuel Supply for information concerning coal reserves owned or controlled by subsidiaries of AEP and under Wholesale Business Operations for information concerning AEP's natural gas pipeline, storage and processing facilities.

The following table sets forth the total overhead circuit miles of transmission and distnbution lines of the AEP System and its operating companies and that portion of the total representing 765,000-volt lines:

Total OGerhead Circuit Miles or Transmission and Distribution Lines AEP System (a).................

211,300(b)

APCo..........................

51,295 CPL.............

31,210 CSPCo (a)..........

13,703 I&M................... 20,672 KEPCo.........................

10,443 OPCo.............................

29,347 PSO................................

18,713 SWEPCo....................

19,873 WTU..............................

12,605 Circuit Miles of 765,000-%olt Lines 2,023 642 614 258 509 (a)

Includes 766 miles of 345,000-volt jointly owned lines (b) Includes 73 miles of transmission lines not identified with an operating company.

36 L --

Titles The AEP System's electric generating stations' are generally located on lands owned in fee simple.

The greaier portion of the transmission and distribiition lines of the System has been constructed over lands of p'nvate owners pursuant to easements or along public highways anid streets pursuant to' appropriate statutory -uthoirity. The rights-of the

,Sysiem'in'the realty on which its facilities are located are considered by-it t6 be adequate for its" use in tile conduct of its busiriess. Minor defects and irregularitiesIcustomanilyfomund in title to properties of like size and character may exist, but such defects'and irregularities do not materially impair the iise of the properties affe6ted thereby.

Systemcomlpanies gerierally have the right of eminent domain whei~eby they mray, if necessary,-'

.acquire, perfect or secure titles to or easementi on privately-held lands used or to be used in their utility operations.

-i.

' ° Substantially all the fixed physical properties and franchises of the AEP S3stem operating companies, except for limited conditions and limitations, are subject to the'lien 6f the mortgage and deed of trust securing the first mortgage bonds of each such company.

System Transmission Lines and Facility Siting Legisilationhin the'itates of Arkansas, Indiana, Kn6ehtcky,Michigad, Ohio, Texas, Virginia, and West Virgil:ia requires prior approval of sites of generating f~eilitie' and/or r6utes of high-voltage transmissioilin'es: Delays and additional'costs iif constiucting facilities have bein expei'ienced'as a result of proceedings'conduicted pursiiant'tos'sch statutes, as well as in proceedings in which operating companies have sought to acquire rights of-way through condemnition, and such proceedings hiay result in additional delays'and costs in future years.

Peak Demand The east zone system is interconnected through 121 high-voltage transmission interconnections with 25 neighboring electric utility systems. The all-time and 2001 one-hour peak system demands were 25,940,000 and 25,433,000 kilowatts, respectively (which included 7,314,000 and 5,469,000 kilowatts, respectively, of scheduled deliveries to unaffiliated systems which the system might, on appropiriate notice, have elected not to schedule for delivery) and occurred on June 17,' i994 and July 24, 2001,..

respectively. The net dependable capacity to serve the system load on such date, including power available under contractual obligations, was 23,457,000 and 23,974,000 kilowatts, respectively.

The all-time and 2001 one-hour internal peak demand ýras' 20,218,000 kiloiatts, aAd occurred on August 8,' 2001. The ne't dependable capacit~y to serve the system load on such date,' including power dedicated under c6nirictual arrangements, was 23,935,000 kilowatts.. The all-time one-hour integrated and internal net system peak demands and 2001 peak demahds for the east'zone generating subsidiaries are shown in the following tabulation:

All-time one-hour Integrated 2001 oe*'-horintegrated net system peak demand net system peak demand

Numbero(

(in thousands)

-- Number of Number of...,,

Kilowatts

' Date Kilowatts Date APCo........ 8,303 January 17, 1997

-7,750 January 10, 2001 CSPCo... 4,833 July 23,2001 4,833 July 23,2001 "I&M.

5,403 '

June 23, 2001 5,403 July 23,2001 KEPCo...

1,860 January 10, 2001 1,860 January 10, 2001 OPCo....... 7,291 June 17, 1994

' 6,668 July 24,2001 All-time one-hour Integrated 2001 one-hour Integrated

'net Internal peak demand net Internal peak demand (in thousands)

I Number of Number of Kilowatts Date

-Kilowatts Date APCo.

6,908 February 5, 1996 6,402 January 3,2001 CSPCo........ 3,927 August 8,2001 3,927 August 8, 2001 I&M........... 4,232 August 8, 2001 4,232 August 8, 2001 KEPCo....... 1,579 January3,2001 1,579 January3,2001 OPCo......... 5,705 June 11, 1999 5,341 July24,2001

-The all-time and 2001 one-hour internal peak demand for ihlewest zone system was 15,048,000 and 14,648,000 kilowatts, respectively, and occurred on August 31, 2000 and July 23, 2001, respectively. The all-time on0e-hour'inrtemal net system peak demands and 2001 peak demands for the west zone generating siubsidiaries are shown in the following tabulation:

"37

All-time one-hour integrated 2001 one-hour integrated net internal peak demand net internal peak demand (in thousands)

Number of Number of Kilowatts Date Kilowatts Date CPL.....

4,623 September 5, 2000 4,323 June 12,2001 PSO.....

3,823 August 30, 2000 3,785 August 9, 2001 SWEPCo..

4,625 August 31, 2000 4,344 July 18,2001 WTU.U....

1,537 September 5, 2000 1,472 July 19, 2001 Hydroelectric Plants AEP has 18 hydro facilities, of which 16 are licensed through FERC. The license for the Elkhart hydroelectric plant in Indiana was issued in January 2001 and extends for a period of thirty years. The license for the Mottville hydroelectric plant in Michigan expires in 2003 and the application for a new license was filed with FERC in September 2001.

Cook Nuclear Plant and STP The following table provides operating information relating to the Cook Plant and STP.

Year Placed In Operation Year of Expiration of NRC License (b)

Nominal Net Electrical Rating In Kilowatts Cook Plant Unit I Unit 2 STP(a)

Unit I Unit 2 1975 1978 1988 1989 2014 2017 2027 2028 1,020,000 1,090,000 1,250,600 1,250,600 Net Capacity Factors 2001 (c) 873%

83A%

94A%

87.1%

2000 (d) 1 4%

50.0%

78.2%

96.1%

(a)

Reflects total plant.

(b)

For economic or other reasons, operation of the Cook Plant and STP for the full term of their operating licenses cannot be assured.

(c)

The capacity factor for both units of the Cook Plant was significantly reduced in 2001 due to an unplanned dual maintenance outage in September 2001 to implement design changes that improved the performance of the essential service water system (d)

The Cook Plant was shut down in September 1997 to respond to issues raised regarding the operability of certain safety systems.

The restart of both units of the Cook Plant was completed with Unit 2 reaching 100% power on July 5, 2000 and Unit I achieving 100%/0 power on January 3, 2001.

Costs associated with the operation (excluding fuel), maintenance and retirement of nuclear plants continue to be of greater significance and less predictable than costs associated with other sources of generation, in large part due to changing regulatory requirements and safety standards, availability of nuclear waste disposal facilities and experience gained in the construction and operation of nuclear facilities. I&M and CPL may also incur costs and experience reduced output at Cook Plant and STP, respectively, because of the design criteria prevailing at the time of construction and the age of the plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP initiatives have contributed to slowing the growth of operating and maintenance costs at these plants. However, the ability of I&M and CPL to obtain adequate and timely recovery of costs associated with the Cook Plant and STP, respectively, including replacement power, any unamortized investment at the end of the useful life of the Cook Plant and STP (whether scheduled or premature), the carrying costs of that investment and retirement costs, is not assured. See Competition and Business Change.

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 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 allowed to be recovered through rates, could have a material adverse effect on results of operations and the financial condition of AEP, CPL, I&M and other AEP System companies.

Reference is made to the footnote to the financial statements entitled Commitments and Contingencies that is incorporated by reference in Item 8 for information with respect to nuclear incident liability insurance.

38

Item 3. Legal Proceedings Federal EPA Notice of Violation to OPCo: On Xuýugist 31,_2000, Region V, F17ddir1 EPA,'issi-ed a Notice of Violation (NOV) to OPCo's Gavin Plant that alleges violations of the Federal EPA-approved Ohio mass particulate emission limit, opacity, and air pollution nuisance rules. AEP has submitted information in response to the allegations and -

requested a conference to discuss the NOV with Region V representatives.

Ohio EPA Notices of Violation to OPCo: On August 17, 2001, Ohio EPA issued proposed findings and orders to OPCo's Gavin Plant based on the alleged failure of a mass particulate eniissions teit on May 17, 2000. OPCo requested a conference to discuss the proposed findings and orders and f "

submitted the results of its investigation of the test P-%

procedures, which confmnned that the May 17 test -

was invalid duý to the corrosion and disintegration of the test probe.

On December 27, 2001, Ohio EPA issued two NOVs to OPCo's Gavin Plant, alleging that OPCo failed to notify Ohio EPA of a malfunction of the flyash handling system-at the plant, and that OPCo' failed to conduct a required mass particulate emissions test.: OPCo has submitted additional control plans for the flyiashhandling system and information regarding the particulate testing completed at the Gavin Plant in response to the NOVs.

COLILitigation: On February 20,2001,..

the U.S. District Court for the Southern District of Ohio ruled against AEP in its suit against the United States over deductibility of interest claimed by AEP in its consolidated federal income tax return related to its,COLI program. AEP had filed suit to resolfve the IRS' -isseition that interest deductiofns for AEP's COLI program should not be allowed. In 1998 and 1999 AEP paid the disputed taxes and interest i attributable to COLI interest deductions for taxable years 1991-98 to avoid the potential assessment by the IRS of additional interest on the contested tax.

The payments were included in other assets pending the resolution of this'mnatter. 4As h r'esult ofth6 U.S.

District Court's decision to deny the COLI interest "deductions, net income was reduced in 2000 a's follows:

(in millions)

AEP System operating companies......

$ 319

, APCo............................................

82

-CSPCo.......

41 I&M

'466 KEP.....................................

8

-6 SOPCo................

4 i18 The'Comlany has filed an appeal of the U.S.

.,District Couit's decision with the U.S. Court of Appeals for the'Sixth Circuit.

.See Item I for a discussion of certain "environmental matters.

Reference is made to the footnote to the financial statements entitled Commitments'and Contingencies incorporated by reference in Item 8 for Sfiirther informati6n with respect to other legal pioceedings."--

74 4 4

'.4 4

4 4

4.

4- 4 4

'4

- 4 4

(4 4

39 Item

3.

Legal Proceedings

Item 4. Submission of Matters to a Vote of Security Holders AEP, APCo, CPL, I&M, OPCo and SWEPCo. None.

AEGCo, CSPCo, KEPCo, PSO and WTU. Omitted pursuant to Instruction I(2)(c).

Executive Officers of the Registrants AEP. The following persons are, or may be deemed, executive officers of AEP. Their ages are given as of March 1, 2002.

Name Agze Office (a)

E. Linn Draper, Jr..............

60 Chairman of the Board, President and Chief Executive Officer of AEP and of the Service Corporation Thomas V. Shockley, III.... 56 Vice Chairman and Chief Operating Officer of the Service Corporation Henry W. Fayne.................

55 Executive Vice President of the Service Corporation Robert P. Powers...............

48 Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation Susan Tomasky..................

48 Executive Vice President-Policy, Finance and Strategic Planning of the Service Corporation J. H. Vipperman................

61 Executive Vice President-Shared Services of the Service Corporation (a)

All of the executive officers listed above have been employed by the Service Corporation or System companies in various capacities (AEP, as such, has no employees) during the past five years, except for Messrs Powers and Shockley and Ms. Tomasky. Prior tojoining the Service Corporation in July 1998 as Senior Vice President-Generation, Mr Powers was Vice President of Pacific Gas & Electric and plant manager of its Diablo Canyon Nuclear Generating Station (1996-1998) Prior to joining the Service Corporation in July 1998 as Senior Vice President, Ms.

Tomasky was a partner with the law firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the Federal Energy Regulatory Commission (May 1993-August 1997) Mr. Powers and Ms. Tomasky became executive officers of AEP effective with their promotions to Executive Vice President on October 24, 2001 and January 26, 2000, respectively. Prior to joining the Service Corporation in his current position upon the merger %%

ith CSW, Mr. Shockley was President and Chief Operating Officer of CSW (1997-2000) and Executive Vice President of CSW (1990-1997) All of the above officers are appointed annually for a one-year term by the board ofdirectors of AEP, the board of directors of the Service Corporation, or both, as the case may be.

APCo, CPL, I&M, OPCo and SWEPCo. The names of the executive officers of APCo, CPL, I&M, OPCo and SWEPCo, the positions they hold with these companies, their ages as of March 1, 2002, and a brief account of their business experience during the past five years appear below. The directors and executive officers of APCo, CPL, I&M, OPCo and SWEPCo are elected annually to serve a one-year term.

Name Age E. Linn Draper, Jr........... 60 Position (a)(b)

Director of CPL and SWEPCo Chairman of the Board and Chief Executive Officer of CPL and SWEPCo Director of APCo, I&M and OPCo Chairman of the Board and Chief Executive Officer of APCo, I&M and OPCo Chairman of the Board, President and Chief Executive Officer of AEP and the Service Corporation Period 2000-Present 2000-Present 1992-Present 1993-Present 1993-Present 40

Name Age Position (a)(b)

Thomas V.Shockley, III.. 56 "Director/and Vice President of APCo, CPL, I&M, OPCo and SWEPCo Chief Operating Officer° 0ftthe Service Corporation Vice Chairman of AEP and the Service 'Corporation "Presidenit and Chief Operating Officer of CSW "Executive Vice President of CSW Hen*y V Period 2000-Present 2001-Present 2000-Present 1997-2000 1990-1997 V. Fayne...............

55 President of APCo, CPL, I&M,;OPCo and SWEPCo 2001-Presei Director of CPL and SWEPCO 2000-Prese*

Director of APCo 1995-Presei Director of OPCo 1993-Presei

-Director of I&M -

1998-Presei Vice President of CPL and SWEPCo 2000-2001 Vice President of APCo, I&M and OPCo 1998-2001 Vice President of AEP 1998-PreseJ Chief Financial Officer of AEP 1998-2001 Executive Vice President of the Service Corporation 2001-Prese Executive Vice President-Finance and Analysis of the Service Corporation...

.. 2000-2001

,Executive Vice President-Financial Services of the Service Corporation 1998-200 "Senidr Vice President-Corporate P1an"ing& Budgeting of" the Service Corporation 1995-1998 nt nt nt nt nt nt nt Robert P. Po-wers.'......

8 Director and Vice President of APCo, CPL, OPCo and SWEPCo

-*,2001-Present Director of I&M 2001-Present Vice President of I&M 1998-Present Executive Vice President-Nuclear Generation and Technical Services of the Service Corporation -- :- : " !:° 2001-Present Senior Vice President-Nuclear Operations of the Service_

Corporation

. 2000-2001 Senior Vice President-Nuclear Generation of theService I Corporation, 1998-2000 Vice President of Pacific Gas & Electric and Plant Manager., -,-, ':

of its Diablo Canyon Nuclear Generating Station 1996-1998 Susan Tomasky................

48 Director and Vice President of APCo, CPL, I&M, OPCo "and SWEPCo >

2000-Present' Executive Vice President-Policy, Finance and Strategic I.

.Planning of the Service Corporation.

2001-Present

-.Executive Vice President-Legal, Policy and Corporate Communications and General Counsel of the Service

, Corporation 20-0-2001 Senior Vic6 President and General Counsel of the Service Corporation,

1998-2000 Hogan & Hartson (law firn) 1997-1998 General Counsel of the FERC,

1993-1997

-41 7

Name Age J. H. Vipperman............. 61 Position (a)(b)

Director and Vice President of CPL and SWEPCo Director of APCo Director of I&M and OPCo Vice President of APCo, I&M and OPCo Executive Vice President-Shared Services of the Service Corporation Executive Vice President-Corporate Services of the Service Corporation Executive Vice President-Energy Delivery of the Service Corporation Period 2000-Present 1985-Present 1996-Present 1996-Present 2000-Present 1998-2000 1996-1997 (a)

Dr. Draper is a dircctor of BCP Management, Inc., which is the general partncr of Borden Chemicals and Plastics L P (b)

Dr. Draper, Messrs Fayne, Powers, Shockley and Vipperman and Ms Tomasky are directors of AEGCo, CSPCo, KEPCo, PSO and WVTU. Dr Draper and Mr Shockley are also directors of AEP.

PART II Item 5. Market for Registrants' Common Equity and Related Stockholder Matters AEP. The information required by this item is common stock of these companies is held solely by incorporated herein by reference to the material AEP. The amounts of cash dividends on common under Common Stock and Dividend Information in stock paid by these companies to AEP during 2001 the 2001 Annual Report.

and 2000 are incorporated by reference to the material under Statement of Retained Earnings in AEGCo, APCo, CPL, CSPCo, I&M, the 2001 Annual Reports.

KEPCo, OPCo, PSO, SWEPCo and WTU. The Item 6. Selected Financial Data AEGCo, CSPCo, KEPCo, PSO and WTU.

Omitted pursuant to Instruction I(2)(a).

AEP, APCo, CPL, I&M, OPCo and SWEPCo.

The information required by this item is incorporated herein by reference to the material under Selected Consolidated Financial Data in the 2001 Annual Reports.

Item 7. Management's Discussion and Analysis of Results of Operations and Financial Condition AEGCo, CSPCo, KEPCo, PSO and WTU.

Omitted pursuant to Instruction I(2)(a).

Management's narrative analysis of the results of operations and other information required by Instruction I(2)(a) is incorporated herein by reference to the material under Management's Narrative Analysis of Results of Operations in the 2001 Annual Reports.

AEP, APCo, CPL, I&M, OPCo and SWEPCo.

The information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Results of Operations and Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters in the 2001 Annual Reports.

42

1O;15'2002 TUE 23:04 FAX L 002/002 Item 7A. Quantitative and Qualitative Disclosures About Market Risk AEGCo, AEP, APCv, CPL, CSPCo, I&M, Condition. Contingencies and Other Matters in the KEPCo, OFCo, PSO, SWEPCo and WTU. The 2001 Annual Reports.

information required by this item is incorporated herein by reference to the material under Management's Discussion and Analysis of Financial Item 8. Financial Statements and Supplementary Data AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SW.EPCo and WTU. The information required by this item is incorporated

-herein by reference to the financial statements and supplementary data described under Item 14 herein.

Item 9., Changes in and Disagreements with Accountants on Accounting and Financial Disclosure AEGCo, AEP, APCo, CSPCo, I&M, KEPCo and OPCo. None.

CPL, PSO, SWEPCo and WrTU. The information required by this item is incorporated herein by reference to each company's Current Report on Form 8-K dated July 5, 2000.

PARTH I Item 10. Directors and Executive Officers AEGCo, CSPCo, KEPCo, PSO and WTU.

Omitted pursuant to Instruction I(2)(c).

AEP. The information required by this item is incorporated herein by reference to the material under Nomineesfor Director and Section 16(a)

Beneficial Ownership*Reporting Compliance of the definitive proxy statement of AEP for the 2002 annual mcetingof shareholders, to be filed within 120 days after December 31, 2001. Refcrcncc also is made to the information under the caption Executive Officers of thi Registrants in Part I of this report.

APCo and OPCo. The information required by this item is incorporated hercin byireference to the material under Election of Directors of the' definitive information statement'of each" cormpany for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001.

Reference also is made to the infonnation under the of the Registrants caption Executive Offiaers of the Registrants in Part I of this report.

CPL and SWEPCo. The information required by this item is incorporated herein by reference to the material under Election ofDirectors of the definitive information statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001.

Reference also is made to the information under the caption Executive Officers of the Registrants in Part I of this report.'.

I&M. -The names of the directors and executive officers of I&M, the positions they hold with I&M, their aiges'as of March 12, 2002, and a brief account of their business experience during the "past five years appear below and under the caption Executive Officers of the Rcgistrantis in Part I of this report.

43 U 002/002 10/15/2002 TUE 23:0-1 FAX

Name Aae K. G. Boyd........................

John E. Ehler.............

David L. Lahrman.............

Marc E. Lewis.............

Susanne M. Moorman......

John R. Sampson...........

D. B. Synowiec..................

Position (a) 50 Director Vice President - Fort Wayne Region Distribution Operations Indiana Region Manager Fort Wayne District Manager 45 Director Manager of Distribution Systems-Fort Wayne District Region Operations Manager 50 Director and Manager, Region Support Fort Wayne District Manager Region Operations Manager 47 Director Assistant General Counsel of the Service Corporation Senior Counsel of the Service Corporation Senior Attorney of the Service Corporation 52 Director and General Manager, Community Services Manager, Customer Services Operations Director, Customer Services 49 Director and Vice President Indiana State President Indiana & Michigan State President Site Vice President, Cook Nuclear Plant Plant Manager, Cook Nuclear Plant 58 Director Plant Manager, Rockport Plant Period 1997-Present 2000-Present 1997-2000 1994-1997 2001-Present 2000-Present 1997-2000 2001-Present 1997-2001 1994-1997 2001-Present 2001-Present 2000-2001 1994-2000 2000-Present 1997-2000 1994-1997 1999-Present 2000-Present 1999-2000 1998-1999 1996-1998 1995-Present 1990-Present (a)

Positions are with l&M unless otherwise indicated.

Item 11. Executive Compensation AEGCo, CSPCo, KEPCo, PSO and WTU.

Omitted pursuant to Instruction I(2)(c).

AEP. The information required by this item is incorporated herein by reference to the material under Directors Compensation and Stock Ownership Guidelines, Executive Compensation and the performance graph of the definitive proxy statement of AEP for the 2002 annual meeting of shareholders to be filed within 120 days after December 31, 2001.

APCo and OPCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of each company for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 2001.

CPL, I&M and SWEPCo. The information required by this item is incorporated herein by reference to the material under Executive Compensation of the definitive information statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after December 31, 200 1.

44

-1

Item 12. Security Ownership of Certain Beneficial Owners and Management

,AEGCo, CSPCo, KEPCo, PSO and WTU.

Omitted pursuant to Instruction I(2)(c).

AEP. The information required by this item is incorporated herein by reference to the material, under Share Ownership ofDirectors and Executive OJfi6eri. of the definitive proxy statement of AEP for the 2002 annual meeting of shareholders to be filed within 120 days after December 31, 2001.

APCo and OPCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of each company for the 2002 -annual meeting of stockholders, to be filed within 120 days after December 31,2001.

CPL and! SWEPCo. The information required by this item is incorporated herein by reference to the material under Share Ownership of Directors and Executive Officers in the definitive information statement of APCo for the 2002 annual meeting of stockholders, to be filed within 120 days after.

December 31, 2001.

I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M are directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock of I&M generally have no voting rights, except with respect to certain corporate actions and in the event of certain defaults in the payment of dividends on such'shares.

The table below shows the number of shares of AEP Common Stock and stock-based units that were beneficially owned, directly or indirectly, as of

--,'January 1, 2002, by each director and nominee of I&M and each of the executive'officers of I&M named in the summary compensation table, and by all directors anid -executive officers of I&M as a group. It is based on information provided to I&M

'by such persons: No sbch person ownfs any shares of any series of the Cumulative Preferred Stock of I&M. Unless otherwise noted, each persoA has sole voting power and investment power over the number of shares of AEP Common Stock and stock based units set forth opposite his name. Fractions of slhares and units have been rounded to the nearest whole number.,

Stock Name Shares (a)

Units (b)

Karl G. Boyd...................................................................................

6,964 88

-E. Linn Draper, Jr............................

238,274(c) 119,218.

John E. Ehler.....

7

?

Henry W. Fayne.

72,685(d)

-4i3,735

-Davi L. F an....................................................................................

360.

Marc E. Lewis.........................................

1,117

3.

Susanne M. M oorman..............................................................................

841

?

Robert P. Powers......................................................................................

21,269 -.-,

1,209 John IR Sampson......................................................................................

5,525 109 Thomas V! Shockley, III...................................

138,822(d)(e)

' ?

David B. Synowiec...................................................................................

2,361 129 Susan Tomasky........................................................................................

67,322 4,329 Joseph H. Vipperman...............................................................................

-78,043(c)(d) 7,201, All Directors and Executive Officers........

633,590(d)(f)

",146,018 I 1

-I

%2 45 Total 7,052 357,492 7

86,420*

.*360.

1,117 841 22,478 5,634 138,822 2,490 71,651 85,244 779,608

(a)

Includes share equivalents held in the AEP Retirement Sa,,ings Plan (and for Mr. Shockley, the CSW Retirement Savings Plan) in the amounts listed below:

AEP Retirement Savings Name Plan (Share Eq M r. Boyd Dr. Draper.........................

Mr. Ehler.......................

Mr. Fayne...............

Mr. Lahrman.........

Mr. Lewis......................

M s M oorman........

ulvalents) 1,964 4,280 7

5,412 360 1,117 841 AEP Retirement Savings Name Plan (Share Equivalents)

Mr Powers................................

436 Mr. Sampson...............................

525 Mr. Shockley.........................................

6,579 Mr Synowiec......................................

695 Ms. Tomasky..........................

656 Mr. Vipperman.......................................

10,498 All Directors and Executive Officers..............

33,370 With respect to the share equivalents held in the AEP Retirement Savings Plan, such persons have sole voting power, but the investment/disposition power is subject to the terms of the Plan Also, includes the following numbers of shares attributable to options exercisable within 60 days: Mr Boyd, 5,000, Dr. Draper, 233,333; Mr.

Powers, 20,833; Mr. Sampson, 5,000, Mr Shockley, 94,450; Mr. Synowice, 1,666, and Messrs. Fayne and Vipperman and Ms Tomasky, 66,666.

(b)

This column includes amounts deferred in stock units and held under AEP's officer benefit plans.

(c)

Includes the following numbers of shares held in joint tenancy with a family member. Dr. Draper, 661; and Mr. Vipperman, 80.

(d)

Does not include, for Messrs. Fayne, Shockley and Vipperman, 85,231 shares in the American Electric Power System Educational Trust Fund over which Messrs Fayne, Shockley and Vipperman share voting and investment power as trustees (they disclaim beneficial ownership). The amount of shares shown for all directors and executive officers as a group includes these shares (e)

Includes the folloNing numbers ofshares held by family members over which beneficial ownership is disclaimed Mr. Shockley, 496 (0

Represents less than 1% of the total number of shares outstanding Item 13. Certain Relationships and Related Transactions AEP, APCo, CPL, I&M, OPCo and SWEPCo.

AEGCo, CSPCo, KEPCo, PSO and WTU.

None.

Omitted pursuant to Instruction I(2)(c).

PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) The following documents are filed as a part of this report:

1.

FINANCIAL STATEMENTS:

The following financial statements have been incorporated herein by reference pursuant to Item 8.

Pat~e AEGCo:

Independent Auditors' Report; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000 and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Combined Notes to Financial Statements.

AEP and its subsidiaries consolidated:

Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated 46

Pa*e Statements of Cash Flows'for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Common Shareholders' Equity and Comprehensive InCome for the years ended December 31, 2001, 2000, and 1999; Combined Notes to Financial Statements; Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt of Subsidiaries -'

at December 31, 2001 and 2000; Independent Auditors' Reports.

APCo, I&M, and OPCo:

Independent Auditors' Report; Consolidated Statements of Income for the years ended' December 31, 2001, 2000, and 1999; Consolidated Statements of Comprehensive

r.

Income for the years ended Decembei 31, 2001, 2000 1and'1999; C6hnolidaied Balanc-'

S Sheets as of December 31, 2001 and 2000; Consolidated Stateme-nts' of Cash Flows for' the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Retained Earmings for the years ended December 31; 2001; 2000, and 1999;-

r Consolidated Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements.

CPL, CSPCo, PSO, and SWEPCo:

Independent Auditors' Report(s); Consolidated Statements of Income for the years ended December 31, 2001, 2000, and 1999; Consolidated Balance Sheets as of December 31, 2001 and 2000; Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Consolidated Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements.

KEPCo:

Independent Auditors' Report; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Statements of Comprehensive Income for the years ended December 31, 2001, 2000 and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Long-term Debt as of December 31,2001 and 2000; Combined Notes to Financial Statements.

WTqU:

Independent Auditors' Reports; Statements of Income for the years ended December 31, 2001, 2000, and 1999; Statements of Retained Earnings for the years ended December 31, 2001, 2000, and 1999; Statements of Cash Flows for the years ended December 31, 2001, 2000, and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements of Capitalization as of December 31, 2001 and 2000; Schedule of Long-term Debt as of December 31, 2001 and 2000; Combined Notes to Financial Statements.

"47

2.

FINANCIAL STATEMENT SCHEDULES:

Pag~e Financial Statement Schedules are listed in the Index to Financial Statement Schedules (Certain schedules have been omitted because the required information is contained in the notes to financial statements or because such schedules are not required or are not applicable).

S-1 Independent Auditors' Report S-2

3.

ExHIBITS:

Exhibits for AEGCo, AEP, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo and WTU are listed in the Exhibit Index and are incorporated herein by reference E-1 (b) No Reports on Form 8-K were filed during the quarter ended December 31, 2001.

48

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.,.

AMERICAN ELECrRIC POWER COMPANY, INC.

BY:

/s/ SUSAN TOMASKY (Susan Tomasky, Vice President, Secretary and Chief Financial Officer)

Date: March 18, 2002 Pursuant to the requiremients of the Securities Exchange Act of 1934, this report has been signed below by the following personi on behalf of the registrant and in the capacities and on the dates indicated.

Signature Title Date (i)

Principal Executive Officer:

• E. LiNN DRAPER, JR.

Chairman of the Board, President, Chief Executive Officer And Director (ii)

Principal Financial Officer:

/sl SUSAN TOMASKY (Susan Tomasky)

(iii)

Principal Accounting Officer:

I// JOSEPH M. BUONALUTO' (Joseph M. Buonaiuto)

(iv)

A Majority of the Directors:

• E. R. BROOKS

• DONALD M. CARLTON

• JOHN P. DEsBARRES

• • ROBERTW.

FRI,

• WILLIAM R. HOWELL,

• LESTER A. HUDSON, JR.

• LEONARD J. KUJAWA

• JAMES L. POWELL

• PRCHARD L. SANDOR

• THOMAS V. SHOCKLEY, III

• DONALD G. SMITH

• LINDA GILLESPIE STUNTZ

• KATHRYN D. SULLIVAN

• By:

/s/ SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact)

Vice President, Secretary and Chief Financial Officer Controller and Chief Accounting Officer March 18, 2002 March 18, 2002 1/4; SMarch 18, 2002

-49

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.

AEP GENERATING COMPANY APPALACHIAN POWER COMPANY CENTRAL POWER AND LIGHT COMPANY COLUMBUS SOUTHERN POWER COMPANY KENTUCKY POWER COMPANY OHIO POWER COMPANY PUBLIC SERVICE COMPANY OF OKLAHOMA SOUTHWESTERN ELECTRIC POWER COMPANY WEST TEXAS UTILITIES COMPANY BY-

/S/

SUSAN TOMASKY (Susan Tomasky, Vice President)

Date: March 18, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.

Signature Title Date (i)

Principal Executive Officer:

• E. LINN DRAPER, JR.

Chairman of the Board, Chief Executive Officer And Director (ii)

Principal Financial Officer:

/S/ SUSAN TOMASKY (Susan Tomasky)

(iii)

Principal Accounting Officer:

/S/ JOSEPH M. BUONAIUTO (Joseph M. Buonaiuto)

(iv)

A Majority of the Directors:

• HENRY W. FAYNE

• A. A. PENA

• ROBERT P. POWERS

• THOMAS V. SHOCKLEY, III

• J. H. VIPPERMAN

• By:

/sf SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact)

Vice President March 18, 2002 And Director Controller and March 18, 2002 Chief Accounting Officer March 18, 2002 50

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.-

INDIANA MICHIGAN POWER COMPANY

-BY:

/sf-SUSAN TOMASKY S-(Susan Tomasky, Vice President)

Date: March 18, 2002

" Pursuant to the requirements of the Securities Exchange Act of 1934, this r~port has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

The signature of each of the undersigned shall be deemned to'relate only to matters having reference to the above-named company and any subsidiaries thereof.

,Signature (i)

Principal Executive Officer:

• E. LINN DRAPER, JR.

- (ii)

Principal Financial Officer:

/S/ SUSAN TOMASKY (Susan Tomasky)

C (iii)

Principal Accounting Officer:

ISI/JOSEPH M. BUONATUrO (Joseph M. Buonaiuto)

(iv)

A Majority of the Directors:

• K. G. BOYD

• JOHN E. EHLER

• HENRY W. FAYNE

• DAVID L. LAHRMAN

• MARC E. LEWIS

• SUSANNE M. MOORMAN

• ROBERT P. POWERS

• JOHN R. SAMPSON

• THOMAS V. SHOCKLEY, III

• D. B. SYNOWIEC

• J. H. VIPPERMAN Title Chairman of the Board, Chief Executive Officer And Director Vice President

""knd Diredtor Controller and, Chief Accounting Officer Date March 18, 2002 March 18, 2002

• By:

Is/ SUSAN TOMASKY (Susan Tomasky, Attorney-in-Fact)

March 18,2002 151

INDEX TO FINANCIAL STATEMENT SCHEDULES Page INDEPENDENT AUDITORS' REPORT.......................................................................................

S-2 The following financial statement schedules are included in this report on the pages indicated.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule II -

Valuation and Qualifying Accounts and Reserves.............................................

S-3 APPALACHIAN POWER COMPANY AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves..........................................

S-3 CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY Schedule II -

Valuation and Qualifying Accounts and Reserves.............................................

S-3 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves............................................

S-4 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves.............................................

S-4 KENTUCKY POWER COMPANY Schedule II -

Valuation and Qualifying Accounts and Reserves..........................................

S-4 OHIO POWER COMPANY AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves............................................

S-5 PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves......................

S-5 SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES Schedule II -

Valuation and Qualifying Accounts and Reserves.............................................

S-5 WEST TEXAS UTILITIES COMPANY Schedule II -

Valuation and Qualifying Accounts and Reserves..............................................

S-6 S-1

INDhPENDENT AUDITORS' REPORT 1AMERMCAN ELECrRIC POWER COMPANY, INC. ANDSUBSIDIARIES:

We have audited the consolidated financial statements of American Electric Power Company, Inc. and its

subsidiaries and the financial statements of certain of its subsidiaries, listed in It6m/-14 herein, as of December 31,;

-2001 and 2000, and for each of the three years in the period ended December 31, 2001, and have issued our

reports thereon dated February 22,2002; such financial statements and reports are included in the 2001 Annual

,Reports and are incorporated herein by reference. Our audits also included the financial stateinent schedules of

!Americaný Electric Power Company, Inc. and its subsidiaries and of certain of its subsidiaries, listed iin Item 14, except for the financial statemenit schedules of Central Power and Light Company and subsidiary, Public Service Company of Oklahoma and its subsidiaries, Southwestern Electric Power Cormpafi, and 'subsidiaries;,id West 7

,Texas Utilities Company for the year ended December 31, 1999 and the financial information of Central and o

South West Corporation and its subsidiaries that is included in the financial statement schedule for American Electric Power Company, Inc. and its subsidiaries for the year ended December 31, 1999.- hese financiall statement schedules are the responsibility of the respective company's management. Our responsibility is to express an opinion based on our audits.. In our opinion, suchh'fmancial statement ichedules, when considered in relation to the corresponding basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

DELOITrE & ToucHE LLP i Columbus, Ohio February 22, 2002 J.

4 4

4, S-2

Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

9766(a)

$106.589(b)

$109.441 Year Ended December 31, 2000.......

$63.207 707 358(a)

$ 70.513(b)

$71.722 Year Ended December 31, 1999.......

5238.347

$15.802(a)

$ 43,485(b)

$63.207 (a)

Recoveries on accounts previously written off.

(b)

Uncollectible accounts written off.

APPALACHIAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

$2.588 S2.644

$1.017(a)

-4.372(b)

$1.877 Year Ended December 31, 2000......

$2.60

$1.5I2A(a)

$.1239(b) 258 Year Ended December 31, 1999.....

S2234

$5.492 R1,995(a)

$7.112(b)

$2.609 (a)

Recoveries on accounts previously written off (b)

Uncollectible accounts written off.

CENTRAL POWER AND LIGHT AND SUBSIDIARY SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

(a)

$1.65(b)

$186 Year Ended December 31, 2000.......

675

$--(a)

$_-. (b)

$1.675 Year Ended December 31, 1999.......

(a)

(b)

(a)

Rccovcnes on accounts previously written off (b)

Uncollcctible accounts written off S-3 AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES SCHIEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES "SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A, Column B1 Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning.

Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

.Year Ended December 31, 2001.......

-659

$ -(a)

L$

245(b)

$745

-r Year Ended December 31, 2000....

.(a)

$57(b)

'Year Ended December 31, 1999....

$2.598

$3.334

$10.782(a)

$13.669(b)

$3.045 (a)

Recoveries on accounts previously written off.

(b)

Uncolleetille accounts written off.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Balance at Charged to Charged to End of Description Beiing Costs and Other Deductions Period of Period Expenses Accounts (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

$759$

(a)-

86(b) 741

""Year Ended December 31, 2000......

$848 235 97(a)

$1.761(b) 759

-Year Ended December 31, 1999.......

$2.027 3.966

$1.36(a)

$5.512(b) -

$1.848 (a)

Recoveries on accounts previously written off.

(b)

Uncollectible accounts written off.

"KENTUCKY POWER COMPANY SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A' Column B Column C Column D Column E Additions Balance at 7 Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expinses Accounts Deductions Period (In thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

22

$(4a),

$___l(b)

$264 Year Ended December 31, 2000.-.....

$187

$(a)

$ 551(b)

-.$2.

Year Ended December 31, 1999........

$848' 5*1-S 47(a)

" $1.710(b)

_637 (a)

Recoveries on accounts previously written off.

(b)

Uncollectible accounts written off.

S-4

Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

$1.054

$ 554

_(a)

$_229(b)

$1.379 Year Ended December 31, 2000.......

2.223

$ 472

$ 778(a)

$2,419(b)

$1.054 Year Ended December 31, 1999.......

1.678 4.7 S

7(a)

$5.458(b)

$2.22 (a)

Recoveries on accounts previously written off (b)

Uncollectible accounts written off PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

S 467 S

44 (a)

S 467(b)

S 44 Year Ended December 31, 2000.......

S--

$ 467 (a)

(b)

S 467 Year Ended December 31, 1999.......

(a)

S -

(b)

(a)

Recoveries on accounts previously written off.

(b)

Uncollectible accounts written off.

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES SCHEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December31,2001.......

L 911 S

8 a)

$ 911(b)

S-82 Year Ended December 31, 2000.......

S4.428

-$ 911 S(4,428 (a)

L 1 1 (b) 911 Year Ended December 31, 1999.......

(a)

S4.256(b)

$4.42 (a)

Recoveries on accounts previously written off (b)

Uncollectible accounts written off S-5 01110 POWER COMPANY AND SUBSIDIARIES SCIIEDULE II -

VALUATION AND QUALIFYING ACCOUNTS AND RESERVES I

S-6 I,

VEST TEXAS UTILITIES COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES Column A Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End of Description Of Period Expenses Accounts Deductions Period (in thousands)

Deducted from Assets:

Accumulated Provision for Uncollectible Accounts:

Year Ended December 31, 2001.......

$288 1$35(a)

$ 140(b)

Year Ended December 31, 2000.......

$186

$.49

$4(a)

$1.443(b)

Year Ended December 31, 1999.......

4$43(a)

L.2_8(b)

S1_8 (a)

Recoveries on accounts prcviously wnttcn off.

(b)

Uncollectible accounts written off.

EXHIBIT INDEX Certain of the following exhibits, designated with an asterisk(*), are filed herewith. The exhibits not so designated have heretofore been filed with the Commission and, pursuant to 17 C.F.Rt 229.10(d) and 240.12b 32, are incorporated herein by reference to the documents indicated in brackets following the descriptions of such exhibits. Exhibits, designated with a daiger (?), are management contracts or compensatory plans or arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report.

Exhibit Number Description AEGCo 3(a)

Copy of Articles of Incorporation of AEGCo [Registration Statement on Form 10 for the Common Shares of AEGCo, File No. 0-18135, Exhibit 3(a)].

3(b)

Copy of the Code of Regulations of AEGCo (amended as of June 15, 2000) [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 2000, File No. 0-18135, Exhibit 3(b)].

10(a)

Copy of Capital Funds Agreement dated as of December 30, 1988 between AEGCo and AEP [Registration Statement No. 33-32752, Exhibit 28(a)].

10(b)(1)

Copy of Unit Power Agreement dated as of March 31, 1982 between AEGCo and I&M, as amended [Registration Statement No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)].

10(b)(2)

Copy of Unit Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and KEPCo [Registration Statement No. 33-32752, Exhibit 28(b)(2)].

10(b)(3)

Copy of Agreement, dated as of October 1, 1984, among AEGCo, I&M, APCo and Virginia Electric and Power Company [Registration Statement No. 33-32752, Exhibit 28(b)(3)].

10(c)

Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B),

10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B)].

• 13 Copy of those portions of the AEGCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

• 24 Power of Attorney.

AEP?

3(a)

Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997

[Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997, File No. 1-3525, Exhibit 3(a)].

3(b)

Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP, dated January 13, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(b)].

3(c)

Composite copy of the Restated Certificate of Incorporation of AEP, as amended

[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 3(c)].

3(d)

Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)].

• 4(a)

Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee.

E-1

Exhibit Number Description

• 4(b)

First Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee, for 6.125% Senior Notes, Series A, due May 15, 2006.

"*4(c)

Second Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as Trustee, for 5.50% Putable Callable Notes, Series B, Putable Callable May 15, 2003.

10(a)

Interconnection Agreement, dated July, 6, 1951, among APCo, CSPCo, KEPCo, OPCo and I&M and with the Service Corporation, as amended [Registration Statemgnt No. 2 529 10, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1 3525, Exhibit 10(a)(3)].

10(b)

Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report

_on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31,1988, File No. 1-3525, Exhibit 10(b)(2)].

10(c)

Copy of Lease Agreements, dated as of December 1, 1989, between AEGCo or I&M "and Wilmington Trust Company, as amended [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C), 28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and 28(c)(6)(C); Registration Statement No. 33-32753, Exhibits 28(a)(1)(C), 28(a)(2)(C),

28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10 K of AEGCo for the fiscal year ended December 31, 1993, File No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B);

Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993,'

File No. 1-3570, Exhibits 10(e)(1)(B)-, 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B),

10(e)(5)(B) and 10(e)(6)(B)].

, 1 11 10(d)

L Lease Agreement dated January 20, 1995 between OPCo and JMG Funding, Linited Partnership, and amendmefit thereto (confidential treatment reqluested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31,1994, File No. 1;6543, Exhibit 10(l)(2)].

10(e)

Modification No. 1 to the AEP Sysitm Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation S[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996,'

File No. 1-3525, Exhibit 10(1)].

10(f)(1)

Agreement and Plan of Merger, dated as of'Dece6mber 21,1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation,[Annual Report on Form 10-K 0f AEP for the fiscal year ended December 31,1J997, File No. 1-3525,'Exhibit 10(0].

10(0(2)

AmendmentNo. 1, dated as of December'31, 1999, to the Agreement and Plan of Merger [Current Rejirton Forhi 8-K of AEP dated December 15, 1999, File No. 1 3525, Exhibit 10].

? 10(g)(1)

AEP Deferred Compensation Agreement foi certain executive officers [Annual Report on Fori 10-K of AEP for the fiscal ye'ar en'ded Decermber'31,1985, File No. 1-3525, Exhibit 10(e)].....gr ment

? 10(g)(2)

Amendment to AEP Deferred Compensation Agreement for erftain executive officers

[Annual Report on Form 10-K of AEP for tlie'fiscal yeha ended Deceinber 31, 1986, File No. 1-3525, Exhibit 10(d)(2)].

? 10(h)

AEP Accident Coverage Insurance Plan for directors [Afiriual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(g)].

E-2

Exhibit Number

? 10(i)(1)

• ?10(i)(2)

? 10(j)(1)(A)

? 100)(1)(B)

? 10j)(2)

? 10(j)(3)

? 10(k)

? 10(1)

? 10(m)

? 10(n)

• ? I0(o)

? 10(p)

? 10(q)

? 10(r)(1)

• ? 10(r)(2)

? 10(r)(3)

"*12

"*13

"*21

• 23(a)

"*23(b)

"*23(c)

• 24 Description AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended June 1, 2000 [Annutal Report cn Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(i)(1)].

AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended January 1, 2002.

AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001

[Anniual Report on Form 10-K of AEP for the fiscal year'ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].

Guai~anty by AEP bf the Service Corporation Excess Benefits Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(h)(1)(B)].

AEP System Supilemental Retirement Savings Plan, Amended and Restated as of June 1, 2001 (Non-Qualified) [Registration Statement No. 333-66048; Exhibit 4].

Service Coiporation Umbrella Triist for Executives [Anniial Report on Form 10-K of AEP for the fiscaly,ear ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].

Employmenit Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)].,

AEP System Senior Officer Annual Incentive Compensation Plan[Annual Report on Form 10-K dfAEP for'the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].

I AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form-10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].

AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year eiided December 31, 1998, File No. 1-3525, Exhibit 10(o)].

AEP Change In'Control Agreement.

AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].

Memorandum of agreement between Susan Tomasky and the Service Corporation dated'January'3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)].

Central anndS6uth West System Special Executive Retifemnent Plan as amended and restated effective July'l, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No. 1-1443, Exhibit 18].

Certified CSW Board Resolution of April 18, 1991.

CSW 1992 Long-Terni Incentive Plan [Proxy Statement of CSW, March 13, 1992].

Statement re-Comjutition of Ratios.

Copy of those portions of the AEP 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

List of subsidiaries of AEP.

Consent of Deloitte & Touche LLP.

Consent of Arthur Andersen LLP.'

Consent of KPMG Audit plc.

Power of Attorney.

E-3

Exhibit Number APCo?

3(a)

Copy of Restated Articles of Incorporation of APCo, and amendments thereto to

,November 4, 1993 [Registration Statement No. 33-50163, Exhibit 4(a); Registration Statement No. 33-53805, Exhibits 4(b) and 4(c)]....

3(b)

Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated June 6,1994 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1994, File No: 1-3457, Exhibit 3(b)]. * *.

3(c)

Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated March 6, 1997 [Annual Report on Form 10-K of APCo for the fiscal year ended "December 31, 1996, File No. 1-3457, Exhibit 3(c)].

3(d)

Composite copy of the Restated Articles of Incorporation of APCo (amended as of March 7, 1997) [Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No..1-3457, Exhibit 3(d)].

• 3(e)

Copy of By-Laws of APCo (amended as of October 24, 2001).

4(a)

Copy of Mortgage and Deed of Trust, dated as of December 1, 1940, between APCo and Bankers Trust Company and R. Gregory Page, as Trustees, as amended and supplemented [Registration Statement No. 2-7289, Exhibit 7(b); Registration Statement No. 2-19884, Exhibit 2(1); Registration Statement No. 2-24453, Exhibit 2(n); Registration Statement No. 2-60015, Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5),

2(b)(6), 2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10); 2(b)(12), 2(b)(14), 2(b)(15), 2(b)(16),

2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20), 2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25),

2(b)(26), 2(b)(27) and 2(b)(28); Registration Statement No. 2-64102, Exhibit 2(b)(29);

-Registration Statement No. 2-66457, Exhibits (2)(b)(30) and 2(b)(3 1); Registration.

Statement No. 2-69217, Exhibit 2(b)(32); Registration Statement No. 2-86237, Exhibit 4(b); Registration Statement No. 33-11723,-Exhibit 4(b); Registration Statement No.

33-17003, Exhibit 4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b);

Registration Statement No. 33-40720, Exhibit 4(b); Registration Statement No. 33 45219, Exhibit 4(b); Registration Statement No. 3346128, Exhibits 4(b) and 4(c);

Registration Statement No. 33-53410, Exhibit 4(b); Registration Statement No. 33 59834, Exhibit 4(b); Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);

Registration Statement No. 33-58431, Exhibits 4(b), 4(c), 4(d) and 4(e); Registration Statement No. 333-01049, Exhibits 4(b) and 4(c); Registration Statement No. 333 20305, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1998, File No. 1-3457, Exhibit 4(b)].

4(b)

Indenture (for unsecured debt securities), dated as of January, 1, 1998, between APCo and The Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibit 4(a); Registration Statement No. 333-49071, Exhibit 4(); Registration

. Statement No. 333-8406 1, Exhibits 4(b) and 4(c); Annual Report on Form 10-K Of APCo for the fiscal year ended December 31, 1999, File No. 1-3457, Exhibit 4(c);

Registration Statement No. 333-81402, Exhibits 4(b),'4(c) and 4(d)].

E-4 Description

Exhibit Number l0(a)(1) 1O(a)(2) 10(a)(3) 10(b) 10(c) 10(d) 10(e)(1) 10(e)(2)

? 10(f)(1)

? 10(f)(2)

? 10(g)

Description Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsejiient to Jantiary 18, 1975, the Administrator of the Energy Research and Development Administiation, as amended [Registritibn Statement No. 2-60015, Exhibit 5(a); RegistrAtion Statement No. 2-63234; Exhibit 5(a)(1)(B); Registration Statement No 2-66301, Exhibit 5(a)(1)(C); RegistrationfStatement No. 2-67728, Ekhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(1)(B)]

Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Forn' 10-K of APCo for the fiscal year ended December 31, 1992, File No.

1-3457, Exhibit 1 0(a)(2)(B)].

Copy of Power Agreemerit, dated July 10, 1953, between OVEC and Indiana Kentucky Electric Corporation, as amended [Registriation Statement No. 2-60015, Eihibit 5(e)]2 Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, OPCo'and I&M and with the Service Corporatiori, as amended [Registration Statement No. 2-529 10, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].

Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form IO-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].

Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, amnong APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].

Agreement andl Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form IO-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].

Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of APCo dated December 15, 1999, File No. 1 3457, Exhibit 10].

AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibii 10(e)].

Amendment to AEP Deferred Compensation Agreement for certain executive officers

[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986, File No. 1-3525, Exhibit 10(d)(2)].

AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].

E-5

Descrintion E-6 10 U.-M. ?j 11 ii l

U M

? 10(h)(1)

AEP System Excess Benefit Plan,Amended and Restated as of January 1, 2001

[Annual Report on Form'l 0-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit'1 0(j)(1)(A)].

? 10(h)(2)

AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001 (Non-Qualified) [Annual Report on Form 1 0-K of AEP for the fiscal

'year ended December 31, 2000, File No. 1-3525, Exhibit 100)(2)].

? 10(h)(3)

Umbrella Trust for Executives [Annual Report on Form' 10-K of AEP for the fiscal

-yea nded December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].

? 10(i)

Employment Agreement between E. Linn Draper, Jr. and AEP and the Service Corporation [Annual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]"

? 10G)

AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].

1 1

? 10(k)

AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1,'1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No. 1-3525, Exhibit 10(o)].

? 10(1)

AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No.-1-3525, Exhibit 10(o)].

? 10(m)

AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].

? 10(n)"

Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)].

? 10(o)(1)

Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, FileNo. 1-1443, Exhibit 18]:

? 10(o)(2)

,Certified CSW Board Res6lution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].

? 10(o)(3)

CSW 1992 Long-Term IncentiVe Plan [Proxy Statement of CSW, March 13, 1992].

"*12 Statement re: Computation of Ratios.

• 13 Copy of those portions of the APCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorpbrated by reference in this filing.

21 List of subsidiaries of APCo [Ahhuil Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21]..-.

• 24 Power of Attorney.

CPL?

3(a)

Restated Articles'oflncorporatiofi Without Amendment, Articles of Correction to' Restated Articles of Incorporation Without Amendment, Articles of Amendment to

'Restated Articles of Incoi'poration; Statements of Registered Office and/or Agent,'and Articles of Amendment to the Articles of Incorporation [Quarterly Report on Form 10 Q of CPL for the quarter ended March 31, 1997,'File No. 0-346, Exhibit 3.1].

3(b) ' "

By-Laws of CPL (amended as of April 19, 2000) [Annual Report on Form 10-K of "CPLTor the fiscal year ended Decemb'er 31, 2000, File No. 0-346, Exhibit 3(b)].

Exhibit Number 4(a)

Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between CPL and The First National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.01; Registration Statement No. 2-62271, Exhibit 2.02; Form U-1 No. 70-7003, Exhibit 17; Registration Statement No. 2-98944, Exhibit 4 (b); Form U-I No. 70-7236, Exhibit 4; Form U-I No. 70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form U-I No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit 10; Form U-1 No. 70-8053, Exhibit 10 (a);

Form U-1 No. 70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10 (c); Form U-I No. 70-8053, Exhibit 10 (d); Form U-1 No. 70-8053, Exhibit 10 (e); Form U-I No. 70-8053, Exhibit 10 (f)].

4(b)

CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of CPL: -

i (1) Indenture, dated as of May 1, 1997, between CPL and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0 346, Exhibits 4.1 and 4.2].

(2) Amended and Restated Trust Agreement of CPL Capital I, dated as of May 1, 1997, ambng CPL, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 1O-Q of CPL dated March 31, 1997, File No. 0 Exhibit 4.3].

, I (3) Guarantee Agreement, dated as of May 1, 1997, delivered by CPL for the benefit of the holders of CPL Capital I's Preferred Securities [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.4].

(4) Agreement as to Expenses and Liabilities dated as of May 1, 1997, between CPL

• and CPL Capital I [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.5].

4(c)

Indenture (for unsecured debt securities), dated as of November 15, 1999, between CPL and The Bank of New York, as Trustee, as amended and supplemented [Annual Report on F6rm 10-K of CPL for the fiscal year ended December 31, 2000, File No. 0 346, Exhibits 4(c), 4(d) and 4(e)].

• 12 Statement re: Computation of Ratios.

• 13 Copy of those portions of the CPL 2001 Annual Report (for the fiscal year ended December 31,; 2001) which are incorporated by reference in this filing.

"*23(a)

Consent of Deloitte & Touche LLP.

"*23(b)

Consent of Arthur Andersen LLP.

• 24 Power of Attorney.

CSPCo?

3(a)

Copy of Amended Articles of Incorporation of CSPCo, as amended to March 6, 1992

[Registration Statement No. 33-53377, Exhibit 4(a)].

3(b)

Copy of Certificate of Amendment to Amended Articles of Incorporation of CSPCo, dated May 19, 1994 [Annual Report on Form 10-K of CSPCo forthe fiscal year ended December 31, 1994, File No. 1-2680, Exhibit 3(b)].

3(c)

Composite copy of Amended Articles of Incorporation of CSPCo, as amended [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1994, File No.

1-2680, Exhibit 3(c)].

3(d)

Copy of Code of Regulations and By-Laws of CSPCo [Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1987, File No. 1-2680, Exhibit 3(d)].

E-7 Description

4(a)

Copy of Indenture of Mortgage'and Deed of Trust,'died September 1, 1940, between CSPCo and City Bank Farmers Trust Company'(now Citibank; N.A.), as trustee, as suppleniented'and aine'nded [Registrati6n Statement No. 2-59411, Exhibits 2(B) and 2(C); Regisitation Statement No. 2-80535, Exhibit 4(b); Registration Statement No. 2 87091, Exhibit'4(b);:Registration Statement No. 2-93208, Exhibit 4(b); Registration Statement No. 2-97652, Exhibit 4(b); Registration Statement No. 33-7081, Exhibit 4(b); Registration Statement No. 33-12389, Exhibit 4(b); Registration Statement No.

33-19227, Exhibits 4(b), 4(e), 4(f, 4(g) and 4(h); Registration Statement No. 33 "35651, Exhibit 4(b); Registration Statement No. 33-46859, Exhibits 4(b) and 4(c);

Registration Statement No. 33-50316, Exhibitý '4(b) and 4(c); Registration Statement No. 33-60336, Exhibits 4(b), 4(c) and 4(d); Registration Statement No. 33-50447, Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1993, File No. 1-2680, Exhibit 4(b)].

4(b)

Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo and Bankers Trust Company, as Trustee [R~gistration Statement No.

333-54025, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998, File No. 1-2680, Exhibits 4(c) and 4(d)].

10(a)(1)

Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United Statei Atoinic Energy Commission, and, subsequent to January 18, 1975, the Administrator of the Efidrgy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); kegistration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File.No. 1-3457, Exhibit

-10(a)(1)(13)].

L, -

1

,1 10(a)(2)

.Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registratifri Stat'ement No. 2-60015, Exhibit 5(c); Registration Statement No: 2-67728, Exhibit 5(a)(3)(B); and Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].

10(a)(3)

Copy of Power Agreement, dated July 10, 1953, betweeni OVEC and Indiana "Kentucky Electric Corporation, as amended [Registrition Statement No. 2-60015, Exhibit 5(e)].

10(b)

Copy of Interconnection Agreemfnt,'dated July 6, 1951, among-APCo, CSPCo, KEPCo, OPCo and I&M and the Service C6iporatiofi, as amended [Registration Statement No. 2-52910, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on F6rrii 10-K of AEP f6i the fiscal year ended December 31, 1990, File No. 1-3525,Exhibit'10(a)(3)].,

10(c)

Copy ofATransmission Agreemeni, dated`Alril 1984,'aimiong APCo, CSPCo, I&M, KEPCo, OPCo, and wvith the Service"Corporaii6xi as agent, aisamended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual'Repo'rt'on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525,'Exhibit 10(b)(2)].

10(d)

C Copy of Modification No. I to the'AEP System InterimdAllowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report 6i'F6rii.10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].

E-8 Description Exhibit Number

Exhibit Number 10(e)(1)

Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].

10(e)(2)

Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of CSPCo dated December 15, 1999, File No. 1 2680, Exhibit 10].

• 12 Statement re: Computation of Ratios.

"*13 Copy of those portions of the CSPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

• 23 Consent of Deloitte & Touche LLP.

• 24 Power of Attorney.

I&M?

3(a)

Copy of the Amended Articles of Acceptance of I&M and amendments thereto

[Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 3(a)].

3(b)

Copy of Articles of Amendmefit to the Amended Articlei'of Acceptance of I&M, dated March 6, 1997 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996, File No: 1-3570, Exhibit 3(b)].

3(c)

Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997) [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 3(c)].

• 3(d)

Copy of the By-Laws of I&M (amended as of November 28, 2001).

4(a)

Copy of Mortgage and Deed of Trust, dated as of June 1, 1939, between I&M and Irving Trust Company (now The Bank of New Y'ork) and various individuals, as Trilitees, as amended and supplemented [Regisirationi Statement No. 2-7597, Exhibit 7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5),

2(c)(6), 2(c)(7), 2(e)(8), 2(e)(9), 2(e)(1 0), 2(e)(1 1)', 2(c)(12), 2(c)(13), 2(c)(14),

2(c)(15), (2)(c)(16); and 2(c)(17); Registration Statement No. 2-63234, Exhibit 2(b)(18); Registration Statement No. 2-653 89, Exhibit 2(a)(19); Registration Statement No. 2-67728, Exhibit 2(b)(20); Registration Statement No. 2-85016, Exhibit 4(b);

Registration Statement No. 33-5728, Exhibit 4(c); Registration Statement No. 33-9280, Exhibit 4(b),I Registration Statement No. 33-11230, Exhibit 4(b); Registration Statement No. 33-19620, Exhibits 4(a)(ii), 4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No. 33-46851, Exhibits 4(b)(i), 4(b)(ii) arid 4(b)(iii); Registration Statement No. 33-54480, Exhibits 4(b)(I) and 4(b)(ii); Registration Statement No. 33-60886, Exhibit 4(b)(1); Registration Statement No. 33-50521 Exhibits 4(b)(I), 4(b)(ii) and 4(b)(iii);'Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)].'

c em9 N

4(b)

Copy of Indenture (for unsecured debt securities), dated as of October 1, 1998, between I&M and The'Býnk of New York, as Trustee [Registration Statement No.

333-88523; Exhibits 4(a), 4(b) and 4(c); Registration Statement No. 58656, Exhibits 4(b) and 4(c)].,

• 4(c)

Copy of Compahy Order and Officers' Certificate, dated December 12, 2001, establishing certain terms of the 6.125% Notes, Series C, due 2006.

E-9 I

Description

Exhibit Number Description 10(a)(1)

Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequent to January 18, 1975, the'Admninistrator of the Energy Research and Development Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); arid Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit I10(a)(1)(B)].,.

10(a)(2)

Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].

10(a)(3)

Copy of Power Agreement, dated July 10, 1953, between OVEC and Indiana Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].

10(a)(4)

Copy of Inter-Company Power Agreement, dated as of July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APCo for the fiscal year ended-December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].

10(a)(5)

Copy of Power Agreement, dated July 10; 1953, between OVEC and Indiana Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibit 5(e)].

I 10(b)

Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M, and OPCo and with the Service Corporation, as amended [Registration Statement No. 2-529 10, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].

10(c)

Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation as agent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No: 1-3525,'Exhibit 10(b)(2)].

10(d)

Copy of Modification No.,1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,,I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(l)].

10(e)

- Copy of Nuclear Material Lease Agreement, dated as of December 1, 1990, between I&M and DCC Fuel Corporation [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993.1 File No. 1-3570, Exhibit 10(d)].'

10(f)

Copy of Lease Agreements, dated as of December 1, 1989, between I&M and Wilmington Trust Company, as amended [Registration Statement No. 33-32753,

,Exhibits 28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C),,28(a)(4)(C), 28(a)(5)(C) and 28(a)(6)(C); Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B),

10(e)(5)(B) and 10(e)(6)(B)].

E-10

Exhibit Number Description 10(g)(1)

Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 10(f)].

10(g)(2)

Amendment No. 1, dited as of December 31, 1999, to the Agreement and Plan of Merger [C-mrent Report on Form 8-K of I&M dated December 15, 1999, File No. 1 3570, Exhibit 10].

• 12 Statement're: Computation of Ratios.

"*13 Copy of those portions of the I&M 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

21 List of subsidiaries of I&M [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21].

• 23 Consent of Deloitte & Touche LLP.

• 24 Power 6fAttorney.

KEPCo?

3(a)

Copy of Restated Articles of Incorporation of KEPCo [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1991, File No. 1-6858, Exhibit 3(a)].

3(b)

Copy of By-Laws of KEPCo (amended as of June 15, 2000) [Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].

4(a)

Copy of Mortgage and Deed of Trust, dated May 1," 1949, between KEPCo and Bankers Trust Company, as supplemented and amended [Registration Statement No. 2 65820, Exhibits 2(b)(1), 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6); Registration Statement No. 33-39394, Exhibits 4(b) and 4(c); Registration Statement No. 33-53226, Exhibits 4(b) and 4(c); Registration Statement No. 33-61808, Exhibits 4(b) and 4(c),

Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and 4(d)].

4(b)

Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between KEPCo and Bankers Trust Company, ias Trustee [Registration Statement No.

333-75785, Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 1999, File No. 1-6858, Exhibit 4(c); Annual Report on Form 10-K of KEPCo for the fiscal year ended December 31, 2000, File No.

1-6858, Exhibit 4(c)].

10(a)

Copy of Interconnection Agreement, dated July 6, 1951, among APCo, CSPCo, KEPCo, I&M and OPCo and with the Service Corporation, as amended [Registration Statement No: 2-529 10, Exhibit 5(a);Registration Statement No. 2-61009, Exhibit 5(b);

and Ahnual Report on Form 10-K of AEP for the fiscal year ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].

" f 10(b)

Copy of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and with the Service Corporation asagent, as amended [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP for the fiscal year ended De~efmiber 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].

10(c)

Copy of Modification No. I to the AEP System Interim Allowance Agreement, dated July 28, 1994; among'APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].

E-I I

10(d)(1)

Agreement and Plan of Merger, dated as of December 21, 1997, By and Among

- American Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31;'1997, File No.1-3525, Exhibit 10(f)].

10(d)(2)

Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Form 8-K of KEPCo dated December 15, 1999, File No. 1 6858, Exhibit 10].

"*12 Statement re: Computation of Ratios.

• 13.

Copy of those portions of the KEPCo 2001 Annual Report (for the fiscal year ended December 31, 200 1) which are incorporated by reference in this filing.

• 24 Power of Attorney.

OPCo?

3(a)

Copy of Amended Articles of Incorporation of OPCo, and amendments thereto to December 31, 1993 [Re'gistration Statement No. '3'-50139, Exhibit 4(a); Annual Report on Form 10-K of OPCo for the fiscal year ended Dechmber 31, 1993, File No. 6543, Exhibit 3(b)].

or a

o 3(b)

Certificate of Amendment to Amended Articles ofInrco'6raiiot of OPCo, dated May 3, 1994 [Annual Report on Form 10-K of OPCo foithe fikal year ended December 31, 1994, File No: 1-6543, Exhibit 3(b)].

3(c),

.Copy'of Certificate'of Amendrhent to Amended Articles of Incorporation of OPCo,

-,dated March 6,"1997 [Aninual Report on Form 10-K of, OPCo for the fiscal year ended "December 31, 1996, File N6. 1-6543, Exhibit 3(c)].

3(d)

Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997) [Annimal Report on Form l,10-K of OPCo for'the fiscal year ended December 31, 1996, File No. 1-6543, Exhibit 3(d)].

3(e)

Copy of Code of Reuilations 6f OPC6 [Annual Rep6rt on Fo&ni 10-K of OPCo for the fiscal year ended December 31, 1990, File No..1-'6543, Eihibit 3(d)].

4(a)

Copy of Mortgage and Deed of Tiust, dated a-s of October 1, 1938, between OPCo and Manufacturers Hanover Trtst Comp~iny'(n6.w Ch'iical Bank), as Trustee, as amended and siipplemerited [Registrati6n Statement No. 273828, Exhibit B-4; Registration Statement No. 2-60721, Exhibits 2(c)(2), 2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7),

2(c)(8), 2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14), 2(c)(15), 2(c)(16),

S2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20), 2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25),

2(c)(26), 2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), ahd 2(c)(31); Registration Statement No. 2-83591, Exhibit 4(b); Registration Stainiernt No. 33-'21208, Exhibits 4(a)(ii),

4(a)(iii) and 4(a)(iv); Registration Staterfiant No. 33-31069, Exhibit 4(a)(ii);

Regisiration State ment No. 33-44995, Exhibit4(a)(ii); Registration Statement N6. 33

• 59006, Exhibits 4(a)(ii), 4(a)(iii) ahd 4(i)(iv); Registration Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv);'Anniual Repd6rt ori Formri 10-K of OPCo for the

- fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 4(b)].

4(b)

Copyý of Indentur6(for uinsecurdd debt securities), d6ited as of September 1, 1997, Sbetween OPCo and Bankers Trust Company,,ds'Trste [Registration Statement No.

"333L49595, Exhibits 4(a); 4(b) and 4(c); Annual Report on Form 10-K of OPCo for the fiscal year ended December 31,'1998, FileNo. 1-6543, Exhibits4(c) and 4(d); Annual Report 6n Foim 10-K of OPCo foi the fiscal year hilded December 31, 1999, File No.

'16543, Exhibits 4(c) and 4(d); ýAfirtual Report cn Fo*mT0Ib-K of OPCo for the fiscal year ended December 31, 2000, File No. 1-6543, Exhibit 4(c)].

E-12 Description Exhibit Number

Exhibit Number 10(a)(1)

Copy of Power Agreement, dated October 15, 1952, between OVEC and United States of America, acting by and through the United States Atomic Energy Commission, and, subsequerit to January 18, 1975, the Administrator of the Energy Research and Developmefit Administration, as amended [Registration Statement No. 2-60015, Exhibit 5(a); Registration Statement No. 2-63234,. Exhibit 5(a)(1)(B); Registration Statement No. 2-66301, Exhibit 5(a)(1)(C); Registration Statement No. 2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of APCo for the fiscal year ended December 31, 1989, File No. 1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10 K of APCo for the fiscal year ended December 31, 1992, File No. 1-3457, Exhibit lO(a)(1)(B)].,,

10(a)(2)

Copy of Inter-Company Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring Companies, as amended [Registration Statement No. 2-60015, Exhibit 5(c); Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); Annual Report on Form 10-K of APC6 for the fiscal year ended December'31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].

10(a)(3)

Copy of Power Agreement, dated July 10, 1953', between OVEC and Indiana Kentucky Electric Corporation, as amended [Registration Statement No. 2-60015, Exhibii 5(e)].'

10(b)

Copy of Interconnection Agreement, dated July 6, 1951, arnong APCo, CSPCo, KEPCo, I&M and OPCo and with the Servide Corporation, as amended [Registration Statement No. 2-529 10, Exhibit 5(a); Registration Statement No. 2-61009, Exhibit 5(b); Annual Report on Form 10-K of AEP for" the'fiscal year ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)].

10(c)

Copy' of Transmission Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KEPCo, OPCo and'with the Servide Corporatiori as agent [Annual Report on Form 10 K of AEP for the fiscal year ended December 31','1985, File No. 1-3525, Exhibit 10(b);

Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1988, File No. 1-3525, Exhibit 10(b)(2)].

10(d)

Copy of Modification No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KEPCo, OPCo and the Service Corporation [Aniual Repori on Form 10-K of AEP for" the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(1)].

10(e)

Copy.of Aniridment No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968, among OPCo, Buckeye and Cardinal Operating Company, and amendments thereto [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit 10(f)].'

10(f)

Lease Agreement dated January 20; 1995 betwveen OPCo and JMG Funding, Limited Partnership,' and amendment thereto (confidential treatment requested) [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1994, File No. 1-6543, Exhibit 10(l)(2)].'

10(g)(1)

Agreement and Plan of Merger, dated as of December 21, 1997, by and among Amenican Electric Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation [Annual Report on Form 10-K of AEP for the fiscal year ended December 31,, 1997, File No.' 1-3525, Exhibit 10(f)].

10(g)(2)

"Amendnrent No. 1,'dated as of December 31, 1999, to the Agreement and Plan of Merger [Current Report on Formn 8-K of OPCo dated December 15, 1999, File No. 1 6543, Exhibit 10].

E-13 Description

? 10(h)(1)

AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].

? 10(h)(2)

Amendment to AEP Deferred Compensation Agreement for certain executive officers

[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1986,

,'File No. 1-3525, Exhibit 10(d)(2)]..

? 10(i)

AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Forni 10-K of AEP for the fiscal year ended December 31, 1996, File No. 1-3525,

¶

• Exhibit 10(i)(1)].

? 10(j)(1)

AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001

"[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].

? 10(j)(2)

'"AEP System Suipplemental Retirement Savings Plan, Amended and Restated as of

-'January 1, 2001 -(Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 100)(2)].

? 100)(3)

Umbrella Trust for Executives [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].

? 10(k)

Employment Agreement between E. Linn Draper, Jr. and AEP and the Service

'Corporation [Afinual Report on Form 10-K of AEGCo for the fiscal year ended December 31, 1991, File No. 0-18135, Exhibit 10(g)(3)]., : : I

? 10(l) -

'AEP System Survivor Benefit Plan,-effective January 27, 1998 [Quarterly Report on

.. Form l0-Q of AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].

? 10(m)

AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31; 1998,,File No. 1-3525, Exhibit 10(o)].

? 10(n)

AEP Chafige In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 10(o)].

? 10(o)

AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].

?10(p)

Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3, 2001 [Annual Report on Form 10-K of AEP. for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(s)].

? 10(q)(1)

Central and South West System Special Executive Retirement Plan as amended and restated effective July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year'ended December 31, 1998, File No.1-1443, Exhibit 18].

? 10(q)(2)

Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31; 2001; File No.- 1-3525, Exhibit 10(r)(2)].

? 10(q)(3)

CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].

"*12 Statement re: Computation of Ratios.

"*13 Copy of those portions of the OPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

21 List of subsidiaries of OPCo [Annual Report on Form'10-K of AEP for the fiscal year ended December 31, 2001, File No. 1-3525, Exhibit 21].

• 23 Consent of Deloitte & Touche LLP.

• 24 Povwer oftAttorney.'

E-14,

Description Exhibit Number

Exhibit Number PSO?

3(a)

Restated Certificate of Incorporation of PSO [Annual Report on Form U5S of Central and South West Corporation for the fiscal year ended December 31, 1996, File No. 1 1443, Exhibit B-3. 1].

3(b)

By-Laws of PSO (amended as of June 28, 2000) [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2000, File No. 0-343, Exhibit 3(b)].

4(a)

Indenture, dated July 1, 1945, between PSO and Liberty Bank and Trust Company of Tulsa, National Association, as Trustee, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration Statement No. 2-65871, Exhibit 2.02; Form U-I No. 70-6822, Exhibit 2; Form U-1 No. 70-7234, Exhibit 3; Registration Statement No. 3348650, Exhibit 4(b); Registration Statement No. 3349143, Exhibit 4(c); Registration Statement No. 3349575, Exhibit 4(b); Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 1993; File No. 0-343, Exhibit 4(b); Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].

4(b)

PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding solely Juni6r Subordinated Debentures of PSO:

(1) Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Truste6 [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0 343, Exhibits 4.6 and 4.7].

(2) Amended and Restated Triust Agreement of PSO Capital I; dated as of May 1, 1997, among PSO, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee

[Quarterly Repdrt on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibit 4.8].

(3) Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders of PSO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343; Exhibits 4.9].

(4) Agreemerit as toExpenses and Liabilities, dated as of May 1, 1997, betweeri PSO and PSO Capital I [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10].

4(c)

Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Banko6fNew York, as Trustee [Annual Report on Form 10-K of PSO for the fiscal'year 6iided December 31, 2000, File No. 0-343, Exhibits 4(c) and 4(d)]

• 12 Statdment re: Computation of Ratios.

"*13 Copy of those portions of the PSO 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

"*23(a)

Consent of Deloitte & Touche LLP.

"*23(b)

Consent of Arthur Andersen LLP.

• 24 Powerfof Attorney.

SWEPCo?

3(a)

Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of Amendment of Restated Certificate of Incorporation [Quarterly Report on Form 10-Q of SWEPCo for the quarter ended March 31, 1997, File No. 1-3146, Exhibit 3A4].

E-15 Description

A E-16 Description

• Thlhit Nnmher Exyhibi NumbehrDerptn 3(b)

• By-Laws'of SWEPCo (amended'as of April 27,,2000) [Quarterly Report on Form 10-Q of SWEPCo for the quarter 6nded March 31,2000, File No. 1-3146, Exhibit 3.3].

4(a)

Indenture, dated February 1, 1940, betw66n'SWEPCo and Continental Bank, National Association and M. J. Kruger, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.04; Registration Statement No. 2-61943, Exhibit 2.02; Registration Statement No. 2-66033, Exhibit 2.02; Registration Statement No. 2

'2 71126, Exhibit 2.02; Registritiori Statement No. 2-77165, Exhibit 2.02; Form U-I No.

70-7121, Exhibit 4; Form U-I No. 70-7233, Exhibit 3; Form U-I No. 70-7676, Exhibit 3; Form U-1 No. 70-7934, Exhibit 10; Form U-1 No. 72-8041, Exhibit 10(b); Form U 1 No. 70-8041, Exhibit 10(c); FornmU-1 No. 70-8239;Exhibit 10(a)].

4(b)

SWEPCO-obligated, mhndatorily jedeemable preferred securities of subsidiary trust holding solely Junior Subordinated Debentures of SWEPCo:,

(1) Indenture, dated as of May 1, 1997, between SWEPCo and the Bank of New York, as Trustee [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.11 and 4.12].

(2) Amended and Restated Trust Agreement of SWEPCo Capital I, dated as of May 1, 1997, among SWEPCo, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.13].

(3) Guarantee Agreement, dated as of May 1, 1997, delivered by SWEPCo for the benefit of the holders of SWEPCo Capital I's Preferred Securities [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.14].

(4) Agreement as to Expenses and Liabilities, dated as of May 1, 1997 between SWEPCo and SWEPCo Capital I [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.15].

4(c)

Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank of New York, as Trustee [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31, 2000, File No. 1-3146, Exhibits 4(c) and 4(d)].

• 12 Statement re: Computation of Ratios.

• 13 Copy of those portions of the SWEPCo 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

"*23(a)

Consent of Deloitte & Touche LLP.

"*23(b)

Consent of Arthur Andersen LLP.

• 24 Power of Attorney.

WTU?

3(a)

Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of Incorporation [Annual Report on Form 10-K of WTU for the fiscal year ended December 31, 1996, File No. 0-340, Exhibit 3.5].

3(b)

By-Laws of WTU (amended as of May 1, 2000) [Quarterly Report on Form 10-Q of WTU for the quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4].

Exhibit Number 4(a)

Indenture, dated August 1, 1943, between WTU and Harris Trust and Savings Bank and J. Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712, Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No. 2-74408, Exhibit 4.02; Form U-I No. 70-6820, Exhibit 12; Form U-1 No. 70-6925, Exhibit 13; Registration Statement No. 2-98843, Exhibit 4(b);

Form U-1 No. 70-7237, Exhibit 4; Form U-1 No. 70-7719, Exhibit 3; Form U-1 No.

70-7936, Exhibit 10; Form U-1 No.,70-8057, Exhibit 10; Form U-1 No. 70-8265, Exhibit 10; Form U-I No. 70-8057, Exhibit 10(b); Form U-I No. 70-8057, Exhibit 10(c)].

• 12 Statement re: Computation of Ratios.

"*13 Copy of those portions of the WTU 2001 Annual Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in this filing.

• 24 Power of Attorney.

? Certain instruments defining the rights of holders of long-term debt of the registrants included in the financial statements of registrants filed herewith have been omitted because the total amount of securities authorized thereunder does not exceed 10% of the total assets of registrants. The registrants hereby agree to furnish a copy of any such ormritted instrument to the SEC upon request.

E-17 Description

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