ML021360189

2001 Financial Information for Indiana Michigan Power Company for Units 1 & 2

ML021360189
Person / Time
Site:	Cook
Issue date:	05/10/2002
From:	Greenlee S Indiana Michigan Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:2691-11
Download: ML021360189 (151)

Text

Indiana Michigan Power Company Cook Nudear Plant One Cook Place Bndgman, MI49106 616&465-5901 INDIANA MICHIGAN POWER May 10, 2002 AEP:NRC:2691-11 10 CFR 50.71 10 CFR 140.21 Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P 1-17 Washington, D.C. 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 2001 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Indiana Michigan Power Company (I&M) hereby submits, as At achrer;t 1. thc I&M 2001 Annual Financial Report in accordance with 10 CFR 50.7t(b)o Also included, as Attachment 2, is a copy of the year 2002 projected cash flow for I&M as required by 10 CFR 140.21 (e).

This letter contains no new commitments. Should you have any questions, please contact Mr. Gordon P. Arent, Manager of Regulatory Affairs, at (616) 697-5553.

Sincerely, A. Greenlee Director of Design Engineering and Regulatory Affairs DB/dmb Attachments c: K. D. Curry, w/o attachments J. E. Dyer MDEQ - DW & RPD, w/o attachments NRC Resident Inspector R. Whale, w/o attachments mq uu ALP- America's Energy Partnze.-

ATTACHMENT 1 TO AEP:NRC:2691-11 INDIANA MICHIGAN POWER COMPANY 2001 ANNUAL REPORT Sections B through E and Sections G through K have been omitted from this attachment in order to provide only information relevant to the Licensee, Indiana Michigan Power Company.

2001 Annual Reports American Electric Power Company, Inc.

S.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 West Texas Utilities Company Audited Financial Statements and Management's Discussion and Analysis.

Z ,AMERICAN ELECTRIC POWER Partner ALI':-,Americds EnemyTg

Contents Page Glossary of Terms i Forward Looking Information iv American Electric Power Company, Inc. and Subsidiary Companies Selected Consolidated Financial Data A-1 Management's Discussion and Analysis of Results of Operations A-2 Consolidated Statements of Income A-12 Consolidated Balance Sheets A-13 Consolidated Statements of Cash Flows A-15 Consolidated Statements of Common Shareholders' Equity and A-16 Comprehensive Income Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries A-17 Schedule of Consolidated Long-term Debt of Subsidiaries A-1 8 Index to Notes to Consolidated Financial Statements A-19 Management's Responsibility A-20 Independent Auditors' Report A-21 AEP Generating Company Selected Financial Data B-1 Management's Narrative Analysis of Results of Operations B-2 Statements of Income and Statements of Retained Earnings B-3 "':;"

Balance Sheets B-4 Statements of Cash Flows B-6 Statements of Capitalization B-7 Index to Notes to Financial Statements B-8 Independent Auditors' Report B-9 Appalachian Power Company and Subsidiaries Selected Consolidated Financial Data C-1 Management's Discussion and Analysis of Results of Operations C-2 Consolidated Statements of Income and Consolidated Statements of C-7 Comprehensive Income Consolidated Balance Sheets C-8 Consolidated Statements of Cash Flows C-1 Consolidated Statements of Retained Earnings C-I I Consolidated Statements of Capitalization C-12 Schedule of Long-term Debt C-13 Index to Notes to Consolidated Financial Statements C-14 Independent Auditors' Report C-15 Central Power and Light Company and Subsidiaries Selected Consolidated Financial Data D-1 Management's Discussion and Analysis of Results of Operations D-2 Consolidated Statements of Income D-6 Consolidated Balance Sheets D-7 Consolidated Statements of Cash Flows D-9 Consolidated Statements of Retained Earnings D-1O0 Consolidated Statements of Capitalization D-11 Schedule of Long-term Debt D-12 Index to Notes to Consolidated Financial Statements D-13 Independent Auditors' Report D-14

Columbus Southern Power Company and Subsidiaries Selected Consolidated Financial Data E-1 Management's Narrative and Analysis of Results of Operations E-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings E-6 Consolidated Balance Sheets E-7 Consolidated Statements of Cash Flows E-9 Consolidated Statements of Capitalization E-10 Schedule of Long-term Debt E-11 Index to Notes to Consolidated Financial Statements E-12 Independent Auditors' Report E-1 3 Indiana Michigan Power Company and Subsidiaries Selected Consolidated Financial Data F-1 Management's Discussion and Analysis of Results of Operations F-2 Consolidated Statements of Income and Consolidated Statements of F-7 Comprehensive Income Consolidated Balance Sheets F-8 Consolidated Statements of Cash Flows F-10 Consolidated Statements of Retained Earnings F-1 1 Consolidated Statements of Capitalization F-12 Schedule of Long-term Debt F-13 Index to Notes to Consolidated Financial Statements F-15 Independent Auditors' Report F-16 Kentucky Power Company Selected Financial Data G-1 Management's Narrative Analysis of Results of Operations G-2 Statements of Income, Statements of Comprehensive Income G-6 and Statements of Retained Earnings Balance Sheets G-7 Statements of Cash Flows G-9 Statements of Capitalization G-10, Schedule of Long-term Debt G-11 Index to Notes to Financial Statements G-12 Independent Auditors' Report G-13 Ohio Power Company and Subsidiaries Selected Consolidated Financial Data H-1 Management's Discussion and Analysis of Results of Operations H-2 Consolidated Statements of Income and Consolidated Statements of H-7 Comprehensive Income Consolidated Balance Sheets H-8 Consolidated Statements of Cash Flows H-10 Consolidated Statements of Retained Earnings H-1i1 Consolidated Statements of Capitalization H-12 Schedule of Long-term Debt H-1 3 Index to Notes to Consolidated Financial Statements H-1 5 Independent Auditors' Report H-16

Public Service Company of Oklahoma and Subsidiaries Selected Consolidated Financial Data I-1 Management's Narrative Analysis of Results of Operations (-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings 1-5 Consolidated Balance Sheets 1-6 * ....*.

Consolidated Statements of Cash Flows 1-8 Consolidated Statements of Capitalization 1-9 Schedule of Long-term Debt 1-10 Index to Notes to Consolidated Financial Statements 1-11 Independent Auditors' Report 1-12 Southwestern Electric Power Company and Subsidiaries Selected Consolidated Financial Data J-1 Management's Discussion and Analysis of Results of Operations J-2 Consolidated Statements of Income and Consolidated Statements of Retained Earnings J-6 Consolidated Balance Sheets J-7 Consolidated Statements of Cash Flows J-9 Consolidated Statements of Capitalization J-10 Schedule of Long-term Debt J-11 Index to Notes to Consolidated Financial Statements J-12 Independent Auditors' Report J-1 3 West Texas Utilities Company Selected Financial Data K-1 Management's Narrative Analysis of Results of Operations K-2 Statements of Income and Statements of Retained Earnings K-6 Balance Sheets K-7 Statements of Cash Flows K-9 Statements of Capitalization K-10 Schedule of Long-term Debt K-1I Index to Notes to Consolidated Financial Statements K-12 Independent Auditors' Report K-1 3 Notes to Financial Statements L-1 Management's Discussion and Analysis of Financial Condition, Contingencies and Other Matters M-1

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

Term Meaning 2004 True-up Proceeding ......... A filing to be made after January 10, 2004 under the Texas Legislation to finalize the amount of stranded costs and the recovery of such costs.

AEGCo................ AEP Generating Company, an electric utility subsidiary of AEP.

AEP ........................................... American Electric Power Company, Inc.

AEP Consolidated ..................... AEP and its majority owned subsidiaries consolidated.

AEP Credit,lnc. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated and unaffiliated domestic electric utility companies.

AEP East electric operating companies ................................ APCo, CSPCo, I&M, KPCo and OPCo.

AEPR ........................................ AEP Resources, Inc.

AEP System or the System ...... The American Electric Power System, an integrated electric utility system, owned and operated by AEP's electric utility subsidiaries.

AEPSC ...................................... American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.

AEP Power Pool ....................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale system sales of the member companies.

AEP West electric operating com panies ................................ CPL, PSO, SWEPCo and WTU.

AFUDC ..................................... Allowance for funds used during construction, a noncash nonoperating income item that is capitalized and recovered through depreciation over the service life of domestic regulated electric utility plant.

Alliance RTO ............................. Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated utilities.

Am os Plant ............................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.

APCo ........................................ Appalachian Power Company, an AEP electric utility subsidiary.

Arkansas Commission .............. Arkansas Public Service Commission.

Buckeye .................................... Buckeye Power, Inc., an unaffiliated corporation.

CLECO ..................................... Central Louisiana Electric Company, Inc., an unaffiliated corporation.

COLI .................. Corporate owned life insurance program.

Cook Plant ................................ The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.

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

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

CSW ......................................... Central and South West Corporation, a subsidiary of AEP.

CSW Energy ............................. CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.

CSW International .................... CSW International, Inc., an AEP subsidiary which invests in energy projects and entities outside the United States.

D.C. Circuit Court ..................... The United States Court of Appeals for the District of Columbia Circuit.

DHMV ....................................... Dolet Hills Mining Venture.

DOE .......................................... United States Department of Energy.

ECOM ....................................... Excess Cost Over Market.

ENEC ........................................ Expanded Net Energy Costs.

EITF .......................................... The Financial Accounting Standards Board's Emerging Issues Task Force.

ERCOT..................................... The Electric Reliability Council of Texas.

EWGs ..................... Exempt Wholesale Generators.

FASB .................. Financial Accounting Standards Board.

Federal EPA ............................ United States Environmental Protection Agency.

FERC ........................................ Federal Energy Regulatory Commission.

FM B ....... .......... ................... First Mortgage Bond.

FUCOs ...................................... Foreign Utility Companies.

GAAP ........................................ Generally Accepted Accounting Principles.

I&M ........................................... Indiana Michigan Power Company, an AEP electric utility subsidiary.

IPC ............................................ Installment Purchase Contract.

IRS ............................................ Internal Revenue Service.

IURC ......................................... Indiana Utility Regulatory Commission.

ISO ............................................ Independent system operator.

Joint Stipulation ......................... Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.

KPCo ........................................ Kentucky Power Company, an AEP electric utility subsidiary.

KPSC ........................................ Kentucky Public Service Commission.

KWH ......................................... Kilowatthour.

LIG ............................................ Louisiana Intrastate Gas.

Michigan Legislation ................. The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer choice of electricity supplier.

Midwest ISO ............................. An independent operator of transmission assets in the Midwest.

MLR .......................................... Member load ratio, the method used to allocate AEP Power Pool transactions to its members.

Money Pool ............................... AEP System's Money Pool.

MPSC ....................................... Michigan Public Service Commission.

MTN .......................................... Medium Term Notes.

MW ........................................... Megawatt.

MWH ......................................... Megawatthour.

NEIL .......................................... Nuclear Electric Insurance Limited.

Nox ........................................... Nitrogen oxide.

NOx Rule .................................. A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states including seven of the states in which AEP companies operates.

NP ............................................. Notes Payable.

NRC .......................................... Nuclear Regulatory Commission.

Ohio Act .................................... The Ohio Electric Restructuring Act of 1999.

Ohio EPA .................................. Ohio Environmental Protection Agency.

OPCo ........................................ Ohio Power Company, an AEP electric utility subsidiary.

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

PCBs ......................................... Polychlorinated Biphenyls.

PJM ........................................... Pennsylvania - New Jersey - Maryland regional transmission organization.

PRP .......................................... Potentially Responsible Party.

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

PUCO ....................................... The Public Utilities Commission of Ohio.

PUCT ........................................ The Public Utility Commission of Texas.

PUHCA ..................................... Public Utility Holding Company Act of 1935, as amended.

PURPA ..................................... The Public Utility Regulatory Policies Act of 1978.

RCRA ........................................ Resource Conservation and Recovery Act of 1976, as amended.

Registrant Subsidiaries ............. AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU.

Rockport Plant .......................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.

RTO .......................................... Regional Transmission Organization.

SEC .......................................... Securities and Exchange Commission.

SFAS ........................................ Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board.

SFAS 71 ................................... Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Tvoes of Reaulation.

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1I1 SFAS 101 ................................. Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of Application of Statement 71.

SFAS 121 ................................. Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of.

SFAS 133 ................................. Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

S NF ........................................... Spent N uclear Fuel.

SPP ........................................... Southwest Power Pool.

STP ........................................... South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company, an AEP electric utility subsidiary.

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

Superfund ................................. The Comprehensive Environmental, Response, Compensation and Liability Act.

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

Texas Appeals Court ................ The Third District of Texas Court of Appeals.

Texas Legislation ...................... Legislation enacted in 1999 to restructure the electric utility industry in Texas.

Travis District Court ................. State District Court of Travis County, Texas.

TVA .......................................... Tennessee Valley Authority.

UX ............................................ The United Kingdom .

UN............................................. Unsecured Note.

VaR ........................................... Value at Risk, a method to quantify risk exposure.

Virginia SCC ............................. Virginia State Corporation Commission.

W V ............................................ W est V irginia.

WVPSC .................................... Public Service Commission of West Virginia.

WPCo ....................................... Wheeling Power Company, an AEP electric distribution subsidiary.

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

Yorkshire ................................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP and New Century Energies until April 2001.

Zimmer Plant ............................ William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus Southern Power Company, an AEP subsidiary.

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

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AMERICAN ELECTRIC POWER COMPANY, INC.

AND SUBSIDIARY COMPANIES

III AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Selected Consolidated Financial Data Year Ended December 31, 2001 2000 1999 1998 1997 INCOME STATEMENTS DATA (in millions):

Total Revenues $61,257 $36,706 $24,745 $18,420 Operating Income $11,427 2,395 2,004 2,304 2,258 2,180 Income Before Extraordinary Items and cumulative Effect 1,003 302 986 975 949 Extraordinary Losses (50) (35) (14) cumulative Effect of (285)

Accounting change 18 Net Income 971 267 972 975 664 Year Ended December 31, 2001 2000 1999 1998 BALANCE SHEETS DATA (in millions): 1997 Property, Plant and Equipment $40,709 $38,088 Accumulated Depreciation $36,938 $35,655 $33,496 and Amortization 16,166 15,695 15,073 Net Property, 14,136 13,229 Plant and Equipment $ 24.543 $~22393 $21 5 * ~$20,26Z Total Assets $47,281 $53,350 $35,693 $33,418 $30,092 Common shareholders' Equity 8,229 8,054 8,673 8,452 8,220 Cumulative Preferred stocks V of Subsidiaries* 156 161 182 350 377 Trust Preferred Securities 321 334 335 335 335 Long-term Debt* 12,053 10,754 11,524 11,113 9,354 Obligations under capital Leases* 451 614 610 539 549 Year Ended December 31, 2001 2000 1999 COMMON STOCK DATA: 1998 1997 Earnings per Common Share:

Before Extraordinary Item and Cumulative Effect $ 3.11 $0.94 $3.07 Extraordinary Losses $3.06 $2.99 (0.16) (.11) (.04) - (.90)

Cumulative Effect of Accounting change 0.06 Earnings Per Share

$2-0-9 Average Number of shares Outstanding (in millions) 322 322 321 318 316 Market Price Range: High $51.20 $48-15/16 $48-3/16 $53-5/16 $ 52 Low 39.25 25-15/16 30-9/16 42-1/16 39-1/8 Year-end Market Price 43.53 46-1/2 32-1/8 47-1/16 51-5/8 Cash Dividends on Common**

$2.40 $2.40 $2.40 $2.40 $2.40 Dividend Payout Ratio** 79.7%

Book Value per Share 289.2% 79.2% 78.4% 114.8%

$25.54 $25.01 $26.96 $26.46 $25.91 The consolidated financial statements give retroactive effect to AEP's merger with was accounted for as a pooling of interests. CSW, which

• Including portion due within one year

"*Based on AEP historical dividend rate.

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Management's Discussion and Analysis of Results of Operations American Electric Power Company, Inc.

(AEP) is one of the largest investor owned AEP's focus is in the US but we also have electric public utility holding companies in the smaller footprints in other parts of the world:

US. We provide generation, transmission and

• a growing energy trading operation in distribution service to over 4.9 million retail Europe based in the UK.

customers in eleven states (Arkansas,

• 4,000 megawatts of generating Indiana, Kentucky, Louisiana, Michigan, Ohio, capacity in the United Kingdom which Oklahoma, Tennessee, Texas, Virginia and represents 16% of the UK's total West Virginia) through our electric utility generation capacity.

operating companies. We market and trade electricity and natural gas in the US and Other foreign investments include Europe. distribution operations in the U.K., Australia, and Brazil. We have additional generating We have a significant presence facilities in China and Mexico. We also offer throughout the domestic energy value chain. engineering and construction services Our US electric assets include: worldwide.

• 38,000 megawatts of generating capacity (the largest US generation Business Strategy portfolio with a significant cost advantage in the Midwest and Our strategy is a balanced business Southwest markets); model of regulated and unregulated

• 38,000 miles of transmission lines and businesses backed by assets, supported by

• 186,000 miles of distribution lines enterprise-wide risk management and a strong balance sheet. We have been focused Our natural gas assets include: on the wholesale side of the business since it

• 128 Bcf of gas storage facilities provides the greater growth opportunities. But, this is complemented by a robust regulated 0 6,400 miles of gas pipelines in business that has a predictable earnings Louisiana and Texas which provide a stream and cash flows. Strong risk basis for market knowledge. management and a disciplined analysis of markets protected us from the California With our coal and transportation assets we: energy crisis and Enron's bankruptcy filing.

"* control over 7,000 railcars

"* control over 1,800 barges and 37 tug Our balanced business model is one boats where AEP integrates its assets, marketing,

"* operate two coal handling terminals trading and market analysis and resources to with 20 million tons of capacity. create a superior knowledge about the

"* produce over 7 million tons of coal commodity markets which keeps us a step annually in the US. ahead of our competition. Our power, gas, coal, and barging assets and operations AEP is one of the largest traders of electricity provide us with market knowledge and and natural gas in the US: customer connectivity giving us the ability to

"* over 576 million MWH of electricity make informed marketing and trading trades in 2001 decision and to customize our products and

"* over 3,800 billion cubic feet (Bcf) of services.

gas trades in 2001 AEP provides investors with a balanced In addition we: portfolio since it has:

"* consume 80 million tons of coal "* a growing unregulated wholesale annually energy marketing and trading

"* consume 310 Bcf of natural gas business annually "* predictable cash flow and earnings A-2

streams from the regulated electricity "* Movement towards re-regulation in business, and California through market caps and a high dividend yield relative to today's other challenges to the continuation of low-interest rate environment. deregulation of the retail electricity supply business in the U.S.,

We are currently in the process of "* The continued negative impact of a restructuring our assets and operations to slowly recovering economy.

separate the regulated operations from the non-regulated operations. Our business plan considers these risks and we believe that we can deliver earnings We filed with the SEC for approval to form growth of 6-8% annually across the energy two separate legal holding company value chain through the disciplined integration subsidiaries of AEP Co. Inc., the parent of strategic assets and intellectual capital to company. Approval is needed from the SEC generate these returns for our shareholders.

under the PUHCA and the FERC to make these organizational changes. Certain state Our strategies to achieve our business regulatory commissions have intervened in plan are:

the FERC proceedings. We have reached a

• Unregulated settlement with those state commissions and "o Disciplined approach to asset are awaiting the FERC's approval before the acquisition and disposition SEC will make a final ruling on our filing. "o Value-driven asset optimiz ation through the linkage of We are implementing a corporate superior commercial, an separation restructuring plan to support our alytical and technical skills objective of unlocking shareholder value for "o Broad participation across all our domestic businesses. Our plan provides energy markets with a for: disciplined and opportunistic

"* transparency and clarity to investors, allocation of risk capital

"* a simpler structure to conduct "o Continued investment in both business, and to anticipate and technology and process im monitor performance, provement to enhance our

"* compliance with states' restructuring competitive advantage laws promoting customer choice, and "o Continued expansion of

"* more efficient financing. intellectual capital through ongoing recruiting, perform The new corporate structure will consist of ance-linked compensation and a regulated holding company and an the development of a structure unregulated holding company. The regulated that promotes sound decision holding company's investments will be in making and innovation at all integrated utilities and Ohio and Texas wires. levels.

The unregulated holding company's investments will be in Ohio and Texas Regulated generation, independent power producers, "o Maintain moderate but steady gas pipe line and storage, UK generation, earnings growth barging, coal mining and marketing and "o Maximize value of trans trading. mission assets and protect revenue stream through The risks in our business are: RTO/Alliance membership

"* Margin erosion on electric trading as "o Continue process improve markets mature, ment to maintain distribution

"* Diminished opportunities for signifi service quality while en cant gains as volatility declines, hancing financial performance

"* Retail price reductions mandated with "o Optimize generation assets the implementation of customer through enhanced availability choice in Texas and Ohio, of off-system sales A-3

o Manage regulatory process to Our divesture of non-strategic assets maximize retention of earnings is somewhat limited by the pooling of interest improvement accounting requirements applied to the merger of CSW and AEP in June 2000. We Our significant accomplishments in 2001 are presently evaluating certain tele were: communications and foreign investments for

"* Adding the following assets to possible disposal and have not yet decided integrate with and support our trading whether to dispose of such investments.

and marketing competitive advantage: Disposal of investments determined to be o 4,200 miles of gas pipeline, non-strategic will be considered in 118 Bcf gas storage and re accordance with the pooling of interests lated gas marketing contracts restrictions which end in June 2002. We are o 1,200 hopper barges and 30 committed to continually evaluate the need to tugboats reallocate resources to areas with greater o 4,000 megawatts of coal-fired potential, to match investments with our generation in England strategy and to pare investments that do not o 160 megawatts of wind produce sufficient return and shareholder generation in Texas value. Any investment dispositions could o coal mining properties, coal affect future results of operations.

reserves, mining operations and royalty interests in Outlook for 2002 Colorado, Kentucky, Ohio, Pennsylvania and West Growth in 2002 will be driven in part by Virginia our continued strategic development of

"* Entering into new markets through the wholesale products and geographies, as acquisition of existing contracts and demonstrated in recent months by our move hiring key staff including 57 into global coal markets and Nordic energy. A employees from Enron's London full year of operation of assets acquired in based international coal trading group 2001 - Houston Pipe Line, Quaker Coal, the in December 2001 and Enron's Nordic MEMCO barge line and two power plants in energy trading group in January 2002. the United Kingdom - will also contribute to We now trade power and gas in the growth in 2002 earnings.

UK, France, Germany, and the Netherlands and coal throughout the Although we expect that the future outlook world for results of operations is excellent there are

"* Adding other energy-related contingencies and challenges. We discuss commodities to our power and gas these matters in detail in the Notes to portfolio i.e. coal, S02 allowances, Financial Statements and in this natural gas liquids (NGLs) and oil Management's Discussion and Analysis. We

"* Disposing of the following assets that intend to work diligently to resolve these did not fit our strategy: matters by finding workable solutions that "o 120 MWs of generation in Mexico, balance the interests of our customers, our "o Above market coal mines in Ohio employees and our shareholders.

and West Virginia, "o A 50 % investment in Yorkshire, a As discussed above we expect to U.K. electric supply and continue evaluating certain investments for distribution company, possible disposal due to either their non "o An investment in a Chilean electric strategic nature or limited future earnings company potential for AEP. Any dispositions could "o Datapult, an energy information result in gains or losses being recorded in our data and analysis tool. income statement.

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

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JIII Results of Operations The decline in net income to $267 million or $0.83 per share in 2000 from $972 In 2001 AEP's principal operating million or $3.03 per share in 1999 was business segments and their major activities primarily due to the 2000 charges described were: above and an extraordinary losses from the discontinuance of regulatory accounting for

"* Wholesale: generation in certain states.

"o Generation of electricity for sale to retail and wholesale A strong performance in the first nine customers months of 2001 was partially offset by "o Gas pipeline and storage unfavorable operating conditions in the fourth services quarter. Extremely mild November and "o Marketing and trading of December weather combined with weak electricity, gas and coal economic conditions in the fourth quarter, "o Coal mining, bulk commodity reduced retail energy sales and wholesale barging operations and other margins. Heating degree days in the fourth energy supply related quarter were down 33% from the same period business. in 2000. Although the fourth quarter was

"* Energy Delivery disappointing, 2001 net income before "o Domestic electricity trans extraordinary items and cumulative effect of mission, accounting change reached the $1 billion "o Domestic electricity distri mark.

bution

" Other Investments Our wholesale business continues to "o Foreign electric distribution perform well despite a slowing economy that and supply investments, reduced both wholesale energy margins and

" Telecommunication services. energy use by industrial customers. Our wholesale business, which includes Net Income generation, retail and wholesale sales of power and natural gas and trading of power Net income increased to $971 million or and natural gas and natural gas pipeline and

$3.01 per share from $267 million or $0.83 storage services, contributed to the earnings per share. The increase of $704 million or increase by successfully returning the Cook

$2.18 per share was due to the growth of Plant to service in 2000 and by growing AEP's ,

A.

AEP's wholesale marketing and trading wholesale business.

business, increased revenues and the controlling of our operating and maintenance Our energy delivery business, which costs in the energy delivery business, and consists of domestic electricity transmission declining capital costs. Also contributing to and distribution services, contributed to the the earnings improvement in 2001 was the increase in earnings by controlling operating effect of 2000 charges for a disallowance of and maintenance expenses and by increasing COLI-related tax deductions, expenses of the revenues.

merger with CSW, write-offs related to non regulated investments and restart costs of the Capital costs decreased due primarily Cook Nuclear Plant. The favorable effect on to interest paid to the IRS in 2000 on a COLI comparative net income of these 2000 deduction disallowance and declining short charges was offset in part by current year term market interest rate conditions.

losses from Enron's bankruptcy and extraordinary losses for the effects of deregulation and a loss on reacquired debt.

A-5

We discontinued application of SFAS Critical Accounting Policies 71 for the generation portion of our business Revenue Recognition - TraditionalElectricity in Ohio for OPCo and CSPCo in September Supply and Delivery Activities - As the owner 2000, in Virginia and West Virginia for APCo of cost-based rate-regulated electric public in June 2000, in Texas for CPL, WTU, and utility companies, AEP Co., Inc.'s SWEPCo in September 1999 and in Arkansas consolidated financial statements recognize for SWEPCo in September 1999 in revenues on an accrual basis for traditional recognition of the passage of legislation to electricity supply sales and for electricity transition to customer choice and market transmission and distribution delivery pricing for the supply of electricity. We services. These revenues are recognized in recorded extraordinary losses when we our income statement when the energy is discontinued the application of SFAS 71. See delivered to the customer and include unbilled Note 2, "Extraordinary Items and Cumulative as well as billed amounts. In general, Effect" for additional information.

expenses are recorded when incurred. As a result of our cost based rate regulated Wholesale Energy Marketing and Trading operations, our financial statements reflect the Activities - We engage in non-regulated actions of regulators that can result in the wholesale electricity and natural gas recognition of revenues and expenses in marketing and trading transactions (trading different time periods than enterprises that are activities). Trading activities involve the not rate regulated. In accordance with SFAS purchase and sale of energy under forward 71, "Accounting for the Effects of Certain contracts at fixed and variable prices and Types of Regulation," regulatory assets buying and selling financial energy contracts (deferred expenses) and regulatory liabilities which includes exchange futures and options (future revenue reductions or refunds) are and over-the-counter options and swaps.

recorded to reflect the economic effects of Although trading contracts are generally short regulation by matching in the same term, there are also long-term trading accounting period regulated expenses with contracts. We recognize revenues from their recovery through regulated revenues. trading activities generally based on changes in the fair value of energy trading contracts.

When regulatory assets are probable of recovery through regulated rates, we record Recording the net change in the fair them as assets on the balance sheet. We value of trading contracts as revenues prior to test for probability of recovery whenever new settlement is commonly referred to as mark events occur, for example a regulatory to-market (MTM) accounting. It represents commission order or passage of new the change in the unrealized gain or loss legislation. Ifwe determine that recovery of a throughout the contract's term. When the regulatory asset is no longer probable, we contract actually settles, that is, the energy is write off that regulatory asset as a charge actually delivered in a sale or received in a against net income. A write off of regulatory purchase or the parties agree to forego assets may also reduce future cash flows delivery and receipt and net settle in cash, the since there may be no recovery through unrealized gain or loss is reversed out of regulated rates. revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase.

A-6

AA Therefore, over the term of the trading further impact on operating results but has an contracts an unrealized gain or loss is offsetting and equal effect on trading contract recognized as the contract's market value assets and liabilities. Of course we could also changes. When the contract settles the total do similar transactions but enter into a gain or loss is realized in cash but only the purchase contract prior to entering into a difference between the accumulated sales contract. If the sale and purchase unrealized net gains or losses recorded in contracts do not match exactly as to prior months and the cash proceeds is commodity type, volumes, delivery point, recognized. Unrealized mark-to-market gains schedule and other key terms, then there and losses are included in the Balance Sheet could be continuing mark-to-market effects on as energy trading and derivative contract revenues from recording additional changes assets or liabilities as appropriate. in fair values using mark-to-market accounting.

The majority of our trading activities represent physical forward electricity and gas Trading of electricity and gas options, contracts that are typically settled by entering futures and swaps, represents financial into offsetting contracts. An example of our transactions with unrealized gains and losses trading activities is when, in January, we enter from changes in fair values reported net in into a forward sales contract to deliver revenues until the contracts settle. When electricity or gas in July. At the end of each these contracts settle, we record the net month until the contract settles in July, we proceeds in revenues and reverse to would record any difference between the revenues the prior unrealized gain or loss.

contract price and the market price as an unrealized gain or loss in revenues. In July The fair value of open short-term when the contract settles, we would realize trading contracts are based on exchange the gain or loss in cash and reverse to prices and broker quotes. We mark-to-market revenues the previously recorded unrealized open long-term trading contracts based gain or loss. Prior to settlement, the change mainly on Company-developed valuation in the fair value of physical forward sale and models. These models estimate future purchase contracts is included in revenues on energy prices based on existing market and a net basis. Upon settlement of a forward broker quotes and supply and demand market trading contract, the amount realized is data and assumptions. The fair values included in revenues for a sales contract and determined are reduced by reserves to adjust realized costs are included in purchased for credit risk and liquidity risk. Credit risk is energy expense for a purchase contract with the risk that the counterparty to the contract the prior change in unrealized fair value will fail to perform or fail to pay amounts due reversed in revenues. AEP. Liquidity risk represents the risk that imperfections in the market will cause the Continuing with the above example, price to be less than or more than what the assume that later in January or sometime in price should be based purely on supply and February through July we enter into an demand. There are inherent risks related to offsetting forward contract to buy electricity or the underlying assumptions in models used to gas in July. If we do nothing else with these fair value open long-term trading contracts.

contracts until settlement in July and if the We have independent controls to evaluate the commodity type, volumes, delivery point, reasonableness of our valuation models.

schedule and other key terms match then the However, energy markets, especially difference between the sale price and the electricity markets, are imperfect and volatile purchase price represents a fixed value to be and unforeseen events can and will cause realized when the contracts settle in July. If reasonable price curves to differ from actual the purchase contract is perfectly matched prices throughout a contract's term and when with the sales contract, we have effectively contracts settle. Therefore, there could be fixed the profit or loss; specifically it is the significant adverse or favorable effects on difference between the contracted settlement future results of operations and cash flows if price of the two contracts. Mark-to-market market prices do not correlate with the accounting for these contracts will have no Company-developed price models.

A-7

We discontinued application of SFAS Critical Accountinq Policies 71 for the generation portion of our business Revenue Recognition - TraditionalElectricity in Ohio for OPCo and CSPCo in September Supply and Delivery Activities - As the owner 2000, in Virginia and West Virginia for APCo of cost-based rate-regulated electric public in June 2000, in Texas for CPL, WTU, and utility companies, AEP Co., Inc.'s SWEPCo in September 1999 and in Arkansas consolidated financial statements recognize for SWEPCo in September 1999 in

• revenues on an accrual basis for traditional recognition of the passage of legislation to electricity supply sales and for electricity transition to customer choice and. market and distribution delivery We transmission pricing for the supply of electricity.

services. These revenuesrate recognized in recorded extraordinary losses when we our income statement when the energy is disc~ontinued the application of SFAS 71. See delivered to the customer and include unbilled Note:2, "Extraordinary Items and Cumulative

as well as billed amount, In general, Effept" for additional information.

,,expenses are recorded whd incurred. As a result of our cost based*° rate regulated Wholesale Energy Marketing and Trading operations, our financial statements reflect the Activities - We engage in non-regulated actions of regulators that can result in the wholesale electricity and natural gas recognition of revenues and expenses in marketing and trading transactions (trading

.-,,different time periods than eterprises that are activities). Trading activities involve the not rate regulated. In accordance with SFAS purchase and sale of energy under forward "71, "Accounting for the* Effe-cts of Certain contracts at fixed and variable prices and Ti"-rypes of Regulation,"* regulatory assets buying and selling financial energy contracts 41 (deferred expenses) and regulatory liabilities which includes exchange futures and options (future revenue reductiongor refunds) are and over-the-counter options and swaps.

recorded to reflect the economic effects of Although trading contracts are generally short regulation by matching in the same term, there are also long-term trading accounting period regulated expenses with contracts. We recognize revenues from their recovery through regulated revenues. trading activities generally based on changes in the fair value of energy trading contracts.

When regulatory assets are probable of recovery through regulated rates, we record Recording the net change in the fair them as assets on the balance sheet. We value of trading contracts as revenues prior to test for probability of recovery whenever new settlement is commonly referred to as mark events occur, for example a regulatory to-market (MTM) accounting. It represents commission order or passage of new the change in the unrealized gain or loss legislation. If we determine that recovery of a throughout the contract's term. When the regulatory asset is no longer probable, we contract actually settles, that is, the energy is write off that regulatory asset as a charge actually delivered in a sale or received in a against net income. A write off of regulatory purchase or the parties agree to forego assets may also reduce future cash flows delivery and receipt and net settle in cash, the since there may be no recovery through unrealized gain or loss is reversed out of regulated rates. revenues and the actual realized cash gain or loss is recognized in revenues for a sale or in purchased energy expense for a purchase.

A-6

jI I Therefore, over the term of the trading further impact on operating results but has an contracts an unrealized gain or loss is offsetting and equal effect on trading contract recognized as the contract's market value assets and liabilities. Of course we could also changes. When the contract settles the total do similar transactions but enter into a gain or loss is realized in cash but only the purchase contract prior to entering into a difference between the accumulated sales contract. If the sale and purchase unrealized net gains or losses recorded in contracts do not match exactly as to prior months and the cash proceeds is commodity type, volumes, delivery point, recognized. Unrealized mark-to-market gains schedule and other key terms, then there and losses are included in the Balance Sheet could be continuing mark-to-market effects on as energy trading and derivative contract revenues from recording additional changes assets or liabilities as appropriate. in fair values using mark-to-market accounting.

The 'najority of our tradin6 activities represent physical forward electricity and gas Trading of electricity and gas options, contracts that are typically settled by entering futures and swaps, represents financial into offsetting contracts. An example of our transactions with unrealized gains and losses trading activities is when, in January, we enter from changes in fair values reported net in into a forward sales contract to deliver revenues until the contracts settle. When electricity or gas in July. At the end of each these contracts settle, we record the net month until the contract settles in July, we proceeds in revenues and reverse to would record any difference between the revenues the prior unrealized gain or loss.

contract price and the market price as an unrealized gain or loss in revenues. In July The fair value of open short-term when the contract settles, we would realize trading contracts are based on exchange the gain or loss in cash and reverse to prices and broker quotes. We mark-to-market revenues the previously recorded unrealized open long-term trading contracts based gain or loss. Prior to settlement, the change mainly on Company-developed valuation in the fair value of physical forward sale and models. These models estimate future purchase contracts is included in revenues on energy prices based on existing market and a net basis. Upon settlement of a forward broker quotes and supply and demand market trading contract, the amount realized is data and assumptions.

included in revenues for a sales contract and The fair values determined are reduced by reserves to adjust realized costs are included in purchased for credit risk and liquidity risk. Credit risk is energy expense for a purchase contract with the risk that the counterparty to the contract the prior change in unrealized fair value will fail to perform or fail to pay amounts due reversed in revenues. AEP. Liquidity risk represents the risk that imperfections in the market will cause the Continuing with the above example, price to be less than or more than what the assume that later in January or sometime in price should be based purely on supply and February through July we enter into an demand. There are inherent risks related to offsetting forward contract to buy electricity or the underlying assumptions in models used to gas in July. If we do nothing else with these fair value open long-term trading contracts.

contracts until settlement in July and if the We have independent controls to evaluate the commodity type, volumes, delivery point, reasonableness of our valuation models.

schedule and other key terms match then the However, energy markets, especially difference between the sale price and the electricity markets, are imperfect and volatile purchase price represents a fixed value to be and unforeseen events can and will cause realized when the contracts settle in July. If reasonable price curves to differ from actual the purchase contract is perfectly matched prices throughout a contract's term and when with the sales contract, we have effectively contracts settle. Therefore, there could be fixed the profit or loss; specifically it is the significant adverse or favorable effects on difference between the contracted settlement future results of operations and cash flows if price of the two contracts. Mark-to-market market prices do not correlate with the accounting for these contracts will have no Company-developed price models.

A-7

has had a major effect on the volume of We also mark to market derivatives that wholesale power marketing and trading are not trading contracts in accordance with especially in the short-term market.

generally accepted accounting principles.

Derivatives are contracts whose value is AEP's total revenues increased 66.9%

derived from the market value of an in 2001 and 48.3% in 2000. The following underlying commodity. table shows the components of revenues in millions.

Our revenues of $61 billion for 2001 December For The Year 31 Ended included $257 million of unrealized net gains 2001 2000 (in millions) 1999 from marking to market open trading and derivative contracts. AEP's net revenues, WHOLESALE BUSINESS:

Residential $ 3,553 $ 3,511 $ 3,290 2,328 2,249 2,083 commercial (revenues less fuel and energy purchases) Industrial 2,388 2,444 2,515 excluding mark-to-market revenues totaled other Retail Customers 419 414 394

$8.3 billion and were realized during 2001.

Unrealized net mark-to-market revenues are Electricity Marketing 35,339 18,858 11,417 and Trading only 3% of total net revenues. A significant Gas Marketing and 2,290 portion of the net unrealized revenues from Trading 14,369 6,127 unrealized MTM Income:

marking to market trading contracts and Electric 210 38 2 21 132 derivatives included in our balance sheet at Gas 47 other 632 838 599 December 31, 2001 as energy trading and Less Transmission and Distribution Revenues derivative contract assets and liabilities, will Assigned to Energy 30-68) be realized in 2002. Delivery* 3-i-5)3--(174)

TOTAL WHOLESALE We defer as regulatory assets or BUSINESS 55,929 31.437 19,543 liabilities the effect on net income of marking ENERGY DELIVERY to market open electricity trading contracts in BUSINESS:

Transmission 1,029 1,009 960 our regulated jurisdictions since these Distribution 2,327 2,165 2.108 transactions are included in cost of service on TOTAL ENERGY DELIVERY 3,356 3,174 3,068 a settlement basis for ratemaking purposes.

Changes in mark-to-market valuations impact OTHER INVESTMENTS:

SEEBOARD 1,451 350 338 1,596 1,705 318 net income in our non-regulated business. CITIPOWER other 171 161 111 TOTAL OTHER INVESTMENTS 1,972 2,095 2,134 Volatility in energy commodities markets affects the fair values of all of our TOTAL REVENUES open trading and derivative contracts *Certain revenues in Wholesale business exposing AEP to market risk causing our include energy delivery revenues due primarily to bundled tariffs that are assignable to the results of operations to be more volatile. See Energy Delivery business.

"Market Risks" section below for a discussion of the policies and procedures AEP uses to The $25 billion increase in 2001 manage its exposure to market and other revenues was due to substantial increases in risks from trading activities. electric and gas trading volumes. The increase in sales of purchased power and Revenues Increase purchased gas during the past two years reflect AEP's intention to be a leading national Our revenues have increased wholesale energy merchant. Wholesale significantly from the marketing and trading of natural gas trading volume for 2001 was electricity and natural gas. The level of 3,874 Bcf, a 178% increase from 2000 electricity trading transactions tends to volume of 1,391 Bcf. Electric trading volume fluctuate due to the highly competitive nature increased 48% to 576 million MWH. We have of the short-term (spot) energy market and invested in resources required to optimize our other factors, such as affiliated and assets and emerge as a leader in the industry.

unaffiliated generating plant availability, The maturing of the Intercontinental weather conditions and the economy. The Exchange, the development of proprietary FERC's introduction of a greater degree of tools, and the increased staffing of energy competition into the wholesale energy market, A-8

ill1 traders have faciliated increased power and liquid product prices.

gas sales. Our June 2001 purchase of Houston Pipe Line enhanced our gas trading Operating Expenses Increase and marketing operation. Although we will trade and market only when we believe profitable opportunites exist, we expect the Changes in the components of operating expenses were as follows:

increased level of activity to continue.

Increase (Decrease)

While wholesale marketing and trading (Dollars in Millions)

From Previous Year 2001 2000 volumes rose, kilowatthour sales to industrial Amount  % Amount %o customers decreased by 5% in 2001. This Fuel and PurchasedA Energy $24,035 83.7 $11,474 66.5 decrease was due to the economic recession. Maintenance and In the fourth quarter, sales to residential, other Operation 196 5.1 565 17.2 Non-recoverable commercial and wholesale customers Merger Costs (182)(89.7) 203 N.M.

Depreciation and declined 9%. The recession reduced demand Amortization 133 10.6 38 3.1 and wholesale prices especially in the fourth Taxes other Than Income Taxes 22) (3.2) 19)(2.7) quarter. Total 6 69.6 i 54.6 While margins available from selling Our fuel and purchased energy power that the company generates generally expense in 2001 increased 84% due to are higher than from selling purchased power, increased trading volume and an increase in such sales are limited by the amount of nuclear generation cost. The return to service generating assets owned. Furthermore, the of the Cook Plant's two nuclear generating profit available from simply selling excess units in June 2000 and December 2000 generation is reduced by the inherent market accounted for the increase in nuclear transparency of such sales. The coordinated generation costs.

sales of excess generation in conjunction with trading and marketing activity optimizes Fuel and purchased energy expense assets, mitigates risk, and increases overall increased 67% in 2000 due to increased trading volume and a significant increase in profit.

the cost of natural gas used for generation.

Natural gas usage for generation declined 5%

The $12 billion increase in 2000 revenues was primarily due to a 27% increase while the cost of natural gas consumed rose in wholesale electricity trading volume and 60%. Net income was not impacted by this increased retail fuel revenues as a result of significant cost increase due to the operation higher gas prices used to generate electricity. of fuel recovery rate mechanisms. These fuel The reduction in industrial revenues in 2000 is recovery rate mechanisms generally provide attributable to the expiration of a long-term for the deferral of fuel costs above the contract on December 31, 1999. amounts included in existing rates or the The accrual of revenues for fuel costs not yet significant increase in 2000 electricity trading volume, which accounted for a 66% increase recovered. Upon regulatory commission in electricity trading revenues, resulted from: review and approval of the unrecovered fuel

"* efforts to grow AEP's energy marketing costs, the accrued or deferred amounts are billed to customers. With the introduction of and trading operations, customer choice of electricity supplier and a

"* favorable market conditions, and transition to market-based generation rates,

"* the availability of additional generation the protection offered by fuel recovery mechanisms against changes in fuel costs Generation availability improved due to was eliminated in Ohio effective January 1, the return to service of one of the Cook Plant 2001 and in the ERCOT area of Texas nuclear units in June 2000 and to improved effective January 1, 2002. As a result, AEP's outage management. The second Cook Plant exposure to the risk of fuel price increases unit which returned to service in December that could adversely affect future results of 2000 did not have a significant impact on operations and cash flows is increasing. See 2000 revenues. Gas revenues increased in Note 1 for applicability of fuel recovery 2000 due to increased natural gas and gas mechanisms by jurisdiction.

A-9

Interest. Preferred Stock Dividends, Minority Maintenance and other operation Interest expense rose in 2001 mainly as a result of additional traders' incentive compensation Interest expense deceased 15% in and accruals for severance costs related to 2001 due to the effect of interest paid the IRS corporate restructuring. on a COLI deduction disallowance in 2000 and lower average outstanding short-term The increase in maintenance and other debt balances and a decrease in average operation expense in 2000 was mainly due to short-term interest rates.

increased expenditures to prepare the Cook Plant nuclear units for restart following an In 2001 we issued a preferred member extended NRC monitored outage and interest to finance the acquisition of HPL and increased usage and prices of emissions paid a preferred return of $13 million to the allowances. The increase in Cook Plant preferred member interest.

restart costs resulted from the effect of deferring restart costs in 1999 and an In 2000 interest increased by 17% due increase in the restart expenditure level in to additional interest expense from the ruling 2000. Cook Plant began its extended outage disallowing COLI tax deductions and AEP's in September 1997 when both nuclear effort to maintain flexibility for corporate generating units were shut down because of separation by issuing short-term debt at questions regarding the operability of certain flexible rates. The use of fixed interest rate safety systems. In 1999 a portion of swaps has been employed to mitigate the risk incremental restart expenses were deferred in from floating interest rates.

accordance with IURC and MPSC settlement agreements which resolved all jurisdictional Other Income rate-related issues related to the Cook Plant's extended outage. With NRC approval Unit 2 Other income increased $166 million in returned to service in June and achieved full 2001. This increase was primarily caused by power operation on July 5, 2000 and Unit 1 the sale in March 2001 of Frontera, a returned to service in December and achieved generating plant required to be divested under full power operation on January 3, 2001. The a FERC approved merger settlement agree increase in emission allowance usage and ment, which produced a pretax $73 million prices resulted from the stricter air quality gain and the effect from the December 2000 standards of Phase II of the 1990 Clean Air impairment writedown of $43 million to reflect Act Amendments, which became effective on the pending sale of AEP's Yorkshire January 1, 2000. investment.

With the consummation of the merger Other income decreased $66 million in with CSW, certain deferred merger costs were 2000 primarily due to a loss in equity earnings expensed in 2000. The merger costs charged from the 2000 write-down of the Yorkshire to expense included transaction and transition investment and losses from certain non costs not allocable to and recoverable from regulated subsidiaries accounted for on an ratepayers under regulatory commission equity basis. Other expenses increased in approved settlement agreements to share net 2000 mainly from a charge for the merger savings. As expected merger costs discontinuance of an electric storage water declined in 2001 after the merger was heater demand side management program of consummated. the regulated business.

Depreciation and amortization expense Income Taxes increased in 2001 primarily as a result of the commencement of amortization of transition Although pre-tax book income generation regulatory assets in the Ohio, increased considerably, income taxes Virginia and West Virginia jurisdictions due to decreased due to the effect of recording in passage of restructuring legislation, the new 2000 prior year federal income taxes as a businesses acquired in 2001 and additional result of the disallowance of COLI interest investments in property, plant and equipment.

A-10

II1 deductions by the IRS and nondeductible 2000 for the Ohio, Virginia and West Virginia merger related costs in 2000. jurisdictions which resulted in the after tax extraordinary loss of $35 million.

Income taxes increased in 2000 over 1999 levels primarily due to the disallowance New accounting rules that became of the COLI interest deductions and the non effective in 2001 regarding accounting for deductible merger related costs discussed derivatives required us to mark to market above. certain fuel supply contracts that qualify as financial derivatives. The effect of initially Extraordinary Losses and Cumulative Effect adopting the new rules at July 1, 2001 was a favorable earnings effect of $18 million, net of In 2001 we recorded an extraordinary tax, which is reported as a cumulative effect loss of $48 million net of tax to write-off of accounting change.

prepaid Ohio excise taxes stranded by Ohio deregulation. The application of regulatory accounting for generation was discontinued in A-11

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Income (in millions - except per share amounts) Year Ended December 31, 2001 2000 1999 REVENUES: $41,513 $25,178 $17,232 Electricity Marketing and Trading 14,416 6,259 2,311 Gas Marketing and Tradin9 3,356 3,174 3,068 Domestic Electricity Delivery 1,972 2,095 2,134 Other Investment 36,706 24,745 TOTAL REVENUES 61,257 EXPENSES:

Fuel and Purchased Energy: 37,558 21,246 13,646 Electricity Marketing and Trading 14,004 6,227 2,305 Gas Marketing and Trading 1,191 1,245 1,293 other Investment 52,753 28,718 17,244 TOTAL FUEL AND PURCHASED ENERGY 3,841 3,276 4,037 Maintenance and other operation 21 203 Non-recoverable Merger Costs 1,383 1,250 1,212 Depreciation and Amortization 668 690 709 Taxes other Than income Taxes 58,862 34,702 22,44 TOTAL EXPENSES 2,395 2,004 2,304 OPERATING INCOME 302 136 202 OTHER INCOME 130 81 42 OTHER EXPENSES 972 1,149 977 LESS: INTEREST 10 11 19 PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES 13 -

MINORITY INTEREST IN FINANCE SUBSIDIARY 1,572 899 1,468 INCOME BEFORE INCOME TAXES 569 597 482 INCOME TAXES 1,003 302 986 INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT EXTRAORDINARY LOSSES (NET OF TAX): (48) (35) (8)

DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION (2) - (6)

LOSS ON REACQUIRED DEBT 18 -

CUMULATIVE EFFECT OF ACCOUNTING CHANGE

$ 971 $167 $ 972 NET INCOME 322 322 31 AVERAGE NUMBER OF SHARES OUTSTANDING EARNINGS PER SHARE: $0.94 $3.07 Income Before Extraordinary Item and Cumulative Effect $ 3.11 (0.16) (.11) (.04)

Extraordinary Losses cumulative Effect of Accounting change .06 -

Earnings Per share (Basic and Dilutive) $J1 "10B3 13-M

$2.40 S2_0_ 12.40 CASH DIVIDENDS PAID PER SHARE See Notes to consolidated Financial Statements beginning on page L-1.

A-12

• II AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Balance Sheets (in millions - except share data)

December 31, 2001 2000 ASSETS CURRENT ASSETS:

cash and cash Equivalents $ 333 $ 342 Accounts Receivable:

Customers 626 888 Miscellaneous 1,365 2,883 Allowance for Uncollectible Accounts (109) (72)

Energy Trading and Derivative Contracts 8,572 15,497 Other 1,776 1,363 TOTAL CURRENT ASSETS 12,563 20,901 PROPERTY PLANT AND EQUIPMENT:

Electric:

Production 17,477 16,328 Transmission 5,879 5,609 Distribution 11,310 10,843 Other (including gas and coal mining assets And nuclear fuel) 4,941 4,077 Construction work in Progress 1,102 1,231 Total Property, Plant and Equipment 40,709 38,088 Accumulated Depreciation and Amortization 16,166 15,695 NET PROPERTY, PLANT AND EQUIPMENT 24,543 22,393 REGULATORY ASSETS 3,162 3,698 INVESTMENTS IN POWER, DISTRIBUTION AND COMMUNICATIONS PROJECTS 677 782 GOODWILL (NET OF AMORTIZATION) 1,494 1,382 LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS 2,370 1,552 OTHER ASSETS 2,472 2,642 TOTAL 47u.81 See Notes to Consolidated Financial Statements beginning on page L-1.

A-13

COMPANIES AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY Consolidated Balance Sheets December 31.

2001 2000 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: $ 2,627

$ 2,245 Accounts Payable 3,155 4,333 short-term Debt 2,300 1,152 Long-term Debt Due within one Year* 8,311 15,671 Energy Trading and Derivative Contracts 2,088 2,154 other 18,099 25,937 TOTAL CURRENT LIABILITIES 9,753 9,602 LONG-TERM DEBT*

CONTRACTS 2,183 1,313 LONG-TERM ENERGY TRADING AND DERIVATIVE 4,823 4,875 DEFERRED INCOME TAXES 491 528 DEFERRED INVESTMENT TAX CREDITS 948 637 DEFERRED CREDITS AND REGULATORY LIABILITIES 194 203 DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 1,334 1,706 OTHER NONCURRENT LIABILITIES COMMITMENTS AND CONTINGENCIES (Note 8)

REDEEMABLE, CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY OF SUBSIDIARY TRUSTS HOLDING PREFERRED SECURITIES SUBORDINATED DEBENTURES OF SUCH 321 334 SOLELY JUNIOR SUBSIDIARIES 750 MINORITY INTEREST IN FINANCE SUBSIDIARY 156 161 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*

COMMON SHAREHOLDERS' EQUITY:

Common Stock-Par Value $6.50:

2001 2000 shares Authorized. .600,000,000 600,000,000 shares Issued. . . .331,234,997 331,019,146 (8,999,992 shares were held in treasury 2,153 2,152 at December 31, 2001 and 2000) 2,906 2,915 Paid-in capital (126) (103)

Accumulated other comprehensive Income (Loss) 3,296 3,090 Retained Earnings 8,229 8,054 TOTAL COMMON SHAREHOLDERS' EQUITY

$47,281 $53 TOTAL

• See Accompanying schedules.

A-14

1II AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Cash Flows (in millions)

Year Ended December 31, 2001 2000 1999 OPERATING ACTIVITIES:

Net Income Adjustments for Noncash Items: $ 971 $ 267 972 Depreciation and Amortization Deferred Federal Income Taxes 1,413 1,299 1,294 Deferred Investment Tax Credits 163 (170) 180 Amortization (Deferral) of Operating (29) (36) (38)

Expenses and Carrying Charges (net)

Equity in Earnings of Yorkshire Electricity 40 48 (151)

Group r 1Ic Extraordinary Loss (44) (45)

Cumulative Effect of Accounting Change 50 35 14 Deferred Costs Under Fuel Clause Mechanisms (18)

Mark to Market of Energy Trading Contracts 340 (449) (191)

Miscellaneous Accrued Expenses (257) (170) (23)

Changes in Certain Current Assets and Liabilities: (384) 217 101 Accounts Receivable (net)

Fuel, Materials and Supplies 1,764 (1,632) (80)

Accrued Utility Revenues (82) 147 (162)

Accounts Payable 26 (79) (35)

Taxes Accrued (461) 1,322 74 Premium Options (147) 172 29 Payment of Disputed Tax and Interest Related (76) 74 8 to COLI Change in Other Assets 319 (16)

Change in other Liabilities (213) (92) (87)

Net Cash Flows From Operating Activities C147) 2,953 205 (245) 1,433 1,599 INVESTING ACTIVITIES:

Construction Expenditures Purchase of Houston Pipe Line (1,832) (1,773) (1,680)

Purchase of U.K. Generation (727)

Purchase of Quaker Coal Co. (943)

Purchase of Memco (101)

Purchase of Indian Mesa (266)

Sale of Yorkshire (175)

Sale of Frontera 383 other 265 Net cash Flows used For Investing Activities (36) 19 7 C3 432) 1,754) 1,673)

FINANCING ACTIVITIES:

Issuance of Common stock Issuance of Minority Interest 10 14 93 Issuance of Long-term Debt 747 Retirement of Cumulative Preferred Stock 2,931 1,124 1,391 Retirement of Long-term Debt (5) (20) (170)

Change in short-term Debt (net) (1,835) (1,565) (915)

Dividends Paid on common Stock (597) 1,308 812 Dividends on Minority Interest in subsidiary (773) (805) (833) other Financing Activities (5)

Net Cash Flows From Financing Activities (43) 473 56 335 Effect of Exchange Rate change on cash (3) 23 (2)

Net Increase (Decrease) in cash and cash Equivalents Cash and cash Equivalents January 1 (9) (242) 259 Cash and Cash Equivalents December 31 342 584 325 E:333 $ý 342 See Notes to Consolidated Financial Statements $ 584 beginning on page L-1.

A-15

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Consolidated Statements of Common Shareholders' Equity and Comprehensive Income (in millions)

Accumulated other Common Stock Paid-In Retained comprehensive shares Amount capi tal Earnings Income (Loss) Total JANUARY 1, 1999 328 $2,134 $2,818 $3,493 $7 $8,452 Issuances 3 15 77 92 Retirements and other 3 3 cash Dividends Declared (833) (833) other (2) (2_)

7,712 com prehensive Income:

Other comprehensive Income, Net of Taxes Foreign currency Translation Adjustment (13) (13)

Minimum Pension Liability 2 2 Net Income 972 972 Total comprehensive Income 961 DECEMBER 31, 1999 331 2,149 2,898 3,630 (4) 8,673 Issuances 3 11 14 cash Dividends Declared (805) (805) other (2) 4 7,886 com prehensive Income:

Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment (119) (119)

Reclassification Adjustment For LOSS Included in Net Income 20 20 Net Income 267 267 Total comprehensive Income 168 DECEMBER 31, 2000 331 2,152 2,915 3,090 (103) $8,054 E>A &.

Issuances 1 9 10 cash Dividends Declared (773) (773) other (18) 8 (10) 7,281 com prehensive income:

Other comprehensive Income, Net of Taxes Foreign Currency Translation Adjustment (14) (14)

Unrealized Gain (LOSS) on Hedged Derivatives (3) (3)

Minimum Pension Liability (6) (6)

Net Income 971 971 Total Comprehensive Income 948 DECEMBER 31, 2001 M See Notes to consolidated Financial Statements.

A-16

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries December 31, 2001 call Price per Shares Shares Amount (In share Ca) AuthorizedCb) Outstandinq(f) Millions]

Not subject to Mandatory Redemption:

4.00% - 5.00% $102-$110 1,525,903 614,608 $6J.

Subject to Mandatory Redemption:

5.90% - 5.92% (c) (d) 1,950,000 333,100 $33 6.02% 7/8% Cc) $100 1,650,000 513,450 52 7% (e) Ce) 250,000 100,000 10 Total Subject to Mandatory Redemption (c) $95 December 31, 2000 Call Price per Shares shares Amount (In share (a) Authorizedb) outstandinoCf) Millions)

Not subject to Mandatory Redemption:

4.00% - 5.00% $102-$110 1,525,903 614,608 16 subject to Mandatory Redemption:

5.90% - 5.92% (c) (d) 1,950,000 333,100 $ 33 6.02% 7/8% (c) $100 1,650,000 513,450 52 7% (e) (e) 250,000 150,000 15 Total Subject to Mandatory Redemption (c) iiao NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES (a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends.

The invol untary liquidation preference is $100 per share for all outstanding shares.

(b) As of December 31, 2001 the subsidiaries had 13,642,750, 22,200,000 and 7,713,495 shares of $100, $25 and no par value preferred stock, respectively, that were authorized but unissued.

(c) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds(generally at par) and reacquisitions of shares in anticipation of future requirements.

The subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed. The sinking fund provisions of the series subject to mandatory redemption aggregate (after deducting sinking fund requirements) of $5 million in 2002 and $5 million in 2003.

(d) Not callable prior to 2003; after that the call price is $100 per share.

(e) with sinking fund.

(f) The number of shares of preferred stock redeemed is 50,000 shares in 2001, 209,563 shares in 2000 and 1,698,276 shares in 1999.

A-17

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES Schedule of Consolidated Long-term Debt of Subsidiaries weighted Average Maturity Interest Rate Interest Rates at December 31, December 31, December 31, 2001 2001 2000 2001 2000 (in millions)

FIRST MORTGAGE BONDS (a) 2001-2003 6.95% 6.00%-7.70% 5.91%-8.95% $ 852 $ 1,247 2004-2008 6.98% 6-1/8%-8.00% 6-1/8%-8% 1,092 1,140 2020-2025 7.66% 6-7/8%-8.80% 6-7/8%-8.80% 850 1,104 INSTALLMENT PURCHASE CONTRACTS (b) 2001-2009 4.30% 1.80%-7.70% 4.90%-7.70% 446 234 2011-2030 5.88% 1.55%-8.20% 4.875%-8.20% 1,234 1,447 NOTES PAYABLE (c) 2001-2021 5.41% 4.0483%-9.60% 6.20%-9.60% 2,237 1,181 SENIOR UNSECURED NOTES 2001-2004 4.81% 2.31%-7.45% 6.50%-7.45% 1,874 2,049 2005-2009 6.24% 6.125%-6.91% 6.24%-6.91% 1,763 475 2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340 JUNIOR DEBENTURES 2025-2038 8.05% 7.60%-8.72% 7.60%-8.72% 618 620 YANKEE BONDS AND EURO BONDS 2001-2006 8.71% 8.50%-8.875% 7.98%-8. 875% 479 684 OTHER LONG-TERM DEBT (d) 308 280 Unamortized Discount (net) (47)

Total Long-term Debt Outstanding (e) 12,053 10,754 Less Portion Due within one Year 2,300 1,152 Long-term Portion NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES (a) First mortgage bonds are secured by first mortgage liens on electric property, plant and equipment.

(b) For certain series of installment purchase contracts interest rates are subject to periodic adjustment. certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from banks and standby bond purchase a reements support certain series.

(c) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. variable rates generally relate to specified short-term interest rates.

(d) other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear fuel (see Note 8 of the Notes to consolidated Financial Statements) and financing obligation under sale lease back agreements.

(e) Long-term debt outstanding at December 31, 2001 is payable as follows:

Principal Amount (in millions) 2002 $ 2,300 2003 2,086 2004 902 2005 616 2006 1,943 Later Years 4.246 Total Principal Amount 12,093 Unamortized Discount 40 Total I-A-18

AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES Index to Notes to Consolidated Financial Statements The notes listed below are combined and its other subsidiary registrants.with the notes to financial statements for AEP The combined footnotes begin on page L-1.

Combined Footnote Reference Significant Accounting Policies Note 1 Extraordinary Items and Cumulative Effect Note 2 Merger Note 3 Nuclear Plant Restart Note 4 Rate Matters Note 5 Effects of Regulation Note 6 Customer choice and Industry Restructuring Note 7 Commitments and Contingencies Note 8 Acquisitions and Dispositions Note 9 Benefit Plans Note 10 Stock-Based compensation Note 11 Business Segments Note 12 Risk Management, Financial Instruments And Derivatives Note 13 Income Taxes Note 14 Basic and Diluted Earnings Per share Note 15 Supplementary Information Note 16 Power, Distribution and Communications Projects Note 17 Leases Note 18 Lines of Credit and Sale of Receivables Note 19 Unaudited Quarterly Financial Information Note 20 Trust Preferred Securities Note 21 Minority Interest in Finance subsidiary Note 22 A-19

MANAGEMENT'S RESPONSIBILITY The management of American Electric Power Company, Inc. is responsible for the integrity and objectivity of the information and representations in this annual report, including the consolidated financial statements. These statements have been prepared in conformity with generally accepted accounting principles, using informed estimates where appropriate, to reflect the Company's financial condition and results of operations. The information in other sections of the annual report is consistent with these statements.

The Company's Board of Directors has oversight responsibilities for determining that management has fulfilled its obligation in the preparation of the financial statements and in the ongoing examination of the Company's established internal control structure over financial reporting. The Audit Committee, which consists solely of outside directors and which reports directly to the Board of Directors, meets regularly with management, Deloitte & Touche LLP - independent auditors and the Company's internal audit staff to discuss accounting, auditing and reporting matters. To ensure auditor independence, both Deloitte &

Touche LLP and the internal audit staff have unrestricted access to the Audit Committee.

The financial statements have been audited by Deloitte & Touche LLP, whose report appears on the next page. The auditors provide an objective, independent review as to management's discharge of its responsibilities insofar as they relate to the fairness of the Company's reported financial condition and results of operations. Their audit includes procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement and includes an evaluation of the Company's internal control structure over financial reporting.

A-20

t11 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 its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, cash flows, and common shareholders' equity and comprehensive income for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of American Electric Power Company, Inc. and its subsidiaries and Central and South West Corporation and its subsidiaries, which has been accounted for as a pooling of interests as described in Note 3 to the consolidated financial statements. We did not audit the consolidated statements of income, and cash flows, and stockholder's equity and comprehensive income of Central and South West Corporation and its subsidiaries for the year ended December 31, 1999, which statements reflect total revenues of $5,516,000,000 for the year ended December 31, 1999. Those consolidated statements, before the restatement described in Note 3, were audited by other auditors whose report, dated February 25, 2000, has been furnished to us, and our opinion, insofar as it relates to those amounts included for Central and South West Corporation and its subsidiaries for 1999, is based solely on the report of such other auditors.

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

In our opinion, based on our audits and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of American Electric Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

We also audited the adjustments described in Note 3 that were applied to restate the 1999 financial statements to give retroactive effect to the change in the method of accounting for vacation pay accruals. In our opinion, such adjustments are appropriate and have been properly applied.

Deloitte &Touche LLP Columbus, Ohio February 22, 2002 A-21

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

[II

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NDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

elected Consolidated Financial Data Year Ended December 31, _____

2001 2000 1999 1998 1997 (in thousands)

ENCOME STATEMENTS DATA:

Operating Revenues $4,803,625 $3,542,084

$2,920,187 $2,435,646 $1,391,917 Operating Expenses 4,643,920 3,576,786 2,811,535 2,.269,639 1.,184,129 Operating Income (Loss) 159,705 (34,702) 108,652 166,007 207,788 Nonoperating Income (Loss) 9,730 9,933 4,530 (839) 4,415 Interest charges 93,647 107,263 80,406 68,540 65,463 Net Income (LOSS) 75,788 (132,032) 32,776 96,628 146,740 Preferred Stock Dividend Requirements 4,621 4,624 4,885 4,824 5,736 Earnings (Loss)

Applicable to Common Stock $ 27.891 $ 91 ,8_ $ 141.00~4 December 31, 2001 2000 1999 1998 1997 (in thousands)

BALANCE SHEETS DATA:

Electric Utility Plant $4,923,721 $4,871,473 $4,770,027 $4,631,848 $4,514,497 Accumulated Depreciation and Amorti zati on 2,436,972 2,280,521 2,194,397 2,081,355 1,973,937 Net Electric Utility Plant $2,~48679 $2,550,4*93 Total Assets $4,817,008 $5.811.038 $4.148. 2 $3,967,798 Common Stock and Paid-in capital $ 789,800 $ 789,656 $ 789,323 $ 789,189 $ 789,056 Accumulated other comprehensive Income (LOSS) (3,835)

Retained Earnings 74,605 3,443 166,389 253,154 278,814 Total Common Shareholder's Equity $ 8,6 $ 793,099 $ 955,712 $1,0427343 1 9,435 Cumulative Preferred stock:

Not subject to Mandatory Redemption $ 8,736 $ 8,736 $ 9,248 $ 9,273 $ 9,435 Subject to Mandatory Redemption (a) 64,945 64,945 64.,945 68,445 68,445 Total Cumulative Preferred Stock $ 73,681 $ 73,681 S 74,193 $ 77,718 $ 77,880 Long-term Debt (a) $1, 324.326 $1. 049. 237 Obligations under 195_ý222 capital Leases (a) $4 1766965 Total capitalization And Liabilities 4A5_4j6 59 $4,148,523 $3,967,798 si4,817,008 $_5,811,038 (a) Including portion due within one year.

F-i

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Manaaement's Discussion and Analysis of Results of Operations I&M is a public utility engaged in the Critical Accounting Policies - Revenue generation, purchase, sale, transmission and Recognition distribution of electric power to 567,000 retail customers in its service territory in northern Regulatory Accounting - As a cost-based rate and eastern Indiana and a portion of regulated electric public utility company, I&M's southwestern Michigan. As a member of the consolidated financial statements reflect the AEP Power Pool, I&M shares the revenues actions of regulators that can result in the and the costs of the AEP Power Pool's recognition of revenues and expenses in wholesale sales to neighboring utilities and different time periods than enterprises that are power marketers including power trading not rate regulated. In accordance with SFAS transactions. I&M also sells wholesale power 71, regulatory assets (deferred expenses) and to municipalities and electric cooperatives. regulatory liabilities (future revenue reductions or refunds) are recorded to reflect the The cost of the AEP System's economic effects of regulation by matching generating capacity is allocated among the expenses with their recovery through AEP Power Pool members based on their regulated revenues in the same accounting relative peak demands and generating period.

reserves through the payment of capacity charges and the receipt of capacity credits. When regulatory assets are probable of AEP Power Pool members are also recovery through regulated rates, we record compensated for the out-of-pocket costs of them as assets on the balance sheet. We energy delivered to the AEP Power Pool and test for probability of recovery whenever new charged for energy received from the AEP events occur, for example a regulatory Power Pool. The AEP Power Pool calculates commission order or passage of new each company's prior twelve month peak legislation. If we determine that recovery of a demand relative to the total peak demand of regulatory asset is no longer probable, we all member companies as a basis for sharing write off that regulatory asset as a charge revenues and costs. The result of this against net income. A write off of regulatory calculation is each company's member load assets may also reduce future cash flows ratio (MLR) which determines each company's since there may be no recovery through percentage share of revenues and costs. regulated rates.

I&M is committed under unit power Traditional Electricity Supply and Delivery agreements to purchase all of AEGCo's 50% Activities - We recognize revenues on an share of the 2,600 MW Rockport Plant accrual basis for electricity supply sales and capacity unless it is sold to other utilities. electricity transmission and distribution AEGCo is an affiliate that is not a member of delivery services. The revenues are the AEP Power Pool. A long-term unit power recognized in our income statement when the agreement with an unaffiliated utility expired energy is delivered to the customer and at the end of 1999 for the sale of 455 MW of include unbilled as well as billed amounts, In AEGCo's Rockport Plant capacity. An general expenses are recorded when agreement between AEGCo and KPCo incurred.

provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.

F-2

Energy Marketing and Trading Activities with delivery points outside of AEP's AEP engages in wholesale electricity traditional marketing area the unrealized gain marketing and trading transactions (trading or loss is recognized as nonoperating income.

activities). A portion of the revenues and costs When the contract settles the total gain or of AEP's trading activities are allocated to l&M loss is realized in cash and the impact on the as a member of the AEP Power Pool. Trading income statement depends on whether the activities involve the purchase and sale of contract's delivery points are within or outside energy under physical forward contracts at of AEP's traditional marketing area. For fixed and variable prices and buying and contracts with delivery points in AEP's selling financial energy contracts which traditional marketing area, the total gain or includes exchange traded futures and options loss realized in cash is recognized in the and over-the-counter options and swaps. The income statement. Physical forward trading majority of trading activities represent physical sale contracts with delivery points in AEP's forward electricity contracts that are typically traditional marketing area are included in settled by entering into offsetting physical revenues when the contracts settle. Physical contracts. Although trading contracts are forward trading purchase contracts with generally short-term, there are also long-term delivery points in AEP's traditional marketing trading contracts. area are included in purchased power expense when they settle. Prior to settlement, Accounting standards applicable to changes in the fair value of physical forward trading activities require that changes in the sale and purchase contracts in AEP's fair value of trading contacts be recognized in traditional marketing area are deferred as revenues prior to settlement and is commonly regulatory liabilities (gains) or regulatory referred to as mark-to-market (MTM) assets (losses). For contacts with delivery accounting. Since I&M is a cost-based rate 4.

points outside of AEP's traditional marketing regulated entity, changes in the fair value of area only the difference between the physical forward sale and purchase contracts accumulated unrealized net gains or losses in AEP's traditional marketing area are recorded in prior months and the cash deferred as regulatory liabilities (gains) or proceeds is recognized in the income regulatory assets (losses). The deferral statement. Physical forward sales contracts reflects the fact that power sales and for delivery outside of AEP's traditional purchases are included in regulated rates on marketing area are included in nonoperating a settlement basis. AEP's traditional income when the contract settles. Physical marketing area is up to two transmission forward purchase contracts for delivery systems from the AEP service territory. The outside of AEP's traditional marketing area change in the fair value of physical forward are included in nonoperating expenses when sale and purchase contracts outside AEP's the contract settles. Prior to settlement, traditional marketing area is included in changes in the fair value of physical forward nonoperating income on a net basis.

sale and purchase contracts with delivery points outside of AEP's traditional marketing Mark-to-market accounting represents area are included in nonoperating income on the change in the unrealized gain or loss a net basis. Unrealized mark-to-market gains throughout the contract's term. When the and losses are included in the Balance Sheet contract actually settles, that is, the energy is as energy trading contract assets or liabilities actually delivered in a sale or received in a as appropriate.

purchase or the parties agree to forego delivery and receipt of electricity and net settle Trading of electricity options, futures in cash, the unrealized gain or loss is and swaps, represents financial transactions reversed and the actual realized cash gain or loss is recognized in the income statement. with unrealized gains and losses from changes in fair values reported net in non Therefore, as the contract's market value operating income until the contracts settle.

changes over the contract's term an When these financial contracts settle, we unrealized gain or loss is deferred for record our share of the net proceeds in non contracts with delivery points in AEP's operating income and reverse to nonoperating traditional marketing area and for contracts income the prior unrealized gain or loss.

F-3

IIl The fair value of open short-term and was the primary reason for a $208 million trading contracts are based on exchange increase in net income. As a result of the prices and broker quotes. We mark-to-market costs incurred in 2000 to restart the Cook open long-term trading contracts based Plant nuclear units and a disallowance of mainly on AEP-developed valuation models. interest deductions for a corporate owned life These models estimate future energy prices insurance (COLI) program, net income based on existing market and broker quotes declined $165 million in 2000. In February and supply and demand market data and 2001 the U.S. District Court for the Southern assumptions. The fair values determined are District of Ohio ruled against AEP and certain reduced by reserves to adjust for credit risk of its subsidiaries, including I&M, in a suit over and liquidity risk. Credit risk is the risk that the deductibility of interest claimed in AEP's counterparty to the contract will fail to perform consolidated tax return related to COLL. In or fail to pay amounts due AEP. Liquidity risk 1998 and 1999 I&M paid the disputed taxes represents the risk that imperfections in the and interest attributable to the COLI interest market will cause the price to be less than or deductions for the taxable years 1991-98 and more than what the price should be based deferred them.

purely on supply and demand. There are inherent risks related to the underlying Operating Revenues Increase assumptions in models used to fair value open long-term trading contracts. AEP has Operating revenues increased 36% in independent controls to evaluate the 2001 and 21% in 2000 due to increased reasonableness of our valuation models. wholesale marketing and trading sales. The However, energy markets, especially following analyzes the changes in operating electricity markets, are imperfect and volatile revenues:

and unforeseen events can and will cause Increase (Decrease) reasonable price curves to differ from actual From Previous Year (dollars in millions) prices throughout a contract's term and when 2001 2000 contracts settle. Therefore, there could be Amount  % Amount  %

significant adverse or favorable effects on Retail * $ (2.3) N.M. $(88.6) (12)

Marketing future results of operations and cash flows if and Trading 1,210.7 52 564.0 32 market prices do not correlate with the AEP other 5.0 13 C13 .0) (26) 1,213.4 40 462.4 18 developed price models. Energy Dellvery* 3.4 1 0.1 N.M.

Sales to AEP Volatility in commodities markets Affiliates 44.7 21 159.4 313 affects the fair values of all of our open Total LZ6IS 36 $6-12 21 trading contracts exposing I&M to market risk. N.M. = Not Meaningful See "Market Risks" section of MD&A for a *Reflects the allocation of certain discussion of the policies and procedures transmission and distribution revenues included in bundled retail rates to energy used to manage exposure to risk from trading delivery.

activities.

The increase in operating revenues in Results of Operations 2001 and 2000 is primarily due to an increase in wholesale marketing and trading activities.

During 2000 both of the Cook Plant The maturing of the Intercontinental nuclear units were successfully restarted after Exchange, the development of proprietary being shutdown in September 1997 due to tools, and increased staffing of energy traders questions regarding the operability of certain have resulted in an increase in the number of safety systems which arose during a NRC forward electricity purchase and sale architect engineer design inspection. See contracts in AEP's traditional marketing area.

discussion in Note 4 of the Notes to Financial A decline in retail revenues partly offset the Statements. increase in wholesale marketing and trading revenues. Retail revenues decreased in 2000 A reduction in other operation and when the accrual of power supply recovery maintenance expense in 2001 reflects the revenues ceased at the end of 1999 pursuant completion of restart work on the Cook Plant to Cook Plant settlement agreements. The F-4

Pool declined 21% in 2001. As a result of the accrued power supply recovery revenues are expiration of AEGCo's power sale contract being amortized over a five-year period with an unaffiliated utility on December 31, ending December 31, 2003. 1999, I&M was obligated to buy more of AEGCo's share of Rockport Plant power.

I&M increased its sales to AEP affiliates Purchases from AEGCo increased 91% in in 2000 when additional electricity became 2000.

available. The return to service of the Cook The decrease in other operation and Plant units and purchasing more power from maintenance expenses in 2001 was primarily AEGCo due to the expiration of AEGCo's due to the cessation of expenditures to contract to sell power to an unaffiliated entity, prepare the Cook Plant nuclear units for increased the amount of power I&M could sell restart with their return to service in 2000.

to its affiliates in the AEP Power Pool. Other operation and maintenance expenses increased in 2000 primarily due to Operating Expenses Increase expenditures to prepare the Cook Plant units for restart. In 1999 the IURC and MPSC Total operating expenses increased approved settlement agreements which 30% in 2001 and 27% in 2000 primarily due to allowed the deferral of $200 million of Cook I, additional purchases of power for marketing Plant restart costs in 1999 for amortization and trading and due to the expiration of an over five years from 1999 through 2003. As a AEGCo unit power agreement to sell part of result, other operation and maintenance its Rockport Plant generation to an unaffiliated expense in 1999 reflected a net deferral of utility. Also contributing to the increase in $160 million. See discussion in Note 4 of the operating expenses in 2000 was the Notes to Financial Statements.

unfavorable COLI tax ruling and costs related to the extended Cook Plant outage and restart The increase in depreciation and efforts. The changes in the components of amortization charges in 2001 reflects operating expenses were: increased generation and distribution plant Increase (Decrease) investments and amortization of I&M's share From Previous Year of deferred merger costs.

(dollars in millions) 2001 200U Amount  % Amount. Taxes other than income taxes Fuel $ 39.2 19 $ 25.5 14 increased in 2001 due to higher real and Marketing and Trading personal property tax expense from the effect Purchases 1,227.7 59 462.9 29 of a favorable accrual adjustment recorded in AEP Affiliate Purchases (27.2) (10) 65.1 32 30 December 2000 to match estimated amounts 137.5 other operation (147.8)

(92.6)

(25)

(42) 84.5 62 with actual expenses. The decrease in taxes Maintenance Depreciation an( 6 4.9 3 other than income tax in 2000 is primarily 9.3 Amortization attributable to decreases in real and personal Taxes Other Thai Income Taxes 4.9 53.6 N.M.

8 (5.2) (8)

(95) property taxes reflecting the favorable accrual Income Taxes _ (9.)

Total $.O. 30 27 adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual adjustment N.M. = Not Meaningful related to the 1998 tax year recorded in 1999 The increase in fuel expense in 2001 for gross receipts tax.

and 2000 reflects an increase in nuclear generation as the Cook Plant units returned to The significant increase in income taxes service following the extended outage. attributable to operations in 2001 is due to an increase in pre-tax operating income. Income Electricity marketing and trading taxes attributable to operations decreased in purchased power expense increased in 2001 2000 due to a decrease in pre-tax operating and 2000 due to AEP's effort to grow its income.

wholesale marketing and trading business.

The decline in purchased power from AEP affiliates in 2001 reflects generation from the Cook Plant replacing purchases from the AEP Power Pool. Purchases from the AEP Power F-5

ýI .

Nonoperating Income and Expenses Increase Interest Charges The increases in nonoperating income The decrease in 2001 interest charges and expenses in 2001 and 2000 is primarily reflects the recognition in 2000 of deferred due to increased volume of forward electricity interest payments to the IRS on disputed trading transactions outside AEP's traditional income taxes from the disallowance of tax marketing area. Nonoperating power trading deductions for COLI interest for the years revenues increased 70% in 2001 and 95% in 1991-1998. Interest charges increased in 2000. Nonoperating power trading expenses 2000 due to increased borrowings to support increased 70% in 2001 and 93% in 2000. expenditures for the Cook Plant restart effort and the recognition of deferred interest payments to the IRS on the disputed taxes.

F-6

IDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES nnsolidated Statements of Income Year Ended December 31, 2001 2000 1999 (in thousands)

PERATING REVENUES:

Electricity Marketing and Trading $4,234,176 $3,020,757 $2,558,338 Energy Delivery 314,410 311,019 310,880 sales to AEP Affiliates 255,039 210,308 50,969 TOTAL OPERATING REVENUES 4,803,625 3,542,084 2,920,187

)PERATING EXPENSES:

Fuel 250,098 210,870 185,419 Purchased Power:

Electricity Marketing and Trading 3,293,255 2,065,509 1,602,658 AEP Affiliates 238,237 265,475 200,372 Other operation 451,195 599,012 461,494 Maintenance 127,263 219,854 135,331 Depreciation and Amortization 164,230 154,920 149,988 Taxes other Than Income Taxes 65,518 60,622 65,843 Income Taxes 54,124 524 10,430 TOTAL OPERATING EXPENSES 4,643,920 33,576,786 2,811,535 OPERATING INCOME (LOSS) 159,705 (34,702) 108,652 NONOPERATING INCOME 1,474,572 869,895 452,019 NONOPERATING EXPENSES 1,459,799 855,773 446,183 Sn1/2 NONOPERATING INCOME TAX EXPENSE 5,043 4,189 1,306 INTEREST CHARGES 93,647 107,263 80,406 NET INCOME (LOSS) 75,788 (132,032) 32,776 PREFERRED STOCK DIVIDEND REQUIREMENTS 4,621 4,624 4,885 EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $

Consolidated Statements of Comprehensive Income Year Ended December 31, 2001 2000 1999 (in thousands)

NET INCOME (LOSS) $75,788 $(132,032) $32,776 OTHER COMPREHENSIVE INCOME (LOSS) cash Flows Interest Rate Hedge (3,835)

COMPREHENSIVE INCOME (LOSS) $711953 $(132.032) i2ll=

See Notes to Financial statements beginning on page L-1.

F-7

[11 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Balance Sheets December 31, 2001 2000 ASSETS ELECTRIC UTILITY PLANT: (in thousands)

Production Transmission $2,758,160 Distribution $2,708,436 General (including nuclear 957,336 945,709 Construction Work in Progress fuel) 900,921 863,736 Total Electric 233,005 257,152 Accumulated DepreciationUtility Plant and Amortization 74,299 4,923, NET ELECTRIC UTILITY PLANT 721 96,440 4,871,473 2,436,972 2,280 521 2,486,749 2,590,952 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 834,109 778,720 LONG-TERM ENERGY TRADING CONTRACTS 215,544 194,554 OTHER PROPERTY AND INVESTMENTS 127,977 131,417 CURRENT ASSETS:

Cash and Cash Equivalents Advances to Affiliates Accounts Receivable: 16,804 14,835 46,309 Customers Affiliated Companies Miscellaneous 60,864 106,832 Allowance for Uncollectible 31,908 48,706 Fuel - at average cost Accounts 25,398 27,491 Materials and Supplies (741) (759)

- at average cost 28,989 Energy Trading Contracts 16,532 Accrued Utility Revenues 91,440 84,471 Prepayments 399,195 1,222,925 2,072 TOTAL CURRENT ASSETS 6,497 708,735 1,527,099 REGULATORY ASSETS -6,066 408,927 552,140 DEFERRED CHARGES 34,967 36,156 TOTAL See Notes to Financial Statements beginning on page L-1.

F-8

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES December 31, 2001 2000 (in thousands)

CAPITALIZATION AND LIABILITIES CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 shares outstanding - 1,400,000 Shares $ 56,584 $ 56,584 Paid-in capital 733,216 733,072 Accumulated other Comprehensive Income (Loss) (3,835)

Retained Earnings 74,605 3,443 Total Common shareholder's Equity 860,570 793,099 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 8,736 8,736 subject to Mandatory Redemption 64,945 64,945 Long-term Debt 1,312,082 1,298,939 TOTAL CAPITALIZATION 2,246,333 2,165,719 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning 600,244 560,628 Other 87,025 108,600 TOTAL OTHER NONCURRENT LIABILITIES 687,269 669,228 CURRENT LIABILITIES:

Long-term Debt Due within One Year 340,000 90,000 Advances from Affiliates 253,582 Accounts Payable - General 90,817 119,472 Accounts Payable - Affiliated Companies 43,956 75,486 Taxes Accrued 69,761 68,416 Interest Accrued 20,691 21,639 obligations under capital Leases 10,840 100,848 Energy Trading and Derivative Contracts 383,714 1,267,981 Other 72,435 97,070 TOTAL CURRENT LIABILITIES 1,032,214 2,094,494 DEFERRED INCOME TAXES 400,531 487,945 DEFERRED INVESTMENT TAX CREDITS 105,449 113,773 DEFERRED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 77,592 81,299 LONG-TERM ENERGY TRADING CONTRACTS 175,581 156,343 DEFERRED CREDITS 92,039 42,237 COMMITMENTS AND CONTINGENCIES (Note 8)

TOTAL See Notes to Financial Statements beginning on page L-1.

F-9

[II INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Cash Flows Year Ended December 31, 2001 2O000 1999 (in thousands)

OPERATING ACTIVITIES:

Net Income (Loss) $ 75,788 $ (132,032) $ 32,776 Adjustments for Noncash Items:

Depreciation and Amortization 166,360 163,391 153,921 Amortization of Incremental Nuclear Refueling Outage Expenses (net) 418 5,737 8,480 Amortization (Deferral) of Nuclear Outage Costs (net) 40,000 40,000 (160,000)

Deferred Federal Income Taxes (29,205) (125,179) 85,727 Deferred Investment Tax Credits (8,324) (7,854) (8,152)

Mark-to-Market of Energy Trading Contracts (19,502) (10,859) (2,602) unrecovered Fuel and Purchased Power costs 37,501 37,501 (84,696) changes in Certain Current Assets And Liabilities:

Accounts Receivable (net) 64,841 (25,305) (19,178)

Fuel, Materials and Supplies (19,426) 10,743 (12,880)

Accrued Utility Revenues (2,072) 44,428 (7,151)

Accounts Payab1e (60,185) 85,056 19,068 Taxes Accrued 1,345 19,446 13,809 Disputed Tax and Interest Related to COLI 56,856 (3,228)

Change in other Assets (5,871) (68,160) (48,879)

Change in Other Liabilities (5,461) 37 668 63,763 Net Cash Flows From Operating Activities 236,207 131 437 30,778 INVESTING ACTIVITIES:

Construction Expenditures (91,052) (171,071) (165,331)

Buyout of Nuclear Fuel Leases (92,616) other 1,074 587 2,501 Net Cash Flows Used For Investing Activities 182, 594) (170,484) (162,830)

FINANCING ACTIVITIES:

Issuance of Long-term Debt 297,656 199,220 247,989 Retirement of Cumulative Preferred Stock (314) (3,597)

Retirement of Long-term Debt (44,922) (148,000) (109,500) change in Advances from Affiliates (net) (299,891) 253,582 change in Short-term Debt (net) (224,262) 115,562 Dividends Paid on common stock (26,290) (114,656)

Dividends Paid on cumulative Preferred stock (4,487) (3,368) (5,856)

Net Cash Flows From (Used For)

Financing Activities 51, 644) 50,568 129,942 Net Increase (Decrease) in cash and cash Equivalents 1,969 11,521 (2,110) cash and cash Equivalents January 1 cash and cash Equivalents December 31 14,835

$ !4_3,314 835 $

5,424 3.314 Supplemental Disclosure:

Cas paid (received) for interest net of capitalized amounts was $92,140,000,$82,511,000 and

$78,703,000 and for income taxes was $100,470,000, $73,254,000 and $(71,395,000) in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases were $1,023,000,

$22,218,000 and $10,852,000 in 2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.

F-I 0

SUBSIDIARIES INDIANA MICHIGAN POWER COMPANY AND Year Ended December 31, Consolidated Statements of Retained Earnin0s 2001 2000 1999 (in thousands)

$ 3,443 $ 166,389 $253,154 Retained Earnings january 1 75,788 (132,032) 32.776 Net Income (LOSS) 79,231 34,357 285,930 Deductions:

cash Dividends Declared: 26,290 114,656 Common Stock 230 244 cumulative Preferred stock: 229 66 66 66 4-1/8% Series 72 74 78 4.56% series 897 963 4.12% series 897 1,250 1,203 1,203 5.90% series 834 834 6-1/4% series 834 1,238 6.30% series 1,186 1,186 119,329 4,487 30,780 6-7/8% series 134 212 Total Cash Dividends Declared 139 119.541 capital stock Expense 4,626 30,914 Total Deductions Retained Earnings December 31 a I L-1.

See Notes to Financial statements beginning on page F-11

. I.

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Consolidated Statements of Capitalization December 31, 2001 2000 (in thousands)

COMMON SHAREHOLDER'S EQUITY 860,570 $ 793,099 PREFERRED STOCK:

$100 Par value Authorized 2,250,000 shares

$25 Par Value Authorized 11,200,000 shares Call Price Shares December 31, Number of Shares Redeemed Outstanding Series 2001 Year Ended December 31, December 31. 2001 2001 2000 1999 Not subject to Mandatory Redemption:

4-1/8% 106.125 - 3,750 97 55,389 4.56% 102 5,539 5,539

- 150 14,412 1,441 1,441 4.12% 102.728 - 1,375 - 17,556 1,756 1,756 Subject to Mandatory Redemption: 8,736 8,736 5.90% (a,b) - - 15,000 152,000 15,200 15,200 6-1/4% (a,b) 10,000 192,500 6.30% (a,b) 19,250 19,250

- 132,450 13,245 13,245 6-7/8% (a,c) 10,000 172,500 17,250 17,250 64,945 64,945 LONG-TERM DEBT (See schedule of Long-term Debt):

First Mortgage Bonds Installment Purchase Contracts 264,141 308,976 Senior unsecured Notes 310,239 309,717 Other Long term Debt 696,144 397,435 Junior De entures 219,947 211,307 Less Portion Due within One Year 161,611 161,504 (340,000) (90,000)

Long-term Debt Excluding Portion Due within One Year 1,312,082 1,298,939 TOTAL CAPITALIZATION UIU413 (a) Not callable until after 2002. There are no aggregate sinking fund provisions through 2002.

provisions require the redemption of 15,000 shares in 2003 and 67,500 shares each Sinking fund The sinking fund provisions of each series subject to mandatory redemption have year in 2004, 2005 and 2006.

been met by purchase of shares in advance of the due date.

(b) Commencing in 2004 and continuing through 2008 the company may redeem, at

$100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30%

series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. Shares previously redeemed may be applied to meet the sinking fund requirement.

(c) Commencing in 2003 and continuing through the year 2007, a sinking fund will shares each year and the redemption of the remaining shares outstanding on Aprilrequire the redemption of 15,000 1, 2008, in per share. shares previously redeemed may be applied to meet the sinking fund requirement. each case at $100 See Notes to Financial Statements beginning on page L-1.

F-12

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Schedule of Long-term Debt First mortgage bonds outstanding were as The terms of the installment purchase follows: contracts require I&M to pay amounts December 31, sufficient for the cities to pay interest on and 2001 2000 (in thousands) the principal (at stated maturities and upon

% Rate Due

$ 40,000 mandatory redemptions) of related pollution 7.63 2001 - June 1 $

7.60 2002 - November 1 50,000 50,000 control revenue bonds issued to finance the December 15 40,000 40,000 7.70 6.10 2002 2003

- November 1 30,000 30,000 construction of pollution control facilities at 8.50 2022 - December 15 75,000 75,000 certain generating plants. On the variable rate 7.35 2023 - october 1 15,000 20,000 7.20 2024 - February 1 30,000 30,000 series the principal is payable at the stated 7.50 2024 - March 1 25,000 25,000 maturities or on the demand of the unamortized Discount (859) (1,024) bondholders at periodic interest adjustment dates which occur weekly. The variable rate First mortgage bonds are secured by bonds due in 2014 are supported by a bank first mortgage liens on electric utility plant. letter of credit which expires in 2002.

Certain indentures relating to the first Accordingly, the variable rate installment mortgage bonds contain improvement, purchase contracts have been classified for maintenance and replacement provisions repayment purposes based on the expiration requiring the deposit of cash or bonds with the date of the letter of credit.

trustee, or in lieu thereof, certification of unfunded property additions. Senior unsecured notes outstanding were as follows:

December 31, Installment purchase contracts have 2001 2000 (in thousands) been entered into, in connection with the  % Rate Due issuance of pollution control revenue bonds (a) 2002 - September 3 $200,000 $200,000 6-7/8 2004 - July 1 150,000 150,000 by governmental authorities as follows: 6.125 2006 - December 15 300,000 6.45 2008 - November 10 50,000 50,000 December 31, (3,856) (2,565) 2001 2000 unamortized Discount (in thousands) 1A32Z4

% Rate Due (a) A floating interest rate is determined city of Lawrenceburg, Indiana: quarterly. The rate on December 31, 2001 7.00 2015 - April 1 $ 25,000 $ 25,000 was 2.71% and 7.31%,

52,000 and 2000 5.90 2019 - November 1 52,000 respectively. The average interest rate was 5.1% in 2001 and 7.3% in 2000.

ci ty of Rockport, Indiana:

(a) 2014 - August 1 50,000 50,000 7.60 2016 - March 1 40,000 40,000 6.55 2025 - June 1 50,000 50,000 (b) 2025 - June 1 50,000 50,000 city of Sullivan, Indiana:

5.95 2009 - May 1 45,000 45,000 unamortized Discount (1.761) (2,283)

(a) A variable interest rate is determined weekly. The average weighted interest rate was 2.4% for 2001 and 4.5% for 2000.

(b) In June 2001 an auction rate was established. Auction rates are determined by standard procedures every 35 days. The auction rate for June through December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a daily, weekly, commercial paper or term rate as designated by I&M. A weekly rate was selected which ranged from 1.9% to 4.9% in 2001 and from 2.9% to 5.9% in 2000 and averaged 3.3% during 2001 and 4.2% during 2000.

F-13

.1 Junior debentures outstanding were as At December 31, 2001, future annual follows: long-term debt payments are as follows:

December 31, Amount 2001 2000 (in thousands)

(in thousands) 2002 $ 340,000

% Rate Due 2003 30,000 8.00 2026 - March 31 $ 40,000 $ 40,000 2004 150,000 7.60 2038 - June 30 125,000 125,000 2005 Unamortized Discount C3,389) (3,496) 2006 300,000 Total SI11504 Later Years 841,947 Total Principal Amount 1,661,947 Unamortized Discount (9,865)

Interest may be deferred and payment Total $1,65W__

of principal and interest on the junior debentures is subordinated and subject in right to the prior payment in full of all senior indebtedness of I&M.

F-I4

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Index to Notes to Financial Statements The notes to I&M's financial statements are combined with the notes to financial statements for AEP and its other subisidiary registrants.

Listed below are the combined notes that apply to I&M. The combined footnotes begin on page L-1.

combi ned Footnote Reference Note 1 Significant Accounting Policies Note 3 Merger Note 4 Nuclear Plant Restart Note 6 Effects of Regulation Note 7 Customer choice and Industry Restructuring Note 8 Commitments and contingencies Note 10 Benefit Plans Note 12 Business Segments Note 13 Risk Management, Financial Instruments and Derivatives Note 14 Income Taxes Note 16 supplementary Information Note 18 Leases Note 19 Lines of Credit and sale of Receivables Note 20 unaudited Quarterly Financial Information Note 24 Related Party Transactions F-1 5

111 INDEPENDENT AUDITORS' REPORT To the Shareholders and Board of Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, retained earnings and cash flows for each of the three years in the period ended December'31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP Columbus, Ohio February 22, 2002 F-16

NOTES TO FINANCIAL STATEMENTS presentation for The notes to financial statements that follow are alistcombined of footnotes shows the AEP and its subsidiary registrants. The following they apply:

registrant to which

1. significant Accounting Policies AEP, OPCo, AEGCo, PSO, APCo, CPL, CSPCo, SWEPCo, WTU I&M, KPCo,

2. Extraordinary Items and AEP, APCO, CPL, CSPCO, OPCO, SWEPCO, WTU cumulative Effect AEP, CPL, I&M, KPCO, PSO, SWEPCO, WTU

3. Merger AEP, I&M

4. Nuclear Plant Restart AEP, APCo, CPL, PSO, SWEPCO, WTU

5. Rate Matters AEP, AEGCO, APCO, CPL, CSPCO, I&M, KPCO,

6. Effects of Regulation OPCO, PSO, SWEPCO, WTU

7. Customer choice and Industry AEP, APCO, CPL, CSPCO, I&M, OPCO, PSO, Restructuring SWEPCO, WTU AEP, AEGCO, APCO, CPL, CSPCO, I&M,

8. commitments and Contingencies KPCo, OPCo, PSO, SWEPCO, WTU I 'I AEP, OPCO, SWEPCO

9. Acquisitions and Dispositions AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,

10. Benefit Plans PSO, SWEPCO, WTU AEP

11. Stock-Based compensation AEP, AEGCO, APCO, CPL, CSPCO, I&M, KPCO,

12. Business Segments OPCO, PSO, SWEPCO, WTU AEP, AEGCO, APCO, CPL, CSPCo, I&M, KPCO,

13. Risk Management, Financial Instruments and Derivatives OPCo, PSO, SWEPCO, WTU AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCO,

14. Income Taxes OPCO, PSO, SWEPCO, WTU

15. Basic and Diluted Earnings AEP Per share AEP, APCO, CSPCO, I&M, OPCO

16. Supplementary Information

17. Power, Distribution and AEP Communications Projects AEP, AEGCO, APCO, CPL, CSPCO, I&M, KPCO,

18. Leases OPCo, PSO, SWEPCO, WTU

19. Lines of credit and sale AEP, AEGCO, APCO, CPL, CSPCO, I&M, KPCO, of Receivables OPCO, PSO, SWEPCO, WTU L-1

[II

20. unaudited Quarterly Financial Information AEP, AEGCO, APCO, CPL, CSPCo, I&M, KPCO, OPCo, PSO, SWEPCO, WTU

21. Trust Preferred Securities AEP, CPL, PSO, SWEPCO

22. Minority Interest in Finance subsidiary AEP

23. Jointly Owned Electric Utility Plant CPL, CSPCo, PSO, SWEPCo, WTU

24. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU L-2

1. Significant Accounting Policies: Principles of Consolidation - AEP's consolidated financial statements include AEP Co., Inc. and its Business Operations- AEP's principal business wholly-owned and majority-owned subsidiaries conducted by its eleven domestic electric utility consolidated with their wholly-owned or operating companies is the generation, substantially controlled subsidiaries. The transmission and distribution of electric power. consolidated financial statements for APCo, CPL, Nine of AEP's eleven domestic electric utility CSPCo, I&M, OPCo, PSO and SWEPCo include operating companies, APCo, CPL, CSPCo, I&M, the registrant and its wholly-owned subsidiaries.

KPCo, OPCo, PSO, SWEPCo, WTU, are SEC Significant intercompany items are eliminated in registrants. AEGCo is a domestic generating consolidation. Equity investments not substantially company wholly-owned by AEP that is an SEC controlled that are 50% or less owned are registrant. These companies are subject to accounted for using the equity method with their regulation by the FERC under the Federal Power equity earnings included in Other Income for AEP Act and follow the Uniform System of Accounts and nonoperating income for the registrant prescribed by FERC. They are subject to further subsidiaries.

regulation with regard to rates and other matters by state regulatory commissions. Basis of Accounting - As the owner of cost-based rate-regulated electric public utility companies, AEP also engages in wholesale marketing and AEP Co., Inc.'s consolidated financial statements trading of electricity, natural gas and to a lesser reflect the actions of regulators that result in the extent coal, oil, natural gas liquids and emission recognition of revenues and expenses in different allowances in the United States and Europe. In time periods than enterprises that are not rate addition the Company's domestic operations regulated. In accordance with SFAS 71, includes non-regulated independent power and "Accounting for the Effects of Certain Types of cogeneration facilities, coal mining and intra-state Regulation," regulatory assets (deferred midstream natural gas operations in Louisiana expenses) and regulatory liabilities (future and Texas. revenue reductions or refunds) are recorded to reflect the economic effects of regulation by International operations include regulated supply matching expenses with their recovery through and distribution of electricity and other non regulated revenues. Application of SFAS 71 for regulated power generation projects in the United the generation portion of the business was Kingdom, Australia, Mexico, South America and discontinued as follows: in Ohio by OPCo and China. CSPCo in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas by CPL, The Company also operates domestic barging, WTU, and SWEPCo in September 1999 and in provides energy services worldwide and furnishes Arkansas by SWEPCo in September 1999. See communications related services domestically. Note 7, "Customer Choice and Industry Restructuring" for additional information.

Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The rates charged Use of Estimates - The preparation of these by the domestic utility subsidiaries are approved financial statements in conformity with generally by the FERC and the state utility commissions. accepted accounting principles necessarily The FERC regulates wholesale electricity includes the use of estimates and assumptions by operations and transmission rates and the state management. Actual results could differ from commissions regulate retail rates. The prices those estimates.

charged by foreign subsidiaries located in the UK, Australia, China, Mexico and Brazil are regulated Property, Plant and Equipment - Domestic by the authorities of that country and are generally electric utility property, plant and equipment are subject to price controls. stated at original cost of the acquirer. Property, plant and equipment of the non-regulated domestic operations and other investments are stated at their fair market value at acquisition plus L-3

the original cost of property acquired or Depreciation, Depletion and Amortization constructed since the acquisition, less disposals. Depreciation of property, plant and equipment is Additions, major replacements and betterments provided on a straight-line basis over the are added to the plant accounts. For cost-based estimated useful lives of property, other than coal rate regulated operations retirements from the mining property, and is calculated largely through plant accounts and associated removal costs, net the use of composite rates by functional class as of salvage, are deducted from accumulated follows:

depreciation. The costs of labor, materials and Annual Composite overheads incurred to operate and maintain plant Functional class Depreciation Rates are included in operating expenses. of Property Ranges 2001 Production:

Steam-Nucl ear 2.5% to 3.4%

Allowance for Funds Used During Construction Steam-Fossil -Fi red 2.5% to 4.5%

Hydroelectric- conventional (AFUDC) and Interest Capitalization- AFUDC is and Pumped storage 1.9% to 3.4%

a noncash nonoperating income item that is Transmi ssion 1.7% to 3.1%

Di stri buti on 2.7% to 4.2%

capitalized and recovered through depreciation other 1.8% to 15.0%

over the service life of domestic regulated electric Annual composite utility plant. It represents the estimated cost of Functional Class Depreciation Rates borrowed and equity funds used to finance of Property Ranges 2000 construction projects. The amounts of AFUDC for Production:

2001, 2000 and 1999 were not significant. Steam-Nucl ear 2.8% to 3.4%

Steam-Fossil-Fired 2.3% to 4.5%

Effective with the discontinuance of the Hydroelectric- conventional and Pumped Storage 1.9% to 3.4%

application of SFAS 71 regulatory accounting for Transmission 1.7% to 3.1%

domestic generating assets in Arkansas, Ohio, Distribution 3.3% to 4.2%

Other 2.5% to 7.3%

Texas, Virginia and West Virginia and for other non-regulated operations, interest is capitalized Annual Composite Functional class Dep reci ati on Rates during construction in accordance with SFAS 34, of Propertv Ranýes "Capitalization of Interest Costs." The amounts of 1999 Production:

interest capitalized were not material in 2001, Steam-Nuclear 2.8% to 3.4%

Steam-Fossil-Fired 3.2% to 5.0%

2000, and 1999. Hydroelectric- Conventional and Pumped storage 1.9% to 3.4%

Transmi ssi on 1.7% to 2.7%

Distribution 2.8% to 4.2%

Other 2.0% to 20.0%

The following table provides the annual composite depreciation rates generally used by the AEP registrant subsidiaries for the years 2001, 2000 and 1999 which were as follows:

Nuclear Steam Hydro Transmission Distribution General AEGCO 3.5% 2.8%

APCo 3.4 2.9 2.2 3.3 3.1 CPL 2.5 2.5 1.9 2.3 3.5 4.0 CSPCO 3.2 2.3 3.6 3.2 I&M 3.4 4.5 3.4 1.9 4.2 3.8 KPCo 3.8 1.7 3.5 2.5 OPCo 3.4 2.7 2.3 4.0 2.7 PSO 2.7 2.3 3.4 6.0 SWEPCo 3.4 2.7 3.6 4.5 WTU 2.8 3.1 3.3 6.6 L-4

translated at monthly average exchange rates Depreciation, depletion and amortization of coal throughout the year. Currency translation gain mining assets is provided over each asset's in and loss adjustments are recorded estimated useful life or the estimated life of the equity as "Accumulated Other shareholders' mine, whichever is shorter, and is calculated Comprehensive Income (Loss)". The non-cash using the straight-line method for mining impact of the changes in exchange rates on cash, structures and equipment. The units-of to amortize coal rights resulting from the translation of items at different production method is used costs based on estimated exchange rates is shown on AEP's Consolidated and mine development Statement of Cash Flows in "Effect of Exchange recoverable tonnages at a current average rate of Rate Change on Cash." Actual currency

$3.46 per ton in 2001, $5.07 per ton in 2000 and included transaction gains and losses are recorded in

$2.32 per ton in 1999. These costs are income.

in the cost of coal charged to fuel expense.

Deferred Fuel Costs - The cost of fuel consumed Cash and Cash Equivalents - Cash and cash is charged to expense when the fuel is burned.

equivalents include temporary cash investments Where applicable under governing state with original maturities of three months or less. regulatory commission retail rate orders, fuel cost over or under-recoveries are deferred as Inventory - Except for CPL, PSO and WTU, the regulatory liabilities or regulatory assets in regulated domestic utility companies value fossil accordance with SFAS 71. These deferrals fuel inventories using a weighted average cost generally are amortized when refunded or billed to method. CPL, PSO and WTU, utilize the LIFO customers in later months with the regulator's method to value fossil fuel inventories. For those generation is review and approval. The amount of deferred fuel domestic utilities whose of coal and oil is carried at costs under fuel clauses for AEP was $139 million unregulated, inventory at December 31, 2001 and $407 million at the lower of cost or market. Coal mine inventories December 31, 2000. See also Note 6 "Effects of are also carried at the lower of cost or market. Regulation".

Natural gas inventories are marked-to-market if held in connection with trading operations. Any We are protected from fuel cost changes in non-trading gas inventory is carried at the lower of Kentucky for KPCo, the SPP area of Texas, cost or market.

Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo. Where fuel Accounts Receivable - AEP Credit Inc. (formerly clauses have been eliminated due to the CSW Credit) factors accounts receivable for the transition to market pricing, (Ohio effective domestic utility subsidiaries and certain non January 1, 2001 and in the Texas ERCOT area affiliated utilities. On December 31, 2001 AEP effective January 1, 2002) changes in fuel costs Credit, Inc. entered into a sale of receivables impact earnings. In other state jurisdictions, agreement with a group of banks and commercial (Indiana, Michigan and West Virginia) where fuel paper conduits. This transaction constitutes a clauses have been frozen or suspended for a sale of receivables in accordance with SFAS 140, period of years, fuel cost changes also impact allowing the receivables to be taken off of the earnings currently. This is also true for certain of companies balances sheet. See Note 19 for AEP's Independent Power Producer generating further details.

units that do not have long-term contracts for their fuel supply. See Note 5, "Rate Matters" and Note Foreign Currency Translation - The financial 7, "Customer Choice and Industry Restructuring" statements of subsidiaries outside the U.S. which for further information about fuel recovery.

are included in AEP's consolidated financial statements are measured using the local currency Revenue Recognition - We recognize revenues as the functional currency and translated into U.S. foreign and domestic generation, from dollars in accordance with SFAS 52 "Foreign of electricity, transmission and distribution Currency Translation". Assets and liabilities are services, other domestic gas pipeline and storage translated to U.S. dollars at year-end rates of as well energy supply related business activities, exchange and revenues and expenses are L-5

as domestic barging, telecommunications and the change in fair values of forward sale and related services. The revenues associated with purchase contracts are included in AEP's these activities are recorded when earned as revenues.

physical commodities are delivered to contractual meter points or services are provided. These All of the registrant subsidiaries except AEGCo revenues also include the accrual of earned, but participate in AEP's wholesale marketing and unbilled and/or not yet metered revenues. Such trading of electricity. APCo, CSPCo, I&M, KPCo revenues are based on contract prices or tariffs and OPCo record forward electricity trading sale and presented on a gross basis consistent with contracts in operating revenues when the generally accepted accounting principles and contracts settle for contracts with delivery points industry practice. Revenue recognition for energy in AEP's traditional marketing area and in marketing and trading transactions is further nonoperating income for forward electricity trading discussed within the Energy Marketing and sale contracts outside AEP's traditional marketing Trading Transactions section below. The area. APCo, CSPCo, I&M, KPCo and OPCo Company follows EITF 98-10 and marks to record forward electricity trading purchase market energy trading activities, which includes contracts in purchased power expense when the the net change in fair value of open trading contracts settle for contracts with delivery points contracts in earnings. Mark-to-market gains and in AEP's traditional marketing area and in losses on open contracts and net settlements of nonoperating expense for forward electricity financial contracts (see below) are included in trading purchase contracts outside AEP's revenues on a net basis. The net basis of traditional marketing area. CPL, PSO, SWEPCo reporting for open contracts is permitted by EITF and WTU record revenues from forward electricity 98-10 and for settled financial contracts is trading sale contracts in operating revenues.

consistent with industry practice. Settled physical CPL, PSO, SWEPCo and WTU record purchased forward trading transactions are reported on a power expense for forward electricity trading gross basis, as permitted by EITF 98-10. purchase contracts when they settle.

Management believes that the gross basis of reporting for settled physical forward trading APCo, CSPCo and OPCo account for open contracts is a better indication of the scope and forward electricity sale and purchase contracts on significance of energy trading activities to the a mark-to-market basis and include the mark-to Company. market change in operating revenues for open contracts in AEP's traditional marketing area and Energy Marketing and Trading Transactions in nonoperating income for open contracts AEP engages in wholesale electricity and natural beyond AEP's traditional marketing area.

gas marketing and trading transactions (trading activities). Trading activities inolve the purchase I&M and KPCo account for open forward and sale of energy under forward contracts at electricity sale and purchase contracts on a mark fixed and variable prices and the trading of to-market basis and defer the mark-to-market financial energy contracts which includes change as regulatory assets or liabilities for those exchange futures and options and over-the open contracts in AEP's traditional marketing area counter options and swaps. Although trading and include the mark-to-market change in contracts are generally short-term, there are long nonoperating income for open contracts beyond term trading contracts. AEP's traditional marketing area.

The majority of trading activities represent forward CPL, PSO, SWEPCo and WTU account for open electricity and gas contracts that are typically forward electricity sale and purchase contracts on settled by entering into offsetting physical a mark-to-market basis. CPL includes the mark contracts. Forward trading sale contracts are to-market change for open electricity trading included in AEP's revenues when the contracts contracts in revenues. PSO defers as regulatory settle. Forward trading purchase contracts are assets or liabilities the mark-to-market change for included in AEP's fuel and purchased energy open forward electricity trading contracts that are expenses when they settle. Prior to settlement included in cost of service on a settlement basis L-6

and ask price. The end of the month liquidity for ratemaking purposes. SWEPCo and WTU reserve is based on the difference in price include the jurisdictional share of the mark-to between the price curve and the bid side of the market change in revenues for open electricity bid ask if we have a long position and the ask trading contracts for those jurisdictions that are side if we have a short position. This provides for not subject to SFAS 71 cost based rate regulation a conservative valuation net of the reserves. The and defer as regulatory assets or liabilities the use of these models to fair value open trading jurisdictional share of the mark-to-market change contracts has inherent risks relating to the for open contracts that are included in cost of underlying assumptions employed by such service on a settlement basis for ratemaking purposes. models. Independent controls are in place to evaluate the reasonableness of the price curve models. Significant adverse or favorable effects Trading purchases and sales through electricity on future results of operations and cash flows and gas options, futures and swaps, represent could occur if market risks, at the time of financial transactions with the net proceeds settlement, do not correlate with AEP developed reported in AEP's revenues at fair value upon price models.

entering the contracts.

The effect on AEP's Consolidated Statements of APCo, CSPCo, I&M, KPCo and OPCo share in Income of marking to market open electricity AEP's trading sales and purchases through trading contracts in AEP's regulated jurisdictions electricity options, futures and swaps, which is deferred as regulatory assets or liabilities since represent financial transactions. Changes in fair "C-'-.

these transactions are included in cost of service N.',

values of these financial contracts are reported When these on a settlement basis for ratemaking purposes.

net in nonoperating income.

Unrealized mark-to-market gains and losses from contracts settle, the net proceeds are recorded in trading activities whether deferred or recognized nonoperating income and the prior unrealized in revenues are part of Energy Trading and gain or loss in reversed.

Derivative Contracts assets or liabilities as appropriate.

Recording of the net changes in fair value of open trading contracts is commonly referred to a mark to-market accounting. Hedging and Related Activities - In order to mitigate the risks of market price and interest rate fluctuations, AEP's foreign subsidiaries, All open contracts from trading activities are utilize interest swaps, SEEBOARD and CitiPower, marked to market in accordance with EITF 98-10. hedge such market and currency swaps to Except as noted above, the net mark-to-market fluctuations. Changes in the market value of (change in fair value) amount included in results these swaps are deferred until the gain or loss is of operations on a net discounted basis. The fair realized on the underlying hedged asset, liability values of open short-term trading contracts are or commodity. To qualify as a hedge, these based on exchange prices and broker quotes.

transactions must be designated as a hedge and Open long-term trading contracts are marked to changes in their fair value must correlate with market based mainly on AEP developed valuation changes in the price and interest rate movement models. The valuation models produce an of the underlying asset, liability or commodity.

extimated fair value for open long-term trading This in effect reduces AEP's exposure to the contracts. The short-term and long-term fair effects of market fluctuations related to price and values are present valued and reduced by interest rates.

appropriate reserves for counterparty credit risks and liquidity risk. The models are derived from AEP, APCo, CSPCo, I&M, and OPCo enter into internally assessed market prices with the contracts to manage the exposure to unfavorable exception of the NYMEX gas curve, where we use changes in the cost of debt to be issued. These daily settled prices. Bid/ask price curves are anticipatory debt instruments are entered into in developed for inclusion in the model based on broker quotes and other available market data. order to manage the change in interest rates The curves are within the range between the bid between the time a debt offering is initiated and L-7

[II the issuance of the debt (usually a period of 60 operating and miscellaneous expenses.

days). Gains or losses from these transactions are deferred and amortized over the life of the Income Taxes - The AEP System follows the debt issuance with the amortization included in liability method of accounting for income taxes as interest charges. There were no such forward prescribed by SFAS 109, "Accounting for Income contracts outstanding at December 31, 2001 or Taxes." Under the liability method, deferred 2000. See Note 13 - "Risk Management, income taxes are provided for all temporary Financial Instruments and Derivatives" for further differences between the book cost and tax basis discussion of the accounting for risk management of assets and liabilities which will result in a future transactions. tax consequence. Where the flow-through method of accounting for temporary differences is Levelization of Nuclear Refueling Outage Costs reflected in regulated revenues (that is, deferred In order to match costs with regulated revenues, taxes are not included in the cost of service for incremental operation and maintenance costs determining regulated rates for electricity),

associated with periodic refueling outages at deferred income taxes are recorded and related I&M's Cook Plant are deferred and amortized over regulatory assets and liabilities are established in the period beginning with the commencement of accordance with SFAS 71 to match the regulated an outage and ending with the beginning of the revenues and tax expense.

next outage.

Investment Tax Credits - Investment tax credits Maintenance Costs - Maintenance costs are have been accounted for under the flow-through expensed as incurred except where SFAS 71 method except where regulatory commissions requires the recordation of a regulatory asset to have reflected investment tax credits in the rate match the expensing of maintenance costs with making process on a deferral basis. Investment their recovery in cost based regulated revenues. tax credits that have been deferred are being See below for an explanation of costs deferred in amortized over the life of the regulated plant connection with an extended outage at I&M's investment.

Cook Plant.

Excise Taxes - AEP and its subsidiary Amortization of Cook Plant Deferred Restart registrants, as an agent for a state or local Costs - Pursuant to settlement agreements government, collect from customers certain approved by the IURC and the MPSC to resolve excise taxes levied by the state or local all issues related to an extended outage of the government upon the customer. These taxes are Cook Plant, I&M deferred $200 million of not recorded as revenue or expense, but only as incremental operation and maintenance costs a pass-through billing to the customer to be during 1999. The deferred amount is being remitted to the government entity. Excise tax amortized to expense on a straight-line basis over collections and payments related to taxes five years from January 1, 1999 to December 31, imposed upon the customer are not presented in 2003. I&M amortized $40 million in 2001, 2000 the income statement.

and 1999 leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the Debt and Preferred Stock - Gains and losses Consolidated Balance Sheets of AEP and I&M.

from the reacquisition of debt used to finance domestic regulated electric utility plant are Other Income and Other Expenses - Other generally deferred and amortized over the Income includes equity earnings of non remaining term of the reacquired debt in consolidated subsidiaries, gains on dispositions of accordance with their rate-making treatment. If property, interest and dividends, an allowance for debt associated with the regulated business is equity funds used during construction (explained refinanced, the reacquisition costs attributable to above) and various other non-operating and the portions of the business that are subject to miscellaneous income. Other Expenses includes cost based regulatory accounting under SFAS 71 losses on dispositions of property, miscellaneous are generally deferred and amortized over the amortization, donations and various other non-term of the replacement debt commensurate with L-8

December 31, 2001 are included in other assets their recovery in rates. Gains and losses on the and represent retail and wholesale distribution reacquisition of debt for operations not subject to licenses for CitiPower operating franchises which SFAS 71 are reported as a component of net are currently being amortized on a straight-line income. basis over 20 and 40 years, respectively.

Debt discount or premium and debt issuance Also SFAS 142 provides that goodwill and other expenses are deferred and amortized over the intangible assets with indefinite lives be tested for term of the related debt, with the amortization impairment annually and not be subjected to included in interest charges. amortization. For AEP's goodwill recognized prior to July 1, 2001 and other intangible assets, these Where rates are regulated redemption premiums requirements will apply beginning January 1, paid to reacquire preferred stock of the domestic 2002. For the year 2001, the amortization of utility subsidiaries are included in paid-in capital goodwill reduced AEP's net income by $50 earnings and amortized to retained million. AEP is still evaluating the impact of in rates. The commensurate with their recovery adopting the impairment tests required by SFAS excess of par value over costs of preferred stock 142.

and reacquired is credited to paid-in capital with the amortized to retained earnings consistent Nuclear Trust Funds - Nuclear decommissioning with timing of its inclusion in rates in accordance and spent nuclear fuel trust funds represent funds SFAS 71. that regulatory commissions have allowed us to collect through rates to fund future Goodwill and Intangible Assets - The amount of decommissioning and spent fuel disposal acquisition cost in excess of the fair value liabilities. By rules or orders, the state allocated to tangible and identifiable intangible jurisdictional commissions (Indiana, Michigan and assets obtained through an acquisition accounted Texas) and the FERC established investment for as a purchase combination is recorded as limitations and general risk management goodwill on AEP's consolidated balance sheet. guidelines to protect their ratepayers' funds and to Goodwill recognized in connection with purchase allow those funds to earn a reasonable return. In combinations acquired after June 30, 2001 was general, limitations include:

determined in accordance with SFAS 141 "Business Combinations." (see also Note 9, "* Acceptable investments (rated investment "Acquisitions and Dispositions"). For goodwill grade or above) associated with purchase combinations before "* Maximum percentage invested in a specific July 1, 2001, amortization is on a straight-line type of investment basis generally over 40 years except for the "* Prohibition of investment in obligations of the portion of goodwill associated with gas trading applicable company or its affiliates.

and marketing activities which is being amortized on a straight-line basis over 10 years. Trust funds are maintained for each regulatory Accumulated amortization of goodwill was $199 jurisdiction and managed by investment million and $166 million at December 31, 2001 managers, who must comply with the guidelines and 2000, respectively. In accordance with SFAS and rules of the applicable regulatory authorities.

142, "Goodwill and Other Intangible Assets," The trust assets are invested in order to optimize goodwill acquired after June 30, 2001 is not the after-tax earnings of the Trust, giving subject to amortization. The amortization of consideration to liquidity, risk, diversification, and goodwill which predates July 1, 2001 ceased on other prudent investment objectives.

December 31, 2001.

Securities held in trust funds for decommissioning SFAS 142 requires that other intangible assets be nuclear facilities and for the disposal of spent separately identified and if they have finite lives nuclear fuel are included in Other Assets at they must be amortized over that life. Other market value in accordance with SFAS 115, intangible assets of $441 million net of "Accounting for Certain Investments in Debt and accumulated amortization of $38 million at L-9

SII Diecember 31, Equity Securities." Securities in the trust funds Components 2001

( thousands) have been classified as available-for-sale due to Foreign Currency Rate Hedge their long-term purpose. In accordance with SFAS APCo $ (340)

I&M (3,835) 71, unrealized gains and losses from securities in KPCO (1,903)

(196) these trust funds are not reported in equity but OPCo result in adjustments to the liability account for the Segment Reporting - The AEP System has nuclear decommissioning trust funds and to adopted SFAS No. 131, which requires disclosure regulatory assets or liabilities for the spent nuclear of selected financial information by business fuel disposal trust funds in accordance with their segment as viewed by the chief operating treatment in rates.

decision-maker. See Note 12 "Business Segments" for further discussion and details Comprehensive Income - Comprehensive income regarding segments.

is defined as the change in equity (net assets) of a business enterprise during a period from Common Stock Options - AEP follows transactions and other events and circumstances Accounting Principles Board Opinion 25 to from non-owner sources. It includes all changes account for stock options. Compensation expense in equity during a period except those resulting is not recognized at the date of grant or when from investments by owners and distributions to exercised, because the exercise price of stock owners. Comprehensive income has two options awarded under the stock option plan components, net income and other equals the market price of the underlying stock on comprehensive income. There were no material income and the date of grant.

differences between net comprehensive income for AEGCo, CPL, CSPCo, EPS - AEP's basic earnings per share is PSO, SWEPCo and WTU.

determined based upon the weighted average number of common shares outstanding during the Components of Other Comprehensive Income years presented. Diluted earnings per share for Other comprehensive income is included on the AEP is based upon the weighted average number balance sheet in the equity section. The following of common shares and stock options outstanding table provides the components that comprise the during the years presented. Basic and diluted balance sheet amount in Accumulated Other EPS are the same in 2001, 2000 and 1999.

Comprehensive Income for AEP.

December 31, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, 2001 2000 1999 PSO, SWEPCo, and WTU are wholly-owned (millions)

Foreign Currency subsidiaries of AEP and are not required to report Adjustments $(113) $ (99) $ 20 EPS.

unrealized Losses On Securities - - (20) unrealized Gain on Hedged Derivatives (3) - Reclassification - Certain prior year financial Minimum Pension __ 0) () (4) statement items have been reclassified to Liability conform to current year presentation. Such reclassification had no impact on previously reported net income. Certain settled forward Accumulated Other Comprehensive Income for energy transactions of the trading operation were AEP registrant subsidiaries as of December 31, reclassified from a net to a gross basis of 2001, is shown in the following table. Registrant presentation in order to better reflect the scope subsidiary balances for Accumulated Other and nature of the AEP System's energy sales and Comprehensive Income for the two years ended purchases. All financially net settled trading December 31, 2000 and 1999 were zero. transactions, such as swaps, futures, and unexercised options, and all marked-to-market values on open trading contracts continue to be reported on a net basis, reflecting the financial nature of these transactions. As applicable, prior year amounts of realized physical purchases from L-1 0

Year Ended settled purchase trading contracts were December 31, 2001 2000 1999 reclassified from revenues to purchased power (in millions) expense to present the prior period on a Extraordinary Items:

Discontinuance of Regulatory comparable gross basis. Accounting for Generation:

Ohio jurisdiction (Net of Tax of $20 million in 2001 and

2. Extraordinary Items and Cumulative Effect: $35 Million in 2000) $(48) $(44) $

virginia and west virginia Jurisdictions (Inclusive of ExtraordinaryItems - Extraordinary items were Tax Benefit of $8 Million) - 9 Texas and Arkansas recorded for the discontinuance of regulatory jurisdictions (Net of Tax of $5 Million) - - (8) accounting under SFAS 71 for the generation LOSS on Reacquired Debt portion of the business in the Ohio, Virginia, West (Net of Tax of $1 Million Virginia, Texas and Arkansas state jurisdictions. in 2001 and $3 Million in 1999) __(2) __ _-

See Note 7 "Customer Choice and Industry g(6)

Extraordinary Items Restructuring" for descriptions of the restructuring plans and related accounting effects. OPCo and Cumulative Effect of Accounting Change - The CSPCo recognized an extraordinary loss for FASB's Derivative Implementation Group (DIG) stranded Ohio Public Utility Excise Tax issued accounting guidance under SFAS 133 for (commonly known as the Gross Receipts Tax certain derivative fuel supply contracts with GRT) net of allowable Ohio coal credits during the volumetric optionality and derivative electricity quarter ended June 30, 2001. This loss resulted capacity contracts. This guidance, effective in the from regulatory decisions in connection with Ohio third quarter of 2001, concluded that fuel supply deregulation which stranded the recovery of the GRT. Effective with the liability affixing on May 1, contracts with volumetric optionality cannot qualify 2001, CSPCo and OPCo recorded an for a normal purchase or sale exclusion from mark-to-market accounting and provided extraordinary loss under SFAS 101. Both Ohio companies have appealed to the Ohio Supreme guidance for determining when electricity capacity contracts can qualify as a normal purchase or Court the PUCO order on Ohio restructuring that sale.

the Ohio companies believe failed to provide for recovery for the final year of the GRT. The Ohio Predominantly all of AEP's fuel supply contracts Supreme Court decision is expected in 2002.

for coal and gas and contracts for electricity capacity, which are recorded on a settlement In October 2001 CPL reacquired $101 million of basis, do not meet the criteria of a financial pollution control bonds in advance of their maturity. Since these pollution control bonds derivative instrument or qualify as a normal were used to finance generation assets, a loss of purchase or sale. Therefore, AEP's contracts are

$2 million after tax was recorded. generally exempt from the DIG guidance described above. Beginning July 1, 2001, the effective date of the DIG guidance, certain of The following table shows the components of the extraordinary items reported on the consolidated AEP's fuel supply contracts with volumetric statements of income: optionality that qualify as financial derivative instruments are marked to market with any gain or loss recognized in the income statement. The effect of initially adopting the DIG guidance at July 1, 2001, for AEP is a favorable earnings mark-to market effect of $18 million, net of tax of $2 million, is reported as a cumulative effect of an accounting change on the income statement.

L-11

3. Merger: The following table shows the vacation accrual conforming adjustment for CSW's registrant utility On June 15, 2000, AEP merged with CSW so that subsidiaries:

CSW became a wholly-owned subsidiary of AEP.

Under the terms of the merger agreement, Net Income Reductions approximately 127.9 million shares of AEP Net Asset Year Ended Common Stock were issued in exchange for all Reduction at December 31, December 31, 1999 1999 the outstanding shares of CSW Common Stock (in millions)

CPL $5.3 $0.7 based upon an exchange ratio of 0.6 share of PSO 2.8 1.1 AEP Common Stock for each share of CSW SWEPCo 4.5 0.5 WTU 2.6 0.4 Common Stock. Following the exchange, former shareholders of AEP owned approximately 61.4 In connection with the merger, $21 million ($14 percent of the corporation, while former CSW million after tax) and $203 million ($180 million shareholders owned approximately 38.6 percent after tax) of non-recoverable merger costs were of the corporation. expensed in 2001 and 2000. Such cost included transaction and transition costs not recoverable The merger was accounted for as a pooling of from ratepayers. Also included in the merger interests. Accordingly, AEP's consolidated costs were non-recoverable change in control financial statements give retroactive effect to the payments. Merger transaction and transition merger, with all periods presented as if AEP and costs of $51 million recoverable from ratepayers CSW had always been combined. Certain were deferred pursuant to state regulator reclassifications have been made to conform the approved settlement agreements through historical financial statement presentation of AEP December 31, 2001. The deferred merger costs and CSW. are being amortized over five to eight year recovery periods, depending on the specific terms The following table sets forth revenues, of the settlement agreements, with the extraordinary items and net income previously amortization ($8 million and $4 million for the reported by AEP and CSW and the combined years 2001 and 2000) included in depreciation amounts shown in the accompanying financial and amortization expense.

statements for 1999:

The following tables show the deferred merger Year Ended December 31, 1999 cost and amortization expense of the applicable (in millions) subsidiary registrants:

Revenues:

AEP $19,229 CSW 5,516 Amortization AEP After Pooling Merger Cost Expense for the Extraordinary Items: Deferral at Year Ended AEP December 31, 2000 December 31, 2000 CSW _LA)

(14) (in millions)

AEP After Pooling CPL $14.4 $1.3 Net Income: I&M 6.9 0.7 AEP $520 KPCo 2.5 0.3 CSW 455 PSO 7.9 0.5 conforming Adjustment (3) SWEPCo 6.1 0.5 AEP After Pooling _$=/ WTU 4.2 0.4 Amortization The combined financial statements include an Merger Cost Expense for the Deferral at Year Ended adjustment to conform CSW's accounting for December 31, 2001 December 31, 2001 vacation pay accruals with AEP's accounting. The (in millions)

CPL $11.8 $2.6 effect of the conforming adjustment was to reduce I&M 9.1 1.7 net assets by $16 million at December 31, 1999 KPCo 3.2 0.6 PSO 6.6 1.2 and reduce net income by $3 million for the year SWEPCo 5.0 1.1 WTU 3.5 0.8 ended December 31, 1999.

L-1 2

Merger transition costs are expected to continue per combined share for the year ended December to be incurred for several years after the merger 31, 1999.

and will be expensed or deferred for amortization as appropriate. As hereinafter summarized, the See Note 8, "Commitments and Contingencies" state settlement agreements provide for, among for information on a recent court decision other things, a sharing of net merger savings with concerning the merger.

certain regulated customers over periods of up to eight years through rate reductions which began 4. Nuclear Plant Restart:

in the third quarter of 2000.

I&M completed the restart of both units of the Summary of key provisions of Merger Rate Cook Plant in 2000. Cook Plant is a 2,110 MW Agreements: two-unit plant owned and operated by I&M under licenses granted by the NRC. I&M shut down State/Company Ratemakinq Provisions Texas - CPL, SWEPCO $221 million rate reduction both units of the Cook Plant in September 1997 WTU over 6 years. due to questions regarding the operability of No base rate increases for certain safety systems that arose during a NRC 3 years post merger.

Indiana - I&M $67 million rate reduction architect engineer design inspection.

over 8 years. Extension of base rate freeze until January 1, 2005. Requires Settlement agreements in the Indiana and additional annual deposits of

$6 million to the nuclear Michigan retail jurisdictions that address decommissioning trust fund recovery of Cook Plant related outage costs for the years 2001 through 2003. were approved in 1999. The IURC approved a Michigan - I&M Customer billing credits of settlement agreement that resolved all matters approximately $14 million over 8 years. Extension of related to the recovery of replacement energy base rate freeze until fuel costs and all outage/restart costs and January 1, 2005.

Kentucky - KPCo Rate reductions of related issues during the extended outage of the approximately $28 million Cook Plant. The MPSC approved a settlement over 8 years.

No base rate increases for agreement for two open Michigan power supply 3 years post merger. cost recovery reconciliation cases that resolved oklahoma - PSO Rate reductions of approximately $28 million all issues related to the Cook Plant extended over 5 years. No base rate outage. The settlement agreements allowed:

increase before January 1, 2003.

Arkansas - SWEPCo Rate reductions of $6 million "* deferral of $200 million of non-fuel restart over 5 years.

Louisiana - SWEPCo Rate reductions of $18 related nuclear operation and maintenance million over 8 years. Base expense for amortization over five years rate cap until June 2005.

ending December 31, 2003, If actual merger savings are significantly less than "* deferral of certain unrecovered fuel and power supply costs for amortization over five years the merger savings rate reductions required by ending December 31, 2003, the merger settlement agreements in the eight "* a freeze in base rates through December 31, year period following consummation of the 2003 and a fixed fuel recovery charge through merger, future results of operations, cash flows March 1, 2004 in the Indiana jurisdiction, and and possibly financial condition could be "* a freeze in base rates and fixed power supply adversely affected. costs recovery factors until January 1, 2004 for the Michigan jurisdiction.

The current annual dividend rate per share of AEP common stock is $2.40. The dividends per share reported on the statements of income for 2000 and 1999 represent pro forma amounts and are based on AEP's historical annual dividend rate of $2.40 per share. If the dividends per share reported for prior periods were based on the sum of the historical dividends declared by AEP and CSW, the annual dividend rate would be $2.60 L-1 3

-1 FE(qC Transmission Rates - In November 2001 FERt. issued an order requiring CPL, PSO, 6. Effects of Regulation:

SWEPCo and WTU to submit revised open access transmission tariffs, and calculate and In accordance with SFAS 71 the consolidated issue refunds for overcharges from January 1, financial statements include regulatory assets 1997. The order resulted from a remand by an (deferred expenses) and regulatory liabilities appeals court of a tariff compliance filing order (deferred revenues) recorded in accordance with issued in November 1998 that had been appealed regulatory actions in order to match expenses and by certain customers. CPL and WTU recorded revenues from cost-based rates in the same refund provisions of $1.7 million and $0.7 million, accounting period. Regulatory assets are respectively, including interest in 2001 for this expected to be recovered in future periods order. PSO and SWEPCo recorded $100,000 through the rate-making process and regulatory each for this order making the AEP total $2.6 liabilities are expected to reduce future cost recoveries. Among other things, application of million.

SFAS 71 requires that the AEP System's West Virginia - On June 2, 2000, the WVPSC regulated rates be cost-based and the recovery of approved a Joint Stipulation between APCo and regulatory assets be probable. Management has other parties related to base rates and ENEC reviewed all the evidence currently available and recoveries. The Joint Stipulation allows for concluded that the requirements to apply SFAS recovery of regulatory assets including any 71 continue to be met for all electric operations in generation-related regulatory assets through the Indiana, Kentucky, Louisiana, Michigan, Oklahoma and Tennessee.

following provisions:

• Frozen transition rates and a wires charge of When the generation portion of the Company's 0.5 mills per KWH. business in Arkansas, Ohio, Texas, Virginia and

• The retention, as a regulatory liability, on the WV no longer met the requirements to apply books of a net cumulative deferred ENEC SFAS 71, net regulatory assets were written off over-recovery balance of $66 million to be for that portion of the business unless they were used to offset the cost of deregulation when determined to be recoverable as a stranded cost generation is deregulated in WV. through regulated distribution rates or wire

• The retention of net merger savings prior to charges in accordance with SFAS 101 and EITF December 31, 2004 resulting from the 97-4. In the Ohio and WV jurisdictions generation merger of AEP and CSW. related regulatory assets that are recoverable

• A 0.5 mills per KWH wires charge for through transition rates have been transferred to departing customers provided for in the WV the distribution portion of the business and are Restructuring Plan (see Note 7 "Customer being amortized as they are recovered through Choice and Industry Restructuring" for charges to regulated distribution customers. As discussion of the WV Restructuring Plan) discussed in Note 7, "Customer Choice and Industry Restructing" the Virginia SCC ordered Management expects that the approved Joint the generation-related regulatory assets in the Stipulation, plus the provisions of pending Virginia jurisdiction to remain with the generation restructuring legislation will, if the legislation portion of the business. Generation-related becomes effective, provide for the recovery of regulatory assets in the Virginia jurisdiction are existing regulatory assets, other stranded costs being amortized concurrent with their recovery and the cost of deregulation in WV. through capped rates. In the Texas jurisdiction generation-related regulatory assets that have been tentatively approved for recovery through securitization have been classified as "regulatory assets designated for securitization." (See Note 7 "Customer Choice and Industry Restructuring" for further details.)

L-1 6

AEP's recognized regulatory assets and liabilities are comprised of the following at:

December 31, 2001 2000 (in millions)

Regulatory Assets:

Amounts Due From Customers For Future Income Taxes $ 814 $ 914 Transition - Regulatory 847 963 Assets Regulatory Assets Designated for 959 953 securitization 139 407 Deferred Fuel costs unamortized Loss on 99 113 Reacquired Debt 80 120 cook Plant Restart Costs DOE Decontamination and Decommissioning 31 35 Assessment 193 other 193 Total Regulatory Assets 53-16BZ Regulatory Liabilities:

Deferred Investment Tax credits $491 $528 393 208 other SH M-6 Total Regulatory Liabilities L-17

[II The recognized regulatory assets and liabilities for the registrant subsidiaries are of two types: those earning a return and those not earning a return. Items not earning a return have their recovery period end date indicated. Regulatory assets and liabilities are comprised of the following items:

AEGCo APCo Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)

Regulatory Assets:

Amounts Due From Customers For Future Income Taxes $(22,725) $(23,996) Note 1 $189,794 $217,540 Note 1 Transition - Regulatory Assets Virginia 46,981 55,523 3un. 2007 Transition - Regulatory Assets west Virginia 127,998 135,946 Jun. 2011 Deferred Fuel costs 11,732 14,669 Unamortized Loss on Reacquired Debt 5,207 5,504 Note 2 10,421 11,676 Note 2 Deferred Storm Damage 6 1,244 Apr. 2002 other 71,890 11,152 Note 3 Total Regulatory Assets $_-172*_2 _447,_S4ZA Regulatory Liabilities:

Deferred Investment Tax Credits $56,304 $59,718 $ 38,328 $ 43,093 WV Rate Stabilization 75,601 75,601 other 61,552 2 614 Total Regulatory Liabilities S 56 9110A 1.ZL:II Note 1: This amount fluctuates from month to month and has no fixed recovery period.

Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants.

Note 3: other may include items not earning a return and would have various recovery periods.

CPL CSPCo Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)

Regulatory Assets:

Amounts Due From Customers For Future Income Taxes $200,496 $ 206,930 Note 1 $ 28,361 $ 31,853 Note 1 Transition - Regulatory Assets 223,830 247,852 Dec. 2008 Excess Earnings (62,852) (39,700)

Regulatory Assets Designated For Securitization 959,294 953,249 Deferred Fuel costs (57,762) 127,295 unamortized Loss on Reacquired Debt 11,180 12,773 Note 2 7,010 8,340 Note 2 DOE Decontamination and Decommissioning Assessment 3,170 3,622 Dec. 2004 Other 11,961 18,815 Note 3 3,066 3,508 Note 3 Total Regulatory Assets $1-L* 65.j7 ] M =294 Ufa Regulatory Liabilities:

Deferred Investment Tax credits $122,893 $128,100 $37,176 $41,234 other 31 11J510 Total Regulatory Liabilities $1289. $]2J.* $9 2$ZIf 52 _

Note 1: This amount fluctuates from month to month and has no fixed recovery period.

Note 2: Unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants.

Note 3: Other may include items not earning a return and would have various recovery periods.

L-18

I&M Recovery KPCo Recovery 2001 2000 Period 2001 2000 Period (in thousands)

Regulatory Assets:

Amounts Due From Customers $83,027 $85,926 Note 1 For Future Income Taxes $171,605 $229,466 Note 1 75,002 112,503 Dec. 2003 1,542 - Feb. 2002 Deferred Fuel Costs unamortized LOSS on 51 459 Note 2 Reacquired Debt 16,255 17,740 Note 2 Cook Plant Restart Costs 80,000 120,000 Dec. 2003 DOE Decontamination and Decommissioning Assessment 27,784 31,744 Dec. 2008 38 281 40.687 Note 3 13.073 12,130 Note 3 other Total Regulatory Assets __ _

Regulatory Liabilities:

Deferred Investment $10,405 $11,656 Tax credits $105,449 $113,773 52,479 9,930 65.51 3,172 other Total Regulatory Liabilities 3157.92 E

recovery period.

Note 1: This amount fluctuates from month to month and has no fixed Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants.

various recovery periods.

Note 3: other may include items not earning a return and would have OPCo PSO Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)

Regulatory Assets:

Amounts Due From Customers $(28,652) Note 1

$186,740 $180,602 Note 1 $(26,085)

For Future Income Taxes Transition - Regulatory Assets 442,707 517,851 Dec. 2007 11,732 43,267 Deferred Fuel Costs unamortized Loss on 13,600 Note 2 5,502 6,106 Note 2 12,321 Reacquired Debt 11.707 15,738 Note 3 other 9 676 10,151 Note 3 Total Regulatory Assets $644.625- 714,710$ 9.

Regulatory Liabilities:

Deferred Investment $35,783

$21,925 $25,214 $33,992 Tax credits 31.858 2,015 other 1,237 1 Total Regulatory Liabilities 3 1 recovery period.

Note 1: This amount fluctuates from month to month and has no fixed Note 2: unamortized loss on reacquired debt varies in its recovery period for each registrant and ranges from one to thirty-seven years recovery period across all registrants.

have various recovery periods.

Note 3: other may include items not earning a return and would SWEPCo WTU Recovery Recovery 2001 2000 Period 2001 2000 Period (in thousands)

Regulatory Assets:

Amounts Due From Customers Note 1 For Future Income Taxes $16,553 $14,558 Note 1 $(13,591)$(13,493) 7,384 35,469 36,872 67,655 Deferred Fuel Costs unamortized Loss on Note 2 19,726 22,626 Note 2 8,198 11,204 Reacquired Debt 13,604 Note 3 other 15.711 A19898 Note 3 5,460 Total Regulatory Assets

• 5 Regulatory Liabilities:

Deferred Investment

$48,714 $53,167 $22,781 $24,052 Tax credits 15,100 Excess Earnings 500 17,300 15,454 8,140 I,10 Other Total Regulatory Liabilities 6 S L recovery period.

Note 1: This amount fluctuates from month to month and has no fixed registrant and ranges from Note 2: unamortized loss on reacquired debt varies in its recovery period for each one to thirty-seven years recovery period across all registrants.

recovery periods.

Note 3: other may include items not earning a return and would have various L-19

1[I

7. Customer Choice and Industry The Ohio Act provides for a five-year transition Restructuring: period to move from cost based rates to market pricing for electric generation supply services. It Prior to 2001 customer choice/industry granted the PUCO broad oversight responsibility restructuring legislation was passed in Ohio, for promulgation of rules for competitive retail Texas, Virginia and Michigan allowing retail electric generation service, approval of a customers to select alternative generation transition plan for each electric utility company suppliers. Customer choice began on January 1, and addressed certain major transition issues 2001 in Ohio and on January 1,2002 in Michigan, including unbundling of rates and the recovery of Virginia and in the ERCOT area of Texas. AEP's stranded costs including regulatory assets and subsidiaries operate in both the ERCOT and SPP transition costs.

areas of Texas.

The Ohio Act made several changes in the Legislation enacted in Oklahoma, Arkansas and taxation of electric companies. Effective January WV to allow retail customers to choose their 1, 2001 the assessment percentage for property electricity supplier is not yet effective. In 2001 taxes on all electric company property other than Oklahoma delayed implementation of customer transmission and distribution was lowered from choice indefinitely. Arkansas delayed the start of 100% to 25%. The assessment percentage customer choice until as late as October 2005. applicable to transmission and distribution The Arkansas Commission has recommended property remains at 88%. Also, electric further delays of the start date or repeal of the companies were exempted from the excise tax restructuring legislation. Before West Virginia's based on receipts. To make up for these tax choice plan can be effective, tax legislation must reductions electric distribution companies became be passed to continue consistent funding for state subject to a new KWH based excise tax. Since and local government. No further legislation has electric companies no longer paid the gross been passed related to restructuring in Arkansas receipts tax, they became liable, as of January 1, or West Virginia. 2002 for the corporation franchise tax and municipal income taxes.

In general, state restructuring legislation provides for a transition from cost-based rate regulated In preparation for the January 1, 2001 start of the bundled electric service to unbundled cost-based transition period, CSPCo and OPCo filed a rates for transmission and distribution service and transition plan in December 1999. After market pricing for the supply of electricity with negotiations with interested parties including the customer choice of supplier. PUCO staff, the PUCO approved a stipulation agreement for CSPCo's and OPCo's transition Ohio Restructuring- Affecting AEP, CSPCo and plans. The approved plans included, among OPCo other things, recovery of generation-related regulatory assets over seven years for OPCo and Customer choice of electricity supplier and over eight years for CSPCo through frozen restructuring began on January 1, 2001, under transition rates for the first five years of the the Ohio Act. During 2001 alternative suppliers recovery period and through a wires charge for registered and were approved by the PUCO as the remaining years. At December 31, 2000, the required by the Ohio Act. At January 1, 2002, amount of regulatory assets to be amortized as virtually all customers continue to receive supply recovered was $518 million for OPCo and $248 service from CSPCo and OPCo with a million for CSPCo.

legislatively required residential generation rate reduction of 5%. All customers continue to be The stipulation agreement required the PUCO to served by CSPCo and OPCo for transmission and consider implementation of a gross receipts tax distribution services. credit rider as the parties could not reach an agreement.

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As of May 1, 2001, electric distribution companies The restructuring law provides an opportunity for became subject to an excise tax based on KWH recovery of just and reasonable net stranded sold to Ohio customers. The last tax year for generation costs. The mechanisms in the Virginia which Ohio electric utilities will pay the excise tax law for net stranded cost recovery are: a capping based on gross receipts is May 1, 2001 through of rates until as late as July 1, 2007, and the April 30, 2002. As required by law, the gross application of a wires charge upon customers who receipts tax is paid in advance of the tax year for depart the incumbent utility in favor of an which the utility exercises its privilege to conduct alternative supplier prior to the termination of the business. CSPCo and OPCo treat the tax rate cap. Capped rates are the rates in effect at payment as a prepaid expense and amortized it to July 1, 1999 if no rate change request was made expense during the tax year. by the utility. APCo did not request new rates; therefore, its current rates are its capped rates.

Following a hearing on the gross receipts tax Virginia's restructuring law does not permit the issue, the PUCO determined that there was no Virginia SCC to change generation rates during duplicate tax overlap period. The PUCO ordered the transition period except for changes in fuel the gross receipts tax credit rider to be effective costs, changes in state gross receipts taxes, or to May 1, 2001 instead of May 1, 2002 as proposed address financial distress of the utility.

by the companies. This order reduced CSPCo's and OPCo's revenues by approximately $90 The Virginia restructuring law also requires filings million. CSPCo's and OPCo's request for to be made that outline the functional separation rehearing of the gross receipts tax issue was also of generation from transmission and distribution denied by the PUCO. A decision on an appeal of and a rate unbundling plan. On January 3, 2001, this issue to the Ohio Supreme Court is pending.

APCo filed its corporate separation plan and rate unbundling plan with the Virginia SCC. The As described in Note 2, the PUCO's denial of the request for recovery of the final year's gross Virginia SCC approved settlement agreements receipts tax and the tax liability affixing on May 1, that resolved most issues except the assignment 2001 stranded the prepaid asset. As a result, an of generation-related regulatory assets among extraordinary loss was recorded in 2001. functionally separated generation, transmission and distribution organizations. The Virginia SCC One of the intervenors at the hearings for determined that generation-related regulatory approval of the settlement agreement (whose assets and related amortization expense should request for rehearing was denied by the PUCO) be assigned to APCo's generation function.

filed with the Ohio Supreme Court for review of Presently, capped rates are sufficient to recover the settlement agreement. During 2001 that generation-related regulatory assets. Therefore, intervenor withdrew from competing in Ohio. The management determined that recovery of APCo's Court dismissed the intervenor's appeal. generation-related regulatory assets remains probable. APCo will not collect a wires charge in CSPCo's and OPCo's fuel costs were no longer 2002 per the settlement agreements. The subject to PUCO fuel clause recovery settlement agreements and related Virginia SCC proceedings beginning January 1, 2001. The order addressed functional separation leaving elimination of fuel clause recoveries in Ohio decisions related to corporate separation for later subjects AEP, CSPCo and OPCo to risk of fuel consideration. The Virginia SCC order approving market price variations and could adversely affect the settlement agreements requires several their results of operations and cash flows. compliance filings, including a fuel/replacement power cost report during an extended outage of Virginia Restructuring- Affecting AEP and APCo an affiliate's nuclear plant. Management is unable to predict the outcome of the Virginia In Virginia, choice of electricity supplier for retail SCC's review of APCo's compliance filings.

customers began on January 1, 2002 under its restructuring law. A finding by the Virginia SCC that an effective competitive market exists would be required to end the transition period.

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[II Texas Restructuring - Affecting AEP, CPL. approved business separation plans. The SWEPCo and WTU business separation plans provided for CPL and WTU to establish separate companies and divide On January 1, 2002, customer choice of electricity their integrated utility operations and assets into supplier began in the ERCOT area of Texas. a power generation company, a transmission and Customer choice has been delayed in other areas distribution utility and a retail electric provider. In of Texas including the SPP area. All of February 2002 the PUCT approved amendments SWEPCo's Texas service territory and a small to SWEPCo's plan. The amended plan separates portion of WTU's service territory are located in the SPP. CPL operates entirely in the ERCOT SWEPCo's Texas jurisdictional transmission and area of Texas. distribution assets and operations into two new regulated transmission and distribution Texas restructuring legislation, among other subsidiaries. In addition, a retail electric provider things: was established by SWEPCo to provide retail

• provides for the recovery of regulatory assets electric service to SWEPCo's Texas jurisdictional and other stranded customers. Until competition commences in the costs through securitization and non-bypassable wires SPP, SWEPCo's assets will not be separated and the SWEPCo retail electric provider will not charges; commence operation.

• requires reductions in NOx and sulfur dioxide emissions; Due to the SPP area delay in the start of

• freezes rates until January 1, 2002; competition, only CPL's and WTU's retail electric

• provides for an earnings test for each of the providers commenced operations on January 1, three years of the rate freeze period (1999 2002. Operations for CPL, SWEPCo and WTU through 2001) which will reduce stranded cost have been functionally separated.

recoveries or if there is no stranded cost provides for a refund or their use to fund Under the Texas Legislation, electric utilities are certain capital expenditures; allowed to recover stranded generation costs

• requires each utility to structurally unbundle including generation-related regulatory assets.

into a retail electric provider, a power The stranded costs can be refinanced through generation company and a transmission and securitization (a financing structure designed to distribution utility; provide lower financing costs than are available

• provides for certain limits for ownership and through conventional financings).

control of generating capacity by companies;

• provides for elimination of the fuel clause In 1999 CPL filed with the PUCT to securitize reconciliation process beginning January 1, $1.27 billion of its retail generation-related 2002; and regulatory assets and $47 million in other

• provides for a 2004 true-up proceeding to qualified restructuring costs. The PUCT determine recovery of stranded costs authorized the issuance of up to $797 million of including final fuel recovery balances, net securitization bonds ($949 million of generation regulatory assets, certain environmental related regulatory assets and $33 million of costs, accumulated excess earnings and qualified refinancing costs offset by $185 million other issues. of customer benefits for accumulated deferred income taxes). Four parties appealed to the Under the Texas Legislation, delivery of electricity Supreme Court of Texas which upheld the continues to be the responsibility of the local PUCT's securitization order. CPL issued its electric transmission and distribution utility securitization bonds in February 2002.

company at regulated prices. Each electric utility was required to submit a plan to structurally CPL included regulatory assets not approved for unbundle its business activities into a retail securitization in its request for recovery of $1.1 electric provider, a power generation company, billion of stranded costs. The $1.1 billion request and a transmission and distribution utility. In 2000 included $800 million of STP costs included in CPL, SWEPCo and WTU filed and the PUCT property, plant and equipment-electric on the L-22

treatment of excess earnings will be amended at Consolidated Balance Sheets. These STP costs that time. CPL has appealed the PUCT's had previously been identified as excess cost estimate of stranded costs and refund of excess over market (ECOM) by the PUCT for regulatory earnings to the Travis County District Court.

purposes. They are earning a lower return and Unaffiliated parties also appealed the PUCT's rate being amortized on an accelerated basis for refund order contending the entire $615 million of making purposes. negative stranded costs should be refunded presently. Management is unable to predict the the After hearings on the issue of stranded costs, outcome of this litigation. An unfavorable ruling PUCT ruled in October 2001 that its current would have a negative impact on results of estimate of CPL's stranded costs was negative operations, cash flows and possibly financial

$615 million. CPL disagrees with the ruling. The condition.

ruling indicated that CPL's costs were below market after securitization of regulatory assets. The Texas Legislation allows for several Management believes CPL has a positive alternative methods to be used to value stranded stranded cost exclusive of securitized regulatory costs in the final 2004 true-up proceeding assets. The final amount of CPL's stranded costs including the sale or exchange of generation including regulatory assets and ECOM will be assets, the issuance of power generation established by the PUCT in the 2004 true-up company stock to the public or the use of an proceeding. If CPL's total stranded costs ECOM model. To the extent that the final 2004 determined in the 2004 true-up are less than the true-up proceeding determines that CPL should amount of securitized regulatory assets, the recover additional stranded costs, the additional PUCT can implement an offsetting credit to amount recoverable can also be securitized.

transmission and distribution rates.

The Texas Legislation provides for an earnings The PUCT ruled that prior to the 2004 true-up test each year of the 1999 through 2001 rate proceeding, no adjustments would be made to the freeze period. For CPL, any earnings in excess of amount of regulatory costs authorized by the the most recently approved cost of capital in its PUCT to be securitized. However, the PUCT also last rate case must be applied to reduce stranded ruled that excess earnings for the period 1999 costs. Companies without stranded costs, 2001 should be refunded through distribution including SWEPCo and WTU, must pay any rates to the extent of any over-mitigation of excess earnings to customers, invest them in stranded costs represented by negative ECOM. In improvements to transmission or distribution 2001 the PUCT issued an order requiring CPL to facilities or invest them to improve air quality at reduce distribution rates by $54.8 million plus generating facilities. The Texas Legislation accrued interest over a five-year period beginning requires PUCT approval of the annual earnings January 1, 2002 in order to return estimated test calculation.

excess earnings for 1999, 2000 and 2001. The Texas Legislation intended that excess earnings The PUCT issued a final order for the 1999 reduce stranded costs. Final stranded cost earnings test in February 2001 and adjustments amounts and the treatment of excess earnings to the accrued 1999 and 2000 excess earnings will be determined in the 2004 true-up were recorded in results of operations in the proceeding. Currently the PUCT estimates that fourth quarter of 2000. After adjustments the 1999 CPL will have no stranded costs and has ordered excess earnings for CPL and WTU were $24 the rate reduction to return excess earnings.

million and $1 million, respectively. SWEPCo had Since CPL expensed excess earnings amounts in no excess earnings in 1999. The PUCT issued a 1999, 2000 and 2001, the order has no additional final order in September 2001 for the 2000 excess effect on reported net income but will reduce cash earnings. CPL's, SWEPCo's and WTU's excess flows for the five year refund period. The amount 2000 earnings were $23 million, $1 million and to be refunded is recorded as a regulatory liability.

$17 million, respectively. An estimate of 2001 excess earnings of $8 million for CPL, $2 million Management believes that CPL will have for SWEPCo and none for WTU has been stranded costs in 2004, and that the current L-23

recorded and will be adjusted, if necessary, in Due to the delay in the start of competition in the 2002 when the PUCT issues its final order SPP areas of Texas, several issues are pending regarding 2001 excess earnings. before the PUCT. These issues impact SWEPCo's and WTU's Texas SPP operations.

Due to the companies' disagreement with the WTU's Texas SPP operations are estimated to be PUCT, its staff and the Office of Public Utility less than 5% of WTU's total operations.

Counsel related to the proper determination of 2000 excess earnings, the companies filed in West Virginia Restructuring - Affecting AEP and district court in October 2001 seeking judicial APCo review of the PUCT's determination of excess earnings. A decision from the court is not In 2000 the WVPSC issued an order approving expected until later in 2002. an electricity restructuring plan which the WV Legislature approved by joint resolution. The joint Beginning January 1, 2002, fuel costs will not be resolution provides that the WVPSC cannot subject to PUCT fuel reconciliation proceedings implement the plan until the legislature makes tax law changes necessary to preserve the revenues for CPL and WTU's ERCOT customers.

of state and local governments. Since the WV Consequently, CPL and WTU will file a final fuel Legislature has not passed the required tax law reconciliation with the PUCT to reconcile their fuel changes, the restructuring plan has not become costs through the period ending December 31, effective. AEP subsidiaries, APCo and WPCo, 2001. Due to the delay of competition for the provide electric service in WV.

SPP area, SWEPCo, which operates in the SPP area, continues to record and request recovery of The WV restructuring plan provides for:

fuel costs under the Texas fuel reconciliation "* deregulation of generation assets proceeding. For WTU's SPP area customers, the "* separation of the generation, transmission PUCT will determine a method to reconcile their and distribution businesses fuel costs beginning in 2002 (see Note 5 "Rate

"* a transition period with capped and fixed rates Matters"). Final unrecovered deferred fuel balances at December 31, 2001 will be included for up to 13 years in each company's 2004 true-up proceeding. If

"* establishment of a rate stabilization deferred the final fuel balances or any amount incurred but liability balance of $81 million ($76 million by not yet reconciled are not recovered, they could APCo and $5 million by WPCo) by the end of have a negative impact on results of operations. year ten of the transition period.

The elimination of the fuel clause recoveries in 2002 in the ERCOT area of Texas will subject APCo's Joint Stipulation, discussed in Note 5 AEP and the retail electric providers of CPL and "Rate Matters" and approved by the WVPSC in WTU to greater risks of fuel market price 2000 in connection with a base rate filing, increases and could adversely affect future provides additional mechanisms to recover results of operations beginning in 2002. transition generation-related regulatory assets.

In order for customer choice to become effective The affiliated retail electric providers of CPL, in WV, the WV Legislature must enact tax SWEPCo and WTU are required by the Texas legislation. Management is unable to predict the Legislation to offer residential and small timing of the passage of such legislation.

commercial customers (with a peak usage of less than 1000 KW) a price-to-beat rate until January Arkansas Restructuring - Affecting AEP and 1, 2007. In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's retail SWEPCo electric providers. Customers with a peak usage of more than 1000 KW are subject to market In 1999 Arkansas enacted legislation to restructure its electric utility industry. Major rates. The Texas restructuring legislation provides provisions of the legislation as amended are:

for the price to beat to be adjusted up to two times annually to reflect changes in fuel and purchased

• retail competition delayed until as late as October 2005; energy costs using a natural gas price index.

L-24

• transmission facilities must be operated by an of operations which continues to be rate ISO if owned by a company which also owns regulated. Additionally, a company must generating facilities; determine if any plant assets are impaired when

• rates will be frozen for one to three years; they discontinue SFAS 71 accounting. At the

• market power issues will be addressed by the time the companies discontinued SFAS 71, the Arkansas Commission; and analysis showed that there was no accounting

• an annual progress report to the Arkansas impairment of generation assets.

General Assembly on the development of competition in electric markets and its impact Prior to 1999, all of the domestic electric utility on retail customers is required. subsidiaries' financial statements reflected the economic effects of regulation under the Based on recommendations in the annual requirements of SFAS 71. As a result of progress report filed by the Arkansas deregulation of generation, the application of Commission, the Arkansas General Assembly SFAS 71 for the generation portion of the passed and the Governor signed legislation in business in Arkansas, Ohio, Texas, Virginia and 2001 changing the start date of electric retail West Virginia was discontinued. Remaining competition to October 1, 2003, and providing the generation-related regulatory assets will be Arkansas Commission with authority to delay that amortized as they are recovered under terms of date for up to an additional two years. transition plans. Management believes that substantially all generation-related regulatory The Arkansas Commission in December 2001 assets and stranded costs will be recovered recommended further delays of the start date or under terms of the transition plans. If future repeal of the restructuring legislation. events including the 2004 true-up proceeding in Texas were to make their recovery no longer Discontinuance of the Application of SFAS 71 probable, the Company would write-off the portion RegulatoryAccounting in Arkansas, Ohio, Texas, of such regulatory assets and stranded costs Virginia and West Virginia - Affecting AEP, APCo, deemed unrecoverable as a non-cash CPL, CSPCo, OPCo, SWEPCo and WTU extraordinary charge to earnings. If any write-off of regulatory assets or stranded costs occurred, The enactment of restructuring legislation and the it could have a material adverse effect on future ability to determine transition rates, wires charges results of operations, cash flows and possibly and any resultant gain or loss under restructuring financial condition.

legislation in Arkansas, Ohio, Texas, Virginia and West Virginia enabled AEP and certain Michigan Restructuring- Affecting AEP and I&M subsidiaries to discontinue regulatory accounting under SFAS 71 for the generation portion of their On June 5, 2000, the Michigan Legislation business in those states. Under the provisions of became law. Its major provisions, which were SFAS 71, regulatory assets and regulatory effective immediately, applied only to electric utilities with one million or more retail customers.

liabilities are recorded to reflect the economic I&M, AEP's electric operating subsidiary doing effects of regulation by matching expenses with business in Michigan, has less than one million related regulated revenues. customers in Michigan. Consequently, I&M was not immediately required to comply with the The discontinuance of the application of SFAS 71 Michigan Legislation.

in Arkansas, Ohio, Texas, Virginia and West Virginia in accordance with the provisions of The Michigan Legislation gives the MPSC broad SFAS 101 and EITF Issue 97-4 resulted in power to issue orders to implement retail recognition of extraordinary gains or losses in customer choice of electric supplier no later than 2000 and 1999. The discontinuance of SFAS 71 January 1, 2002 including recovery of regulatory can require the write-off of regulatory assets and assets and stranded costs. In compliance with liabilities related to the deregulated operations, MPSC orders, on June 5, 2001, I&M filed its unless their recovery is provided through cost proposed unbundled rates, open access tariffs based regulated rates to be collected in a portion and terms of service. On October 11, 2001, the L-25

MPSC approved a settlement agreement which The following table shows the estimated generally approved I&M's June 5, 2001 filing construction expenditures of the subsidiary except for agreed upon modifications. In registrants for 2002 - 2004:

accordance with the settlement agreement, I&M (in millions) agreed that recovery of implementation costs and regulatory assets would be determined in future AEGCo $ 171.9 proceedings. The settlement agreement did not APco 815.5 CPL 573.1 modify the procedure for review of decom CSPCO 408.7 missioning costs recoveries. Customer choice I&M 556.9 commenced for I&M's Michigan customers on KPCO 223. 3 OPco 1,008.0 January 1, 2002. Effective with that date the rates PSO 364.9 on I&M's Michigan customers' bills for retail SWEPCo 321.4 WTU 169.6 electric service were unbundled to allow customers the opportunity to evaluate the cost of APCo, AEP's subsidiary which operates in generation service for comparison with other Virginia and West Virginia, has been seeking offers. l&M's total rates in Michigan remain regulatory approval to build a new high voltage unchanged and reflect cost of service. At this transmission line for over a decade. Through time, none of I&M's customers have elected to December 31, 2001 we had invested change suppliers and no competing suppliers are approximately $40 million in this effort. If the active in I&M's Michigan service territory.

required regulatory approvals are not obtained and the line is not constructed, the $40 million Management has concluded that as of December investment would be written off adversely 31, 2001 the requirements to apply SFAS 71 affecting future results of operations and cash continue to be met since I&M's rates for flows.

generation in Michigan continue to be cost-based regulated. As a result I&M has not yet dis Long-term contracts to acquire fuel for electric continued regulatory accounting under SFAS 71.

generation have been entered into for various terms, the longest of which extends to the year Oklahoma Restructuring - Affecting AEP and 2014 for the AEP System. The expiration date of PSO the longest fuel contract is 2006 for APCo, 2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 Under Oklahoma restructuring legislation passed for OPCo, 2014 for PSO, 2006 for SWEPCo and in 1997 retail open access and customer choice 2006 for WTU. The contracts provide for periodic was scheduled to begin by July 1, 2002.

price adjustments and contain various clauses In June 2001 the Oklahoma Governor signed into that would release the subsidiaries from their obligations under certain force majeure law a bill to delay, indefinitely, the implementation conditions.

of the transition to customer choice and market based pricing under restructuring legislation.

The AEP System has contracted to sell Consequently, PS0, the AEP subsidiary doing approximately 1,300 MW of capacity domestically business in Oklahoma, will remain rate-regulated on a long-term basis to unaffiliated utilities.

until further legislation passes and continues the Certain of these contracts totaling 250 MW of application of SFAS 71 regulatory accounting.

capacity are unit power agreements requiring the delivery of energy only if the unit capacity is

8. Commitments and Contingencies:

available. The power sales contracts expire from 2002 to 2012.

Constructionand Other Commitments - The AEP System has substantial construction commitments In connection with a lignite mining contract for its to support its operations. Aggregate construction Henry W. Pirkey Power Plant, SWEPCo has expenditures for 2002-2004 for consolidated agreed under certain conditions, to assume the domestic and foreign operations are estimated to obligations of the mining contractor. The be $5.4 billion.

contractor's actual obligation outstanding at L-26

purchase the facility at its original construction December 31, 2001 was $75 million. cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is sold As part of the process to receive a renewal of a and the proceeds from the sale are insufficient to Texas Railroad Commission permit for lignite repay the Investors, AEP may be required to mining, SWEPCo has agreed to provide make a payment to the Lessor of up to 85% of the guarantees of mine reclamation in the amount of project's cost. AEP has guaranteed a portion of

$85 million. Since SWEPCo uses self-bonding, the obligations of its subsidiaries to the SPE to the guarantee provides for SWEPCo to commit during the construction and post-construction in use its resources to complete the reclamation periods.

the event the work is not completed by a third to party miner. At December 31, 2001 the cost As of December 31, 2001, project costs subject to reclaim the mine is estimated to be approximately these agreements totaled $168 million, and total

$36 million. costs for the completed facility are expected to be approximately $450 million. Since the lease is AEP, through certain subsidiaries, has entered accounted for as an operating lease for financial into agreements with an unrelated, accounting purposes, neither the facility nor the purpose entity (SPE) to unconsolidated special related obligations are reported on AEP's balance develop, construct, finance and lease a power sheets. The lease is a variable rate obligation generation facility. The SPE will own the power indexed to three-month LIBOR. Consequently as generation facility and lease it to an AEP market interest rates increase, the payments consolidated subsidiary after construction is under this operating lease will also increase.

completed. The lease will be accounted for as an Annual payments of approximately $12 million operating lease with the payment obligations represent future minimum payments under the included in the lease footnote. Payments under first five-year lease term calculated using the the operating lease are expected to commence in indexed LIBOR rate of 2.85% at December 31, the first quarter of 2004. AEP will in turn sublease 2001.

the facility to an unrelated industrial company which will both use the energy produced by the OPCo has entered into a purchased power facility and sell excess energy. Another affiliate of agreement to purchase electricity produced by an AEP has agreed to purchase the excess energy unaffiliated entity's three-unit natural gas fired from the subleasee for resale. plant that is under construction. The first unit is anticipated to be completed in October 2002 and The SPE has an aggregate financing commitment the agreement will terminate 30 years after the from equity and debt participants (Investors) of third unit begins operation. Under the terms of

$427 million. AEP, in its role as construction the agreement OPCo has the options to run the agent for the SPE, is responsible for completing plant until December 31, 2005 taking 100% of the construction by December 31, 2003. In the event power generated. For the remainder of the 30 the project is terminated before completion of year contract term, OPCo will pay the variable construction, AEP has the option to either costs to generate the electricity it purchases purchase the project for 100% of project costs or which could be up to 20% of the plant's capacity.

terminate the project and make a payment to the The estimated fixed payments through December Lessor for 89.9% of project costs. 2005 are $55 million.

The term of the operating lease between the SPE Nuclear Plants- Affecting AEP, CPL and I&M and the AEP subsidiary is five years with multiple extension options. If all extension options are I&M owns and operates the two-unit 2,110 MW exercised the total term of the lease would be 30 Cook Plant under licenses granted by the NRC.

years. AEP's lease payments to the SPE are CPL owns 25.2% of the two-unit 2,500 MW STP.

sufficient to provide a return to the Investors. At STPNOC operates STP on behalf of the joint the end of the first five-year lease term or any owners under licenses granted by the NRC. The extension, AEP may renew the lease at fair operation of a nuclear facility involves special market value subject to Investor approval; L-27

II risks, potential liabilities, and specific regulatory SNF Disposal- Affecting AEP, CPL, and I&M and safety requirements. Should a nuclear incident occur at any nuclear power plant facility Federal law provides for government in the U.S., the resultant liability could be responsibility for permanent SNF disposal and substantial. By agreement I&M and CPL are assesses nuclear plant owners fees for SNF partially liable together with all other electric utility disposal. A fee of one mill per KWH for fuel companies that own nuclear generating units for consumed after April 6, 1983 at Cook Plant and a nuclear power plant incident at any nuclear STP is being collected from customers and plant in the U.S. In the event nuclear losses or remitted to the U.S. Treasury. Fees and related liabilities are underinsured or exceed interest of $220 million for fuel consumed prior to accumulated funds and recovery in rates is not April 7, 1983 at Cook Plant have been recorded possible, results of operations, cash flows and as long-term debt. I&M has not paid the financial condition would be adversely affected. government the Cook Plant related pre-April 1983 fees due to continued delays and uncertainties Nuclear Incident Liability - Affecting AEP, CPL related to the federal disposal program. At and I&M December 31, 2001, funds collected from customers towards payment of the pre-April 1983 The Price-Anderson Act establishes insurance fee and related earnings thereon are in external protection for public liability arising from a nuclear funds and approximate the liability. CPL is not incident at $9.5 billion and covers any incident at liable for any assessments for nuclear fuel a licensed reactor in the U.S. Commercially consumed prior to April 7, 1983 since the STP available insurance provides $200 million of units began operation in 1988 and 1989.

coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the Decommissioning and Low Level Waste liability would be provided by a deferred premium Accumulation Disposal- Affecting AEP, CPL and assessment of $88 million on each licensed /&M reactor in the U.S. payable in annual installments of $10 million. As a result, I&M could be Decommissioning costs are accrued over the assessed $176 million per nuclear incident service lives of the Cook Plant and STP. The payable in annual installments of $20 million. CPL licenses to operate the two nuclear units at Cook could be assessed $44 million per nuclear Plant expire in 2014 and 2017. After expiration of incident payable in annual installments of $5 the licenses, Cook Plant is expected to be million as its share of a STPNOC assessment. decommissioned through dismantlement. The The number of incidents for which payments estimated cost of decommissioning and low level could be required is not limited. radioactive waste accumulation disposal costs for Cook Plant ranges from $783 million to $1,481 Insurance coverage for property damage, million in 2000 nondiscounted dollars. The wide decommissioning and decontamination at the range is caused by variables in assumptions Cook Plant and STP is carried by I&M and including the estimated length of time SNF may STPNOC in the amount of $1.8 billion each. Cook need to be stored at the plant site subsequent to Plant and STPNOC jointly purchase $1 billion of ceasing operations. This, in turn, depends on excess coverage for property damage, de future developments in the federal government's commissioning and decontamination. Additional SNF disposal program. Continued delays in the insurance provides coverage for extra costs federal fuel disposal program can result in resulting from a prolonged accidental outage. increased decommissioning costs. I&M is re I&M and STPNOC utilize an industry mutual covering estimated Cook Plant decommissioning insurer for the placement of this insurance costs in its three rate-making jurisdictions based coverage. Participation in this mutual insurer on at least the lower end of the range in the most requires a contingent financial obligation of up to recent decommissioning study at the time of the

$36 million for I&M and $3 million for CPL which last rate proceeding. The amount recovered in is assessable if the insurer's financial resources rates for decommissioning the Cook Plant and would be inadequate to pay for losses. deposited in the external fund was $27 million in L-28

2001 and $28 million in 2000 and 1999. acquired AEP common stock between July 25, 1997 and June 25, 1999. The complaint alleged The licenses to operate the two nuclear units at that the defendants knowingly violated federal STP expire in 2027 and 2028. After expiration of securities laws by disseminating materially false the licenses, STP is expected to be and misleading statements related to the decommissioned using the decontamination extended Cook Plant outage.

method. CPL estimates its portion of the costs of decommissioning STP to be $289 million in 1999 Municipal Franchise Fee Litigation - Affecting nondiscounted dollars. CPL is accruing and AEP and CPL recovering these decommissioning costs through rates based on the service life of STP at a rate of In 2001 CPL settled litigation regarding municipal

$8 million per year. franchise fees in Texas. CPL paid $11 million to settle the litigation and be released from any further liability. The City of San Juan, Texas had Decommissioning costs recovered from filed a class action suit in 1996 seeking $300 customers are deposited in external trusts. In million in damages.

2001 and 2000 I&M deposited in its decommissioning trust an additional $12 million Texas Base Rate Litigation - Affecting AEP and and $6 million, respectively, related to special CPL regulatory commission approved funding for decommissioning of the Cook Plant. Trust fund In 2001 the Texas Supreme Court denied CPL's earnings increase the fund assets and the request to review a case resulting from a 1997 recorded liability and decrease the amount PUCT base rate order. The Court also denied needed to be recovered from ratepayers. CPL's rehearing request.

Decommissioning costs including interest, unrealized gains and losses and expenses of the The primary issues were:

trust funds are recorded in other operation "* the classification of $800 million of invested expense for Cook Plant. For STP, nuclear capital in STP as ECOM and assigning it a decommissioning costs are recorded in other lower return on equity than other generation operation expense, interest income of the trusts property; are recorded in nonoperating income and interest "* and an $18 million disallowance of an expense of the trust funds are included in interest affiliate service billings.

charges.

Lignite Mining Agreement Litigation - Affecting On the AEP Consolidated Balance Sheets, AEP and SWEPCo nuclear decommissioning trust assets are included in other assets and a corresponding In 2001 SWEPCo settled ongoing litigation nuclear decommissioning liability is included in concerning lignite mining in Louisiana. Since other noncurrent liabilities. On CPL's balance 1997 SWEPCo has been involved in litigation sheets, the nuclear decommissioning liability of concerning the mining of lignite from jointly owned

$99 million is included in electric utility plant lignite reserves. SWEPCo and CLECO are each accumulated depreciation and amortization. At a 50% owner of Dolet Hills Power Station Unit 1 December 31, 2001 and 2000, the and jointly own lignite reserves in the Dolet Hills decommissioning liability for Cook Plant and STP area of northwestern Louisiana. Under terms of combined totals $699 million and $654 million, a settlement, SWEPCo purchased an unaffiliated respectively. mine operator's interest in the mining operations and related debt and other obligations for $86 Shareholders'Litigation - Affecting AEP million.

On December 21, 2001, the U.S. District Court for FederalEPA Complaint and Notice of Violation the Southern District of Ohio dismissed a class Affecting AEP, APCo, CSPCo, I&M, and OPCo action lawsuit against AEP and four former or present officers. The class consisted of all Since 1999 AEP, APCo, CSPCo, I&M, and OPCo persons and entities who purchased or otherwise have been involved in litigation regarding L-29

generating plant emissions under the Clean Air AEP System companies do not prevail, any Act. Federal EPA and a number of states alleged capital and operating costs of additional pollution that AEP System companies and eleven control equipment that may be required as well as unaffiliated utilities modified certain units at coal any penalties imposed would adversely affect fired generating plants in violation of the Clean Air future results of operations, cash flows and Act. Federal EPA filed complaints against AEP possibly financial condition unless such costs can subsidiaries in U.S. District Court for the Southern be recovered through regulated rates, and where District of Ohio. A separate lawsuit initiated by states are deregulating generation, unbundled certain special interest groups was consolidated transition period generation rates, stranded cost with the Federal EPA case. The alleged wires charges and future market prices for modification of the generating units occurred over electricity.

a 20 year period.

In December 2000 Cinergy Corp., an unaffiliated Under the Clean Air Act, if a plant undertakes a utility, which operates certain plants jointly owned major modification that directly results in an by CSPCo, reached a tentative agreement with emissions increase, permitting requirements Federal EPA and other parties to settle litigation might be triggered and the plant may be required regarding generating plant emissions under the to install additional pollution control technology. Clean Air Act. Negotiations are continuing This requirement does not apply to activities such between the parties in an attempt to reach final as routine maintenance, replacement of degraded settlement terms. Cinergy's settlement could equipment or failed components, or other repairs impact the operation of Zimmer Plant and W.C.

needed for the reliable, safe and efficient Beckjord Generating Station Unit 6 (owned 25.4%

operation of the plant. The Clean Air Act and 12.5%, respectively, by CSPCo). Until a final authorizes civil penalties of up to $27,500 per day settlement is reached, CSPCo will be unable to per violation at each generating unit ($25,000 per determine the settlement's impact on its jointly day prior to January 30, 1997). In March 2001 the owned facilities and its results of operations and District Court ruled claims for civil penalties based cash flows.

on activities that occurred more than five years NOx Reductions - Affecting AEP, AEGCo, APCo, before the filing date of the complaints cannot be CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo imposed. There is no time limit on claims for injunctive relief. Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions in a In February 2001 the government filed a motion number of eastern states, including certain states requesting a determination that four projects in which the AEP System's generating plants are undertaken on units at Sporn, Cardinal and Clinch located. The NOx Rule has been upheld on River plants do not constitute "routine appeal. The compliance date for the NOx Rule is maintenance, repair and replacement" as used in May 31, 2004.

the Clean Air Act. Management believes its maintenance, repair and replacement activities The NOx Rule required states to submit plans to were in conformity with the Clean Air Act and comply with its provisions. In 2000 Federal EPA intends to vigorously pursue its defense.

ruled that eleven states, including states in which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and In January 2002 the U.S. Court of Appeals for the OPCo's generating units are located, failed to 1 1 th Circuit ruled that TVA may pursue its court submit approvable compliance plans. Those challenge of a Federal EPA administrative order states could face stringent sanctions including charging similar violations to those in the limits on construction of new sources of air complaints against AEP and other utilities.

emissions, loss of federal highway funding and Management is unable to estimate the loss or possible Federal EPA takeover of state air quality range of loss related to the contingent liability for management programs. AEP subsidiaries and civil penalties under the Clear Air Act proceedings other utilities requested that the D.C. Circuit Court and unable to predict the timing of resolution of review this ruling.

these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. In the event the L-30

In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting petitions filed by Estimated Amount certain northeastern states under the Clean Air Compliance Cost Spent Act. The rule imposes emissions reduction (in millions) requirements comparable to the NOx Rule AEGCo $125 $

beginning May 1, 2003, for most of AEP's coal APCO 365 130 fired generating units. Affected utilities including CPL 57 4 certain AEP operating companies, petitioned the CSPCo 106 1 D.C. Circuit Court to review the Section 126 Rule. I&M 202 KPCo 140 13 After review, the D.C. Circuit Court instructed OPCO 606 277 Federal EPA to justify the methods it used to SWEPCO 28 21 allocate allowances and project growth for both the NOx Rule and the Section 126 Rule. AEP Since compliance costs cannot be estimated with subsidiaries and other utilities requested that the certainty, the actual cost to comply could be D.C. Circuit Court vacate the Section 126 Rule or significantly different than the preliminary suspend its May 2003 compliance date. On estimates depending upon the compliance August 24, 2001, the D.C. Circuit Court issued an alternatives selected to achieve reductions in NOx order tolling the compliance schedule until emissions. Unless any capital and operating costs Federal EPA responds to the Court's remand. of additional pollution control equipment are Federal EPA has announced that it intends to recovered from customers, they will have an adopt May 31, 2004, as the compliance date for adverse effect on results of operations, cash the Section 126 Rule when it finalizes the NOx flows and possibly financial condition.

budgets for both rules.

MergerLitigation- On January 18, 2002, the U.S.

In 2000 the Texas Natural Resource Court of Appeals for the District of Columbia ruled Conservation Commission adopted rules requiring that the SEC failed to prove that the June 15, significant reductions in NOx emissions from utility 2000 merger of AEP with CSW meets the sources, including CPL and SWEPCo. The requirements of the PUHCA and sent the case compliance date is May 2003 for CPL and May back to the SEC for further review. Specifically, 2005 for SWEPCo. the court told the SEC to revisit its conclusion that the merger met PUHCA requirements that utilities During 2001 selective catalytic reduction (SCR) be "physically interconnected" and confined to a technology to reduce NOx emissions on OPCo's "single area or region."

Gavin Plant commenced operations. Construction of SCR technology at certain other AEP In its June 2000 approval of the merger, the SEC generating units continues with completion agreed with AEP that the companies' systems are scheduled in 2002 through 2006. integrated because they have transmission access rights to a single high-voltage line through Our estimates indicate that compliance with the Missouri and also met the PUCHA's single region NOx Rule, the Texas Natural Resource requirement because it is now technically possible Conservation Commission rule and the Section to centrally control the output of power plants 126 Rule could result in required capital across many states. In its ruling, the appeals expenditures of approximately $1.6 billion of court said that the SEC failed to explain its which approximately $450 million has been spent conclusions that the transmission integration and through December 31, 2001 for the AEP System. single region requirements are satisfied.

Estimated compliance costs and amounts spent by registrant subsidiaries are as follows: Management believes that the merger meets the requirements of the PUHCA and expects the matter to be resolved favorably.

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Enron Bankruptcy - Affecting AEP, APCo, 9. Acquisitions and Dispositions:

CSPCo, I&M, KPCo and OPCo On June 1, 2001, AEP, through a wholly owned At the date of Enron's bankruptcy AEP had open subsidiary, purchased Houston Pipe Line trading contracts and trading accounts Company and Lodisco LLC for $727 million from receivables and payables with Enron. In addition, Enron. The acquired assets include 4,200 miles on June 1, 2001, we purchased Houston Pipe of gas pipeline, a 30-year $274 million prepaid Line from Enron and entered into a lease lease of a gas storage facility and certain gas arrangement with a subsidiary of Enron for a gas marketing contracts. The purchase method of storage facility. At the date of Enron's bankruptcy accounting was used to record the acquisition.

various HPL related contingencies and According to APB Opinion No. 16 "Business indemnities remained unsettled. In the fourth Combinations" AEP recorded the assets acquired quarter of 2001 AEP provided $47 million ($31 and liabilities assumed at their estimated fair million net of tax) for our estimated loss from the values as determined by the Company's Enron bankruptcy. The amounts for certain management based on information currently subsidiary registrants were: available and on current assumptions as to future operations. Based on a preliminary purchase Amounts price allocation the excess of cost over fair value Amounts Net of of the net assets acquired was approximately Regi strant Provided Tax $190 million and is recorded as goodwill. SFAS (in millions) 142 "Goodwill and Other Intangible Assets" treats goodwill as a non-amortized, non-wasting asset APCO $5.2 $3.4 effective January 1, 2002. Therefore, goodwill CSPCO 3.2 2.1 was amortized for only seven months in 2001 on I&M 3.4 2.2 a straight-line basis over 30 years. The purchase KPCO 1.3 0.8 method results in the assets, liabilities and OPCo 4.3 2.8 earnings of the acquired operations being included in AEP's consolidated financial The amounts provided were based on an analysis statements from the purchase date.

of contracts where AEP and Enron are counterparties, the offsetting of receivables and SFAS 141 "Business Combinations" apply to all payables, the application of deposits from Enron business combinations initiated and and management's analysis of the HPL related consummated after June 30, 2001.

purchase contingencies and indemnifications. If there are any adverse unforeseen developments AEP also purchased the following assets or in the bankruptcy proceedings, our future results acquired the following businesses from July 1, of operations, cash flows and possibly financial 2001 through December 31, 2001 for an condition could be adversely impacted.

aggregate total of $1,651 million:

SWEPCo, an AEP subsidiary, purchased Other - AEP and its registrant subsidiaries are involved in a number of other legal proceedings the Dolet Hills mining operations including and claims. While management is unable to existing mine reclamation liabilities at its predict the ultimate outcome of these matters, it is jointly owned lignite reserves in Louisiana.

The purchase resulted from a litigation not expected that their resolution will have a settlement discussed in Note 8, material adverse effect on results of operations, "Commitments and Contingencies".

cash flows or financial condition.

Management expects the acquisition to have minimal impact on results of operations.

• Quaker Coal Company as part of a bankruptcy proceeding settlement and assumed additional liabilities of approximately $58 million. The acquisition L-32

Dispositions includes property, coal reserves, mining operations and royalty interests in In March 2001 CSWE, a subsidiary company, Colorado, Kentucky, Ohio, Pennsylvania completed the sale of Frontera, a generating plant and West Virginia. AEP will continue to in that the FERC required to be divested operate the mines and facilities which connection with the merger of AEP and CSW.

employ over 800 individuals. The sale proceeds were $265 million and resulted MEMCO Barge Line that adds 1,200 in an after tax gain of $46 million.

hopper barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450 In July 2001 AEP, through a wholly owned employees will continue to operate the subsidiary, sold its 50% interest in a 120 barge line. MEMCO also adds major megawatt generating plant located in Mexico.

of barging operations on the Mississippi and The sale resulted in an after tax gain Ohio rivers to AEP's barging operations approximately $11 million.

on the Ohio and Kanawha rivers.

4,000 megawatts of UK coal-fired In July 2001 OPCo, an AEP subsidiary, sold coal to generation that includes Fiddler's Ferry, a mines in Ohio and West Virginia and agreed of coal four-unit, 2,000-megawatt station on the purchase approximately 34 million tons River Mersey in northwest England, from the purchaser of the mines through 2008.

on approximately 200 miles from London and The sale is expected to have a nominal impact Ferrybridge, a four-unit, 2,000-megawatt results of operations and cash flows.

station on the River Aire in northeast its England, approximately 200 miles from In December 2001 AEP completed the sale of ownership interests in the Virginia and West London and related coal stocks.

A 20% equity interest in Caiua, a Brazilian Virginia PCS (personal communications services) electric operating company which is a Alliances for stock. AEP recorded a 25%

is subsidiary of Vale. See Note 17, "Power, valuation provision on the stock received and and Communications restricted from selling this stock until after January Distribution Projects". The Company converted a total 1, 2003. In addition, the number of shares AEP of $66 million on an existing loan and can sell each month is limited in order to prevent accrued interest on that loan into Caiua large swings in the stock price. The sales resulted equity. in an after tax gain of approximately $7 million.

Indian Mesa Wind Project consisting of a 160 megawatts of wind generation located In December 2000 the Company, through wholly owned subsidiary, committed to negotiate near Fort Stockton, Texas.

Acquired existing contracts and hired 22 a sale of its 50% investment in Yorkshire, a U.K.

a key staff from Enron's London-based electricity supply and distribution company. As international coal trading group. result a $43 million impairment writedown ($30 million after tax) was recorded in the fourth the Regarding the 2001 acquisitions management has quarter of 2000 to reflect the net loss from quarter of 2001. The recorded the assets acquired and liabilities expected sale in the first assumed at their estimated fair values in impairment writedown is included in Other Income On accordance with APB Opinion No. 16 and SFAS on AEP's Consolidated Statements of Income.

sell the 141 as appropriate based on currently available February 26, 2001 an agreement to information and on current assumptions as to Company's 50% interest in Yorkshire was signed.

the future operations. Management is in the process On April 2, 2001, following the approval of of obtaining independent appraisals regarding buyer's shareholders, the sale was completed certain of these acquisitions and evaluating others without further impact on AEP's consolidated earnings.

to refine its determination of fair values.

Accordingly the allocation of the purchase prices a are subject to revision based on the final In December 2000, CSW International, in a determinations. subsidiary company sold its investment L-33

[II Chilean electric company for $67 million. A net provide medical and death benefits for retired loss on the sale of $13 million ($9 million after tax) is included in Other Income, and includes $26 employees in the U.S.

million ($17 million net of tax) of losses from foreign exchange rate changes that were The foreign pension plans are for employees of previously reflected in other comprehensive SEEBOARD in the U.K. and CitiPower in income. In the second quarter of 2000 manage Australia. The majority of SEEBOARD's ment determined that the then existing decline in employees joined a pension plan that is market value of the shares was other than administered for the U.K.'s electricity industry. The temporary. As a result the investment was written assets of this plan are actuarially valued every down by $33 million ($21 million after tax) in June three years. SEEBOARD and its participating 2000. The total loss from both the write down of employees both contribute to the plan.

the Chilean investment to market in the second Subsequent to July 1, 1995, new employees were quarter and from the sale in the fourth quarter no longer able to participate in that plan and two was $46 million ($30 million net of tax). new pension plans were made available to new employees of SEEBOARD. CitiPower sponsors a defined benefit pension plan that covers all

10. Benefit Plans:

employees.

In the U.S. AEP sponsors two qualified pension plans and two nonqualified pension plans. The following tables provide a reconciliation of the Substantially all employees in the U.S., are changes in the plans' benefit obligations and fair covered by one or both of the pension plans. value of assets over the two-year period ending OPEB plans are sponsored by the AEP System to December 31, 2001, and a statement of the funded status as of December 31 for both years:

L-34

U.S. Foreign OPEB U.S.

Plans Pension Plans Pension Plans 2001 2000 2001 2000 2001 2000 (in millions)

Reconciliation of benefit obligation: $2,934 $1,179 $1,17613 $1,668 30 $1,365 29 obligation at January 1$ 3,161 60 12 106 69 60 64 114 Service Cost 232 227 5 8 7 Interest Cost 4 (b) (67) (c) 17 Parti ci pant Contributions (71) (a)

Plan Amendments (36) (95)

Foreign Currency Translation 80 192 262 Adjustment 218 (62) (d) 121 (287)

Actuarial (Gain) Loss (64) (88) (85)

Divestures (207) (58) 51 (e)

(291) 1 Benefit Payments Curtailments obligation at December 31 Reconciliation of fair value of plan assets: $1,405 $704 $668 Fair value of plan assets at $3,866 $1, 290 (31) 2 3,911 (131) 55 January 1 $ (182) 250 118 112 7

Actual Return on Plan Assets 2 4 5 8 7 Company Contributions Parti ci pant Contributions (111)

Foreign Currency Translation (40)

Adjustment (207) (85)

(291) (88)

Benefit Payments (6.249 Fair value of plan assets at December 31

$(964)

Funded status: $ 750 $(27) $111 $(944)

$146 Funded status at December 31 - 263 298 Unrecognized Net Transition (15) (23) 9 10 17 (Asset) obligation (12) (12) unrecognized Prior-Service cost 448 unrecognized Actuarial (628) 74 649 35 (Gain) Loss Prepaid Benefit (Accrued 5__8U 5-56 I_5A 191)

Liability) nMpA n plans converted to the cash balance pension formula from a final average (a) one of the qualified pensio pay formula.

(b) Related to the purchase of Houston Pipe Line company and MEMCO Barge Line.

(c) change to a service-related formula for retirement health care costs and a 50% of pay life insurance benefit for retiree life insurance. coal company.

(d) Related to the sale of central Ohio Coal Company, Southern Ohio coal Company and windsor and windsor Coal southern Ohio Coal company (e) Related to the shutdown of Central Ohio coal Company, company.

costs and accrued benefit liability recognized The following table provides the amounts for prepaid benefit years. The amounts for additional minimum in the consolidated balance sheets as of December 31 of both for 2000 were recorded in 2001 and liability, intangible asset and accumulated other comprehensive income the amounts for 2001 will be recorded in 2002.

OPEBU. Plans S.

U.S. Foreign Pension Plans Pension Plan 200U 2001 2000 2000 2001 2001 (in millions)

$ 159 $57 $54- $ (16)1 $ (221) 3 Prepaid Benefit Costs $ 205 (51) (72) (1) N/A

- N/A Accrued Benefit Liability (15) (24) - N/A N/A Additional Minimum Liability 9 14 Intangible Asset Accumulated other 6 10 N/A Comprehensive Income $8__7 Net Asset (Liability) other comprehensive (Income)

Expense Attributable to - N/A change in Additional Pension i_0)

Liability Recognition N/A = Not Applicable L-35

I[I Both of the AEP System's nonqualified pension plans had accumulated benefit obligations in excess of plan assets of $40 million and $26 million at December 31, 2001 and $41 million and $26 million at December 31, 2000. There are no plan assets in the nonqualified plans.

The AEP System's OPEB plans had accumulated benefit obligations in excess of plan assets of $944 million and $964 million at December 31, 2001 and 2000, respectively.

In late December 2001 AEP purchased generation plants in the UK (see Note 9, "Acquisitions and Dispositions"). The purchase included the pension plan of the existing generation plant employees.

In connection with the acquisition, a $10 million liability for the accumulated benefit obligation in excess of plan assets was assumed.

The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2001, 2000 and 1999:

U.S. Foreign U.S.

Pension Plans Pension Plans OPEB Plans 2001 2000 1999 2001 2000 1999 2001 2000 1999 (in millions)

Service cost $ 69 $ 60 $ 71 $ 12 $ 13 $ 15 Interest cost $ 30 $ 29 $ 33 232 227 211 60 64 59 114 106 90 Expected return on plan assets (338) (321) (299) (69) (75) (71) (61) (57) (49)

Amortization of transition (asset) obligation Amortization of prior-service (8) (8) (8) 30 41 43 cost - 13 12 Amortization of net actuarial (gain) loss C24) 39) 15)

Net periodic benefit cost 18 4 5 (credit) (69) (68) (28) 4 3 curtailment loss(a) 3 131 123 122 Net periodic benefit 1 79 18 cost (credit) after curtailments k(69) &_(W) 5_(Z8) $4 $__ 3 $_ 1132 $202 $-14-0 (a) curtailment charges were recognized during 2000 and 1999 for the shutdown of Central Ohio coal company, Southern Ohio coal company and windsor Coal company.

The following table provides the net periodic benefit cost (credit) for the plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:

U.S. U.S Pension Plans OPEB Plans 2001 2000 1999 2001 2000 1999 (in thousands)

APCo $(13,645) $(14,047) $(3,925) $22,810 $ 22,139 $19,431 CPL (3,411) (2,986) (4,270) 8,214 6,656 7,595 CSPCo (10,624) (10,905) (4,893) 10,328 9,643 8,623 I&M (7,805) (8,565) (1,259) 15,077 14,155 13,664 KPCo (1,922) (2,075)

OPCo (393) 2,438 2,364 2,652 (14,879) (15,041) (4,979) 34,444 116,205 52,518 PSO (2,480) (2,196) (3,129)

SWEPCo 6,187 4,277 5,516 (3,051) (2,606) (3,734) 6,399 4,152 4,913 WTU (1,664) (1,585) (2,221) 3,729 2,929 3,377 The weighted-average assumptions as of December 31, used in the measurement of the Company's benefit obligations are shown in the following tables:

U.S. Foreign Pension Plans Pension Plans U.S. OPEB Plans 2001 2000 1999 2001 2000 1999 2001 2000 1999 Discount rate %u 7.2S 75 7.50 80 8.00 5.

5-5.8  %

5-5.5 5.5-6 7.25 7.50  %

8.00 plan assets 9.00 9.00 9.00 Rate of compensation 6.1-7.5 6-7.5 6.5-7.5 8.75 8.75 8.75 increase 3.7 3.2 3.8 4.0 3.5-4.0 4-4.5 N/A N/A N/A L-36

Other UMWA Benefits - AEP and OPCo provide For OPEB measurement purposes, an 8% annual UMWA pension, health and welfare benefits for rate of increase in the per capita cost of covered certain unionized mining employees, retirees, and health care benefits was assumed for 2002. The their survivors who meet eligibility requirements.

rate was assumed to decrease gradually each The benefits are administered by UMWA trustees year to a rate of 5% through 2005 and remain at and contributions are made to their trust funds.

that level thereafter. Contributions are expensed as paid as part of the cost of active mining operations and were not Assumed health care cost trend rates have a material in 2001, 2000 and 1999.

significant effect on the amounts reported for the OPEB health care plans. A I % change in 11. Stock-Based Compensation:

assumed health care cost trend rates would have the following effects:

AEP has a Long-term Incentive Plan under which 1% Increase 1% Decrease a maximum of 15,700,000 shares of common (in millions) service stock can be issued to key employees. The plan Effect on total and interest cost was adopted in 2000.

components of net periodic postretirement $(15) health care benefit cost $ 18 Under the plan, the exercise price of each option Effect on the health care granted equals the market price of AEP's component of the common stock on the date of grant. These Accumulated Postretirement (156) options will vest in equal increments, annually, Benefit obligation 189 over a three-year period with a maximum exercise term of ten years.

AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered to non-UMWA CSW maintained a stock option plan prior to the U.S. employees. The cost for contributions to merger with AEP in 2000. Effective with the these plans totaled $55 million in 2001, $37 merger, all CSW stock options outstanding were million in 2000 and $36 million in 1999. converted into AEP stock options at an exchange Beginning in 2001 AEP's contributions to the ratio of one CSW stock option for 0.6 of an AEP plans increased to 4.5% of the initial 6% of stock option. The exercise price for each CSW employee pay contributed from the previous 3% stock option was adjusted for the exchange ratio.

of the initial 6% of employee base pay The provisions of the CSW stock option plan will contributed. continue in effect until all options expire or there are no longer options outstanding. Under the The following table provides the cost for CSW stock option plan, the option exercise price contributions to the savings plans by the following was equal to the stock's market price on the date AEP registrant subsidiaries for fiscal years 2001, of grant. The grant vested over three years, one 2000 and 1999: third on each of the first three anniversary dates 2001 2000 1999 of the grant, and expires 10 years after the (in thousands) original grant date. All CSW stock options are fully vested.

$3,988 $4,091 APCO $7,031 3,284 CPL 3,046 3,161 CSPCO 2,789 1,638 1,679 7,833 4,231 3,996 I&M 1,016 544 561 KPCO OPCO 6,398 3,713 3,744 PSO 2,235 2,306 2,435 SWEPCO 2,776 2,880 2,961 WTU 1,558 1,708 1,766 L-37

I.

The following table summarizes share activity in the above plans, and the weighted-average exercise price:

2001 2000 1999 weighted wei ghted weighted Average Average Average options Exercise options Exercise Options Exercise (in thousands) Price (in thousands) Price (in thousands) Price outstanding at beginning of year 6,610 $36 825 $40 866 $40 Granted 645 $45 6,046 $36 Exercised (216) $38 (26) $36 (22) $38 Forfeited (217) $37 (235) $39 _(19) $43 outstanding at end of year 6,822 $37 i*_1_0 $36 825 $40 options Exercisable at end of year 3_95 $43 588 $41 707 $42 The weighted-average grant-date fair value of options granted in 2001 and 2000 was $8.01 and 12. Business Segments:

$5.50 per share. There were no options granted in 1999. Shares outstanding under the stock In fiscal year 2000, AEP reported the following option plan have exercise prices ranging from $35 four business segments: Domestic Electric to $49 and a weighted-average remaining Utilities; Foreign Energy Delivery; Worldwide contractual life of 8.5 years. Energy Investments; and Other. With this structure, our regulated domestic utility If compensation expense for stock options had companies were considered single, vertically been determined based on the fair value at the integrated units, and were reported collectively in grant date, net income and earnings per share the Domestic Electric Utilities segment.

would have been the pro forma amounts shown below: In 2001, we moved toward our goal of functionally 2001 2000 1999 and structurally segregating our businesses. The Pro forma net income (in millions) ensuing realignment of our operations resulted in

$959 $264 $972 our current business segments, Wholesale, Pro forma earnings per share: Energy Delivery and Other. The business Basic $2.98 $0.82 $3.03 activities of each of these segments are as Diluted $2.97 $0.82 $3.03 follows:

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

• Generation of electricity for sale to retail and wholesale customers, The pro forma amounts are not representative of

• Marketing and trading of electricity and the effects on reported net income for future gas worldwide.

years.

• Gas pipeline and storage services and other energy supply related business The fair value of each option award is estimated on the date of grant using the Black-Scholes Energy Delivery option-pricing model with the following weighted

• Domestic electricity transmission average assumptions used to estimate the fair

• Domestic electricity distribution value of options granted:

2001 2000 Other Risk Free Interest Rate 4.87% 5.02%

• Foreign electricity generation investments Expected Life 7 years 7 years Expected volatility 28.40% 24.75% ° Foreign electricity distribution and supply Expected Dividend Yield 6.05% 6.02%

investments Telecommunication services L-38

income in that it does not take into account Segment results of operations for the twelve interest expense or income taxes. EBIT is months ended December 31, 2001, 2000 and believed to be a reasonable gauge of results of 1999 are shown below. These amounts include operations. By excluding interest and income certain estimates and allocations where taxes, EBIT does not give guidance regarding the necessary. demand of debt service or other interest requirements, or tax liabilities or taxation rates.

We have used Earnings before Interest and The effects of interest expense and taxes on Income Taxes (EBIT) as a measure of segment overall corporate performance can be seen in the is operating performance. The EBIT measure consolidated income statement.

total operating revenues net of total operating expenses and other routine income and deductions from income. It differs from net Reconciling AEP Energy other Adiustments consolidated wholesale Delivern millions)

Year 2001 Revenues from:

External unaffiliated $61,257

$55,929 $ 3,356 $ 1,972 customers Transactions with other 2,708 20 1,155 (3,883)

(115) 2,567 operating segments 1,418 986 278 Segment EBIT 1,383 Depreciation, depletion and 597 632 154 (1, 174) (a) 47,281 amortization expense 31,459 12,455 4,541 Total assets 656 Investments in equity method 242 - 414 1,832 subsidiaries 640 844 348 Gross property additions (a) Reconciling adjustments for Total Assets: (1,558) 404 Eliminate intercompany balances (20)

Corporate assets (1,174) other 2000 Revenues from:

External unaffiliated $ 3, 174 $2,095 $36,706 customers $ 31,437 Transactions with other 2 750 (2,478) 2,059 1,726 358 (322) operating segments 1,006 11 017 Segment EBIT (3) 1,250 Depreciation, depletion and 559 506 188 53,350 (866) (b) amortization expense 32,216 14, 876 7,124 Total assets 724 864 Investments in equity method 140 1,773 subsidiaries 493 961 319 Gross property additions (955)

(b) Reconciling adjustments for Total Assets: 93 Eliminate intercompany balances -(4)

Corporate assets other (866) 1999 Revenues from:

External unaffiliated $3,068 $2,134 $24,745 customers $ 19,543

- 573 (1,611)

Transactions with other 1,038 (82) 2,464 operating segments 1,146 1,008 392 Segment EBIT (3) 1,212 depletion and 565 454 196 Depreciation, (335) (c) 35,693 amortization expense 18,408 11,224 6,396 Total assets 889

- 755 Investments in equity method 134 1,680 subsidiaries 390 815 475 Gross property additions (345)

(c) Reconciling adjustments for Total Assets: 10 Eliminate intercompany balances other (335)

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[I Geographically our business is transacted primarily in the United States and the United Kingdom with other holdings in a small number of other counties. Results of operations by geographic area are as follows:

Geographic Areas Revenues uni ted AEP United States Kingdom Other Foreign Consolidated (in millions) 2001 $53,650 $7,201 2000 $406 $61,257 34,300 2,011 395 36,706 1999 22,694 1,705 346 24,745 Long-Lived Assets United AEP united States Kingdom Other Foreign consolidated (in millions) 2001 $21,726 $2,158 2000 $659 $24,543 20,463 1,220 710 22,393 1999 19,958 1,124 783 21,865 Of the registrant operating company subsidiaries, all of the registrant subsidiaries except AEGCo have two business segments. The segment results for each of these subsidiaries are reported in the table below. AEGCo has one segment, a wholesale generation business. AEGCo's results of operations are reported in AEGCo's financial statements.

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Twelve Months Ended Twelve Months Ended December 31. 2000 December 31, 2001 Revenues Revenues From From External Segment External Segment EBIT Customers Total Assets Customers EBIT Total Assets (in thousands)

(in thousands)

Wholesale Segment $154,525 $3,708,252

$164,844 $2,855,337 $4,512,390 273,650 3,182,192 APCo $6,404,394 1,870,689 303,926 2,977,504 2,848,545 2,767,569 235,860 2,488,513 CPL 1,987,756 3,816,644 232,372 4,003,805 CSPCo 3,231,065 (146,297) 117,396 3,318,919 4,489,215 1,055,521 22,379 766,605 I&M 585,847 1,528,212 4,935 4,007,722 KPCo 4,524,513 289,084 240,128 3,156,115 5,709,689 1,184,895 54,072 1,011,432 OPCo 52,086 907,165 1,939,372 1,337,776 27,055 1,302,398 PSO 82,409 1,223,334 2,241,444 583,358 13,910 466,499 SWEPCo 7,930 396,147 895,235 WTU

$574,918 $191,560 $2,925,472 Energy Delivery Segment $213,733 $2,252,601

$595,036 478,814 136,069 2,285,492 APCo 109,587 2,138,482 473,182 398,046 81,896 1,399,789 CPL 130,503 1,118,112 483,219 311,019 126,241 1,807,233 CSPCo 1,498,089 314,410 111,206 742,459 I&M 121,346 49,770 54,033 567,396 131,183 467,587 138,418 2,234,835 KPCo 118,261 1,759,952 552,713 85,524 1,126,901 OPCo 1,010,732 245,124 261,877 79,787 PSO 344,950 129,842 1,355,558 107,197 1,273,266 333,004 50,201 620,912 SWEPCo 527,273 176,204 169,036 33,226 WTU Registrant Subsidiaries

$5,087,308 $346,085 $6,633,724 Company Total $378,577 $5,107,938

$6,999,430 2,349,503 409,719 5,467,684 APCo 5,115,986 3,321,727 413,513 3,165,615 317,756 3,888,302 CPL 362,875 3,105,868 4,299,863 3,542,084 (20,056) 5,811,038 CSPCo 228,602 4,817,008 4,803,625 1,176,867 72,149 1,509,064 I&M 58,968 1,153,243 1,659,395 4,992,100 427,502 6,242,557 KPCo 358,389 4,916,067 6,262,402 1,430,019 139,596 2,138,333 OPCo 131,873 1,917,897 2,201,249 1,682,726 156,897 2,657,956 PSO 2,496,600 2,574,448 189,606 1,087,411 SWEPCo 759,562 64,111 41,156 923,420 1,064,271 WTU L-41

[II Twelve Months Ended December 31 1999 Revenues From External Customers Segment EBIT Total Assets (in thousands)

Wholesale Segment APCo $3,404,987 $116,907 $2,434,110 CPL 1,032,808 267,165 2,821,449 CSPCo 2,242,459 214,312 1,798,394 A&M 2,609,307 (18,055) 3,153,344 KPCo 789,008 18,569 501,212 OPCo 3,763,711 278,415 3,002,768 PSO 493,063 56,521 721,195 SWEPCo 672,158 95,385 1,032,045 WTU 270,800 25,008 369,457 Energy Delivery Segment APCo $565,660 $208,460 $1,920,290 CPL 449,667 133,172 2,026,401 CSPCo 389,280 93,962 1,011,596 A&M 310,880 142,973 1,423,352 KPCo 129,113 51,556 485,426 OPCo 460,182 149,906 1,674,441 PSO 256,327 74,430 803,531 SWEPCo 299,369 83,143 1,074,170 WTU 174,909 46,216 491,748 Registrant Subsidiaries Company Total APCo $3,970,647 $325,367 $4,354,400 CPL 1,482,475 400,337 4,847,850 CSPCo 2,631,739 308,274 2,809,990 I&M 2,920,187 124,918 4,576,696 KPCo 918,121 70,125 986,638 OPCo 4,196,893 428,321 4,677,209 PSO 749,390 130,951 1,524,726 SWEPCo 971,527 178,528 2,106,215 WTU 445,709 71,224 861,205 L-42

13. Risk Management, Financial management controls.

Instruments and Derivatives:

AEP is exposed to risk from changes in the market prices of coal and natural gas used to Risk Management generate electricity where generation is no longer regulated or where existing fuel We are subject to market risks in our day to clauses are suspended or frozen. The day operations. Our risk policies have been protection afforded by fuel clause recovery reviewed with the Board of Directors, mechanisms has either been eliminated by approved by a Risk Management Committee the implementation of customer choice in and administered by Chief Risk Officer. The Ohio (effective January 1, 2001) and in the Risk Management Committee establishes risk ERCOT area of Texas (effective January 1, limits, approves risk policies, assigns 2002) or frozen by settlement agreements in responsibilities regarding the oversight and Indiana, Michigan and West Virginia. To the management of risk and monitors risk levels. extent all fuel supply for the generating units This committee receives daily, weekly, and in these states are not under fixed price long monthly reports regarding compliance with term contracts, AEP is subject to market price policies, limits and procedures. The risk. AEP continues to be protected against committee meets monthly and consists of the market price changes by active fuel clauses in Chief Risk Officer, Chief Credit Officer, V.P. Oklahoma, Arkansas, Louisiana, Kentucky, Market Risk Oversight, and senior financial Virginia and the SPP area of Texas.

and operating managers.

We employ fair value hedges, cash flow The risks and related strategies that hedges and swaps to mitigate changes in management can employ are: interest rates or fair values on short and long Risk Description Strategv term debt when management deems it Price Risk Volatility in Trading and necessary. We do not hedge all interest rate commodity prices hedging Changes in risk.

Interest Rate Risk Interest rates Hedging Foreign Exchange Fluctuations in We employ cash flow forward hedge contracts foreign currency Risk rates Hedging to lock-in prices on transactions denominated Credit Risk Non-performance in foreign currencies where deemed on contracts with Guarantees, counterparties Collateral necessary. International subsidiaries use currency swaps to hedge exchange rate We employ physical forward purchase and fluctuations in debt transactions denominated sale contracts, exchange futures and options, in foreign currencies. We do not hedge all over-the-counter options, swaps, and other foreign currency exposure.

derivative contracts to offset price risk where appropriate. However, we engage in trading Our open trading contracts, including of electricity, gas and to a lesser degree coal, structured transactions, are marked-to-market oil, natural gas liquids, and emission daily using the price model and price curve(s) allowances and as a result the Company is corresponding to the instrument. Forwards, subject to price risk. This risk is managed by futures and swaps are generally valued by the management of the trading operations, subtracting the contract price from the market the Company's Chief Risk Officer and the price and then multiplying the difference by Risk Management Committee. If the risk from the contract volume and adjusting for net trading activities exceeds certain pre present value and other impacts. Significant determined limits, the positions are modified estimates in valuing such contracts include or hedged to reduce the risk to the limits forward price curves, volumes, seasonality, unless specifically approved by the Risk weather, and other factors.

Management Committee. Although we do not hedge all commodity price exposure, manage Forwards and swaps (which are a series of ment makes informed risk taking decisions forwards) are valued based on forward price supported by the above described risk curves which represent a series of projected L-43

II prices at which transactions can be executed others. For example, peak electricity is a in the market. The forward price curve more liquid product than off-peak electricity.

includes the market's expectations for prices Henry Hub gas trades in monthly blocks for up of a delivered commodity at that future date. to 36 months and after that only trades in The forward price curve is developed from the seasonal or calendar blocks. In the near market bid price, which is the highest price term, forward price curves for gas have a which traders are willing to pay for a contract, seasonal shape. They are based on market and the ask or offer price, which is the lowest quotes beyond that.

price traders are willing to receive for selling a contract. For all these factors, the curve used for valuation is the mid-point. At times bids or Options contracts, consisting primarily of offers may not be available due to market options on forwards and spread options, are events, volatility, constraints, long-dated part valued using models, which are variations on of the curve, etc. When this occurs, the Black-Scholes option models. The market Company uses its best judgment to estimate related inputs are the interest rate curve, the the curve values until actual values are underlying commodity forward price curve, available again. The value used will be based and the implied volatility curve. Option prices on various factors such as last trade price, or volatilities may be quoted in the market. recent price trend, product spreads, location Significant estimates in valuing these spreads (including transportation costs), cross contracts include forward price curves, commodity spreads (e.g., heat rate volumes, and other volatilities. conversion of gas to power), time spreads, cost of carry (e.g., cost of gas storage),

Futures and futures options traded on futures marginal production cost, cost of new entrant exchanges (primarily oil and gas on Nymex) capacity, and alternative fuel costs. Also, an are valued at the exchange price. energy commodity contract's price volatility generally increases as it approaches the Market prices utilized in valuing all forward delivery month. Spot price volatility (e.g., daily contracts, OTC options, swaps and structured or hourly prices) can cause contract values to transactions represent mid-market price, change substantially as open positions settle which is the average of the bid and ask against spot prices. When a portion of a prices. These bids and offers come from curve has been estimated for a period of time brokers, on-line exchanges such as the and market changes occur, assumptions are Intercontinental Exchange, and directly from updated to align the company's curve to the other counterparties. These prices exist for market.

delivery periods and locations being traded or quoted and vary by period, location and The fair values determined are reduced by commodity. For periods and locations that reserves to adjust for credit risk and liquidity are not liquid and for which external risk. Credit risk is based on credit ratings of information is not readily available, counterparties and represents the risk that the management uses the best information counterparty to the contract will fail to perform available to develop bid and ask prices and or fail to pay amounts due AEP. Liquidity risk forward curves. represents the risk that imperfections in the market will cause the price to be less than or Electricity and gas markets in particular have more than what the price should be based primary trading hubs or delivery points/regions purely on supply and demand. The liquidity and less liquid secondary delivery points. In reserve essentially reserves half of the North American natural gas markets, the difference between bids and offers for each primary delivery points are generally traded open position, such that the wider the bid from Henry Hub, Louisiana. The less liquid offer spread (indicating lower liquidity), the gas or power trading points may trade as a greater the reserve.

spread (based on transportation costs, constraints, etc.) from the nearest liquid We also mark to market derivatives that are trading hub. Also, some commodities trade not trading contracts in accordance with more often and therefore are more liquid than generally accepted accounting principles.

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There may be unique models for these transactions, but the curves the company Futures, Forward and inputs into the models are the same forward Counterparty Swap curves, which are described above. Credit Quality: Contracts Options Total Year Ending December 31, 2001 (in millions)

We have developed independent controls to AAA/Exchanges $ 147 $ 147 evaluate the reasonableness of our valuation AA 140 4 144 A 304 7 311 models and curves. However, there are BBB 932 34 966 inherent risks related to the underlying Below Investment assumptions in models used to fair value Grade 56 23 79 open long-term trading contracts. Therefore, Total U$68 4 there could be a significant favorable or adverse effect on future results of operations The counterparty credit quality and exposure and cash flows if market prices at settlement for the registrant subsidiaries is generally differ from the price models and curves. consistent with that of AEP.

AEP limits credit risk by extending unsecured We enter into transactions for electricity and credit to entities based on internal ratings. natural gas as part of wholesale trading AEP uses Moody's Investor Service, Standard operations. Electric and gas transactions are and Poor's and qualitative and quantitative executed over-the-counter with counterparties data to independently assess the financial or through brokers. Gas transactions are also health of counterparties on an ongoing basis. executed through brokerage accounts with This data, in conjunction with the ratings brokers who are registered with the information, is used to determine appropriate Commodity Futures Trading Commission.

risk parameters. AEP also requires cash Brokers and counterparties require cash or deposits, letters of credit and parental/affiliate cash related instruments to be deposited on guarantees as security from certain below these transactions as margin against open investment grade counterparties in our normal positions. The combined margin deposits at course of business. December 31, 2001 and 2000 was $55 million and $95 million. These magin accounts are We trade electricity and gas contracts with restricted and therefore are not included in numerous counterparties. Since our open cash and cash equivalents on the Balance energy trading contracts are valued based on Sheet. AEP and its subsidiaries can be changes in market prices of the related subject to further margin requirements should commodities, our exposures change daily. We related commodity prices change.

believe that our credit and market exposures The margin deposits at December 31, 2001 with any one counterparty is not material to financial condition at December 31, 2001. At for the registrants were:

December 31, 2001 less than 5% of the counterparties were below investment grade (in thousands) as expressed in terms of Net Mark to Market APCO $2,832 Assets. Net Mark to Market Assets CPL 299 represents the aggregate difference (either CSP 1,736 positive or negative) between the forward I&M 1,879 KPCo 698 market price for the remaining term of the OPCO 2,862 contract and the contractual price. The PSO 247 following table approximates counterparty SWEPCO 299 credit quality and exposure for AEP. WTU 99 L-45

It III FinancialDerivatives and Hedging Most of the derivatives identified in the trans ition adjustment were designated as cash flow In the first quarter of 2001, AEP adopted hedges and relate to foreign operations.

SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as The amour ts of net revenue margins (sales amended by SFAS 137 and SFAS 138. SFAS less purchases) in 2001, 2000, and 1999 for 133 requires that entities recognize all trading activities were:

derivatives including fair value hedges as 2001 2000 1999 either assets or liabilities and measure such (in millions) derivatives at fair value. Changes in the fair Net Revenue value of derivatives are included in earnings Margin $609 $435 $91 unless designated as a cash flow hedge. This practice is commonly referred to as mark-to The amounts of revenues recorded in 2001, market accounting. Changes in the fair value 2000 and 1999 for the registrant subsidiaries of derivatives that are designated as effective were:

2001 2000 1999 cash flow hedges are included in other (in thousands) comprehensive income. AEP recorded a APCo $78,521 $72,649 $28,970 favorable transition adjustment to accumu CPL 15,711 3,385 CSPCo 51,765 48,142 14,800 lated other comprehensive income of $27 I&M 36,089 58,909 16,147 million at January 1, 2001 in connection with KPCo 12,466 23,417 5,563 OPCo 65,118 73,474 24,389 the adoption of SFAS 133. Derivatives PSO (2,483) 9,268 included in the transition adjustment are SWEPCo WTU 7,897 (1,491) 6,404 1,821 interest rate swaps, foreign currency swaps and commodity swaps, options and futures.

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The fair value of open trading contracts that are marked-to-market are based on management's best estimates using over-the-counter quotations and exchange prices for short-term open trading contracts, and Company developed price curves for open long-term trading contracts. The fair values of trading contracts at December 31 are:

2001 2000 Fair Fair value value (in millions) (in millions)

Tradinq Assets Electric Futures and Options-NYMEX $ 11 $

Physicals 3,588 8,791 Options - OTC 182 215 swaps 117 164 Total Trading Assets Gas Futures and Options-NYMEX $ 143 $

Physicals 238 454 options - OTC 978 1,266 swaps 5,646 6,185 Total Trading Assets Trading Liabilities Electric Futures and Options-NYMEX $ - $

Physicals (3,382) (8,852)

Options - OTC (101) (133) swaps (126) (144)

Total Trading Liabilities )

Gas Futures and options NYMEX $ (92) $ (81)

Physicals (80) (419)

Options - OTC (1,076) (934)

Swaps (5,598) (6,449)

Total Trading Liabilities *)*4=i) 2001 2000 Fair Fair value value (in thousands) (in thousands)

APCo Trading Assets Electric Futures and options-NYMEX (net) $ - $

Physicals 801,306 2,234,522 Options - OTC 46,649 59,814 Swaps 34,578 51,470 Trading Liabilities Electric Futures and Options-NYMEX (net) $ -$

Physicals (748,016) (2,258,596) options - OTC (21,895) (35,955)

Swaps (36,921) (44,855)

KPCo Trading Assets Electric Futures and Options-NYMEX (net) $ - $

Physicals 197,545 530,828 Options - OTC 11,503 14,207 Swaps 8,529 12,227 L-47

Trading Liabilities Electric Futures and Options-NYMEX (net) $ $

Physicals (190,389) (536,512)

Options - OTC (5,372) (8,521)

Swaps (9,106) (10,656) 2001 2000 Fai r Fai r Value (in (n l ue thousands)

(in thousands)

I&M Trading Assets Electric Futures and Options-NYMEX (net) $ $

Physicals 560,393 1,349,950 Options - OTC 31,397 36,139 Swaps 22,950 31,095 Trading Liabilities Electric Futures and Options-NYMEX (net) $ $

Physicals (513,026) (1,371,793)

Options - OTC (15,864) (25,807)

Swaps (24,505) (27,099)

OPCo Trading Assets Electric Futures and Options-NYMEX (net) $

Physicals 668,142 1,776,259 Options - OTC 38,108 46,731 Swaps 29,730 41,788 Trading Liabilities Electric Futures and Options-NYMEX (net)

Physicals (619,756) (1,792,417)

Options - OTC (18,227) (29,350)

Swaps (32,551) (37,398)

CSPCo Trading Assets Electric Futures and Options-NYMEX (net) $

Physicals 491,290 1,192,203 options - OTC 28,612 31,918 Swaps 21,211 27,461 Trading Liabilities Electric Futures and Options-NYMEX (net) $

Physicals (456,613) (1,204,948) options - OTC (13,403) (19,220)

Swaps (22,648) (23,932)

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2001 2000 Fair Fair value Value (in thousands) (in thousands)

CPL Trading Assets Electric Physicals $285,481 $ 542,626 Trading Liabilities Electric Physicals (281,624) (550,817)

PSO Trading Assets Electric Physicals 217,415 431,186 Trading Liabilities Electric Physicals (214,981) (437,694)

SWEPCo Trading Assets Electric Physicals 249,531 516,385 Trading Liabilities Electric Physicals (246,631) (524,180)

WTU Trading Assets Electric Physicals 84,784 171,597 Trading Liabilities Electric Physicals (83,869) (174,187)

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The FASB's Derivatives Implementation Cash flows from both derivative instruments Group (DIG) Issued guidance, effective in the and trading activities are included in net cash third quarter of 2001, regarding the imple flows from operating activities.

mentation of SFAS 133 for certain fuel supply contracts with volume optionality and Certain derivatives may be designated for electricity capacity contracts. The guidance accounting purposes as a hedge of either the concluded that fuel supply contracts with fair value of an asset, liability or firm volumetric optionality cannot qualify for a commitment, or a hedge of the variability of normal purchase or sale exclusion from mark cash flows related to a variable-priced asset, to-market accounting and provided guidance liability, commitment or forecasted trans for determining when electricity capacity con action. To qualify for hedge accounting, the racts can qualify as normal purchases or relationship between the hedging instrument sales. and the hedged item must be documented to include the risk management objective and Predominantly all of AEP's contracts for coal, strategy for use of the hedge instrument. At gas and electricity, which are recorded on a the inception of the hedge and on an ongoing settlement basis, do not meet the criteria of a basis, the effectiveness of the hedge is financial derivative instrument and qualify as assessed as to whether the hedge is highly normal purchases or sales. As a result they effective in offsetting changes in fair value or are exempt from the DIG guidance described cash flows of the item being hedged.

above and have not been marked-to-market. Changes in the fair value that result from  !::!i!!

Beginning July 1, 2001, the effective date of ineffectiveness of a hedge under SFAS 133 the DIG guidance, certain of AEP's fuel are recognized currently in earnings through supply contracts with volumetric optionality mark-to-market accounting. Changes in the that qualify as financial derivative instruments fair value of effective cash flow hedges are are marked to market with any gain or loss reported in accumulated other comprehensive recognized in the income statement. The income if documented at inception. Gains effect of initially adopting the DIG guidance at and losses from cash flow hedges in other July 1, 2001, a favorable earnings mark-to comprehensive income are reclassified to market effect of $18 million, net of tax, is earnings in the accounting periods in which reported as a cumulative effect of an the variability of cash flows of the hedged accounting change on the income statement. items affect earnings.

Cash flow hedges included in Accumulated Other Comprehensive income on the Balance Sheet at December 31, 2001 are:

Hedging Assets Hedging Liabilities other Comprehensive Income (Loss) After Tax (in millions)

Electric $16 $ (6) $ 4 Interest Rate (21) (12)

Foreign Currency 5 SLf)

The following table represents the activity in Other Comprehensive Income related to the effect of adopting SFAS 133 for derivative contracts that qualify as cash flow hedges at December 31, 2001:

(in millions)

AEP consolidated Transition Adjustment, January 1, 2001 changes in fair value $ 27 Reclasses from ocI to net income (1)

Accumulated oci derivative loss, December 31, (29) 2001 L-50

(in thousands)

APCO $

Transition Adjustment, January 1, 2001 Effective portion of changes in fair value (340)

Reclasses from OCI to net income Accumulated OCI derivative gain, December 31, 2001 KPCo $ (557)

Transition Adjustment, January 1, 2001 (2,348)

Effective portion of changes in fair value 1,002 Reclasses from OCT to net income Accumulated oci derivative gain, December 31, 2001 I&M $ (317)

Transition Adjustment, January 1, 2001 (5,368)

Effective portion of changes in fair value 1,850 Reclasses from oCI to net income Accumulated oci derivative gain, December 31, 2001 OPCO $(9 Transition Adjustment, January 1, 2001 (196)

Effective portion of changes in fair value Reclasses from OCI to net income Accumulated oCI derivative gain, December 31, 2001 Approximately $15 million of net losses from FINANCIAL INSTRUMENTS cash flow hedges in accumulated other comprehensive income at December 31, 2001 Market Valuation of Non-Derivative Financial are expected to be reclassified to net income Instrument in the next twelve months as the items being hedged settle. The actual amounts The book values of cash and cash reclassified from accumulated other equivalents, accounts receivable, short-term comprehensive income to net income can debt and accounts payable approximate fair differ as a result of market price changes. value because of the short-term maturity of The maximum term for which the exposure to these instruments. The book value of the pre the variability of future cash flows is being April 1983 spent nuclear fuel disposal liability hedged is 5 years. approximates the best estimate of its fair value.

We have derivatives under SFAS 133 that do not employ hedge accounting and are not The fair values of long-term debt and energy trading. The derivative's mark to preferred stock subject to mandatory market value at December 31, 2001 was a redemption are based on quoted market

$22.7 million asset and a $13.1 million liability. prices for the same or similar issues and the current dividend or interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange. The book values and fair values of significant financial instruments for AEP and its registrant subsidiaries December 31, 2001 and 2000 are summarized in the following tables.

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2001 2000 Book value Fair value Book value Fair value (in millions) (in millions)

AEP consolidated Long -term Debt $12,053 $12,002 $10,754 $10,812 Preferred Stock 95 93 100 98 Trust Preferred Securities 321 320 334 326 (in thousands) (in thousands)

AEGCo Long-term Debt $45,000 $45,268 $45,000 $45,000 APCo Long-term Debt $1,556,559 $1,439,531 $1,6Q5,818 $1,601,313 Preferred stock 10,860 10,860 0,860 10,725 CPL Long-term Debt $1,253,768 $1,278,644 $1,454,559 $1,463,690 Trust Preferred Securities 136,250 135,760 148,500 147,431 CSPCo Long -term Debt $791,848 $802,194 $899,615 $908,620 Preferred Stock 10,000 10,100 15,000 14,892 I&M Long-term Debt $1,652,082 $1,672,392 $1,388,939 $1,377,230 Preferred stock 64,945 62,795 64,945 63,941 KPCo Long-term Debt $346,093 $350,233 $330,880 $335,408 OPCo Long-term Debt $1,203,841 $1,227,880 $1,195,493 .$1,176,367 Preferred stock 8,850 8,837 8,850 8,780 PSO Long-term Debt $451,129 $462,903 $470,822 $476,964 Trust Preferred Securities 75,000 74,730 75,000 72,180 SWEPCo Long-term Debt $645,283 $656,998 $645,963 $651,586 Trust Preferred Securities 110,000 109,780 110,000 106,700 WTU Long-term Debt $255,967 $266,846 $255,843 $261,315 L-52

Other Financial Instruments - Nuclear Trust 14. Income Taxes:

Funds Recorded at Market Value - The trust investments which are classified as held for The details of AEP's consolidated income sale for decommissioning and SNF disposal, taxes as reported are as follows:

reported in other assets, are recorded at Year Ended December 31, market value in accordance with SFAS 115. 2001 2000 1999 (in millions)

At December 31, 2001 and 2000 the fair Federal:

values of the trust investments were $933 Current $406 $ 766 $308 Deferred 60 (237) 129 million and $873 million, respectively, and had Total 466 529 437 a cost basis of $839 million and $768 million, State:

25 current 61 5o respectively. The change in market value in Deferred 35 (9_)

41 25 2001, 2000, and 1999 was a net unrealized Total 96 International:

holding loss of $11 million, and net unrealized Current 1 6 3 6 21 17 holding gain of $6 million, and $18 million, Deferred Total 7 27 20 respectively.

Total Income Tax as Reported s5fia $-59Z _482 The details of the registrant subsidiaries income taxes as reported are as follows:

AEGCo APCO CPL CSPCo I&M Year Ended December 31, 2001 (in thousands)

Charged (Credited) to operating Expenses (net):

Current $ 9,126 $ 71,623 $190,671 $ 88,013 $ 107,286 (6,224) 27,198 (72,568) 14,923 (45,785)

Deferred (7,377)

Deferred Investment Tax credits (3,.237) (5,207) (3,899) 2,1-902 95,584 54,124 Total 112,896 99,037 charged (credited) to Nonoperating Income (net): (398)

(13,803)

(56) (19,165) (10,590)

Current Deferred 21,832 17,885 16,580 (1,528) (947)

Deferred Investment Tax Credits (3.,414) (159) 3,923 5,043 Total (3,470) 1,139 Total Income Tax as Reported L*) $96_ 2 KPCo oPco PSO SWEPCo WTU Year Ended December 31, 2001 (in thousands)

Charged (credited) to operating Expenses (net):

Current $ 7,726 $(62,298) $ 53,030 $ 77,965 $ 19,424 Deferred 2,812 166,166 (16,726) (31,396) (11,891)

(1,180) (2,495) (1.791) (4,453) (1,271)

Deferred Investment Tax Credits 9,358 42,116 6,262 Total 101,373 34,51 charged (credited) to Nonoperating Income (net):

Current (2,725) (21,600) 352 542 (691)

Deferred 3,481 20,014 Deferred Investment Tax credits (794) 684 (2,380) 352 542 ( )

Total Total Income Tax as Reported AEGCO APCO CPL CSPCO I&M Year Ended December 31, 2000 (in thousands) charged (credited) to Operating Expenses (net):

Current $ 8,746 $129,165 $ 89,403 $120,494 $ 134,796 Deferred (5,842) 3,838 16,263 (7,746) (126,748)

(2,947) (5,207) (3,379) (7,524)

Deferred Investment Tax credits 2,904 130,056 109,369 Total 100,459 524 Charged (credited) to Nonoperating Income (net): 2,950 Current (44) 327 (5,073) 3,777 Deferred 4,764 3,683 1,569 (3.396) (1,968) -(103) (330)

Deferred Investment Tax Credits (5_07)

Total L3__6)

(3,440) 3,123 7,357 4,189 Total Income Tax as Reported L-53

KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands) charged (credited) to operating Expenses (net):

Current $17,878 $259,608 $11,597 $16,073 $ 6,774 Deferred 2,521 (70,263) 25,453 14,653 9,401 Deferred Investment Tax Credits (1,187) (1,824) R35_,427259' -(4.482) (1,271)

Total 19,212 187,521 26,244 14,904 Charged (credited) to Nonoperating Income (net): (222)

Current (50) 15,426 (1,306) (1,476)

Deferred 1,244 4,307 (1,237)

Deferred Investment Tax credits (65) (1,575)

Total 1,129 18,158 (1.36 (1.476) (1,459)

Total Income Tax as Reported $13.44 5 AEGCo APCo CPL CSPco I&M Year Ended December 31, 1999 (in thousands)

Charged (credited) to operating Expenses (net):

Current $ 7,713 $69,522 $ 89,112 $79,410 $(67,368)

Deferred (5,282) 8,981 19,620 9,737 85,345 Deferred Investment Tax Credits (2.659) (7,547) 2l431 75,844 01207) (3,432) 10,430 Total Charged (Credited) to Nonoperating Income (net):

Current (146) (1,548) (5,604) (3,122) 1,529 Deferred - 4,052 318 744 382 Deferred Investment Tax Credits (3,448) (2.313) (562) (605)

Total (3)) 19 (2940) 1,3 6 Total Income Taxes as Reported KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands)

Charged (credited) to Operating Expenses (net):

Current $14,897 $135,540 $20,777 $ 60,169 $ 3,328 Deferred 2,239 4,205 14,521 (17,347) 12,026 Deferred Investment Tax Credits (1.193) (4,565)

(1,825) 38,257 (1275)

Total 15,943 137,920 14,079 charged (credited) to Nonoperating Income (net):

Current (424) (3,256) (2,215) (4,826) 858 Deferred 357 (539) - -

Deferred Investment Tax Credits (99) (1,633)

Total (166) (5,428) 428215) 858 Total Income Taxes as Reported The following is a reconciliation for AEP Consolidated of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of income taxes reported.

Year Ended Decgmber 31, 2001 2000 1999 (in millions)

Net Income $ 971 $267 $ 972 Extraordinary Items (net of income tax $20 million in 2001,

$44 million in 2000 and $8 million in 1999) 50 35 14 cumulative Effect of Accounting change (net of income tax $2 million in 2001) (18)

Preferred stock Dividends 10 11 19 Income Before Preferred Stock Dividends of Subsidiaries 1,013 313 1,005 Income Taxes 569 597 482 Pre-Tax Income M9G0 Income Tax on Pre-Tax Income at Statutory Rate (35%) $554 $319 $520 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreci ati on 48 77 71 Corporate Owned Life Insurance 4 247 2 Investment Tax Credits (net) (37) (36) (38)

Tax Effects of Foreign Operations (27) (29) (54)

Merger Transaction Costs 49 State Income Taxes 62 26 16 Other (35) (56) (35)

Total Income Taxes as Reported S2AU Effective Income Tax Rate L-o L-54

Shown below is a reconciliation for each AEP registrant subsidiary of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported.

AEGCO APCo CPL CSPCo I&M Year Ended December 31, 2001 (in thousands)

Net Income (Loss) $7,875 $161,818 $182,278 $161,876 $ 75,788 Extraordinary (Gains) Loss Income Tax Benefit Income Taxes (6) 96,723 112,498 102,960 59,167 Pre-Tax Income (Loss) $258.541 $ 2 $294.60 Income Tax on Pre-Tax Income (LOSS) at Statutory Rate (35%) $ 2,557 $ 90,490 $104,050 $103,201 $ 47,234 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 230 2,977 8,477 2,757 21,224 Corporate owned Life Insurance 450 - 544 (148)

Nuclear Fuel Disposal Costs (3,292)

Allowance for Funds used During Construction (1,078) (1,606)

Rockport Plant unit 2 Investment Tax Credit 374 Removal Costs Investment Tax Credits (net) (3,414) (4,765) (5,207) (4,058) (8,324)

State Income Taxes 1,050 9,613 9,652 5,727 6,137 other (2,042) (4,474) (5,211) (2,058)

Total Income Taxes as Reported Effective Income Tax Rate 3*-.9% 3_4_1.%1 KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2001 (i n thousand ds)

Net Income $21,565 $147,445 $ 57,759 $ 89,367 $12,310 Extraordinary Loss 18,348 Income Tax Benefit 98,993 42,658 5,*571 Income Taxes 10,042 34,865 Pre-Tax Income Income Tax on Pre-Tax Income at Statutory Rate (35%) $11,062 $ 92,675 $32,418 $ 46,209 $ 6,259 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 1,581 7,972 - 1,463 corporate owned Life Insurance 334 1,852 - -

Nuclear Fuel Disposal costs Allowance for Funds used During Construction Rockport Plant unit 2 Investment Tax credit Removal Costs (420) (1,791) (4,453)

Investment Tax Credits (net) (1,252) (3,289) (1,271)

State Income Taxes 318 9,752 5,137 5,451 1,283 (9,969) (899) (4,549) (2,163)

Other (1,581) S$ 42_658 Total Income Taxes as Reported 31L2%

Effective Income Tax Rate 31.8% 3$ 8A9 31--% 32_3%

AEGCo APCo CPL CSPCo I&M Year Ended December 31, 2000 (in thousands)

Net Income (Loss) $7,984 $ 73,844 $189,567 $ 94,966 $(132,032)

Extraordinary (Gains) Loss (1,066) 39,384 Income Tax Benefit (7,872) - (14,148)

Income Taxes (536) 133 179 95,386 116,726 4,713 Pre-Tax Income (Loss)

Income Tax on Pre-Tax Income (LOss) at Statutory Rate (35%) $ 2,607 $ 69,330 $99,733 $ 82,925 $(44,561)

Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 452 7,606 7,556 10,529 20,378 Corporate Owned Life Insurance 54,824 - 29,259 42,587 Nuclear Fuel Disposal Costs - - (3,957)

Allowance for Funds used During Construction (1,070) - - (2,211)

Rockport Plant Unit 2 Investment Tax Credit 374 Removal Costs (1,197)

Investment Tax Credits (net) (3,396) (4,915) (5,207) (3,482) (7,854)

State Income Taxes 784 9,950 2,296 89 6,004 Other 3687) (2,419) (8_992,) (2,594) (5,673)

Total Income Taxes as Reported $133,179 N-4.

A9u-Yz6 Effective Income Tax Rate Lz-2% 11-50A L-55

KPCo OPCo PSO SWEPCo WTU Year Ended December 31, 2000 (in thousands)

Net Income $20,763 $ 83,737 $ 66,663 $72,672 $27,450 Extraordinary Loss 40,157 Income Tax Benefit (21,281) 20,342 205,679 Income Taxes 33 9S3 24,768 13,445 Pre-Tax Income 530702440 Income Tax on Pre-Tax Income at Statutory Rate (35%) $14,387 $107,903 $35,216 $ 34,104 $14,313 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 1,827 27,577 - 1,204 Corporate owned Life Insurance 5,149 84,453 Nuclear Fuel Disposal costs Allowance for Funds used During Construction Rockport Plant unit 2 Investment Tax credit Removal Costs (42 20)

Investment Tax Credits (net) (1,2552) (3,398) (1,791) ( 4,482) (1,271)

State Income Taxes 1,5997 (1,988) 3,037 1,650

[6,504)

Other (94 ) (8,868) (801)

Total Income Taxes as Reported Effective Income Tax Rate 49, 25.476 AECGCo APCo CPL (i n thousands) CSPCO I&M Year Ended December 31, 1999 Net Income $ 6, .195 $120,492 $182,201 $150,27CS$32,776 Extraordinary Loss 8,488 Income Tax Benefit (2,971) 98,239 Income Taxes .163) 76,035 82,775 11,736 Pre-Tax Income $285=957z S233,045 Income Tax on Pre-Tax $ 1, $ 81,5( i6 Income at Statutory Rate (35%) 762 $ 68,785 $100,085 $15,580 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 446 12,593 7,981 8,846 19,966 Corporate owned Life Insurance - 594 Nuclear Fuel Disposal Costs - (3,347)

Allowance for Funds used During Construction (1,069) - (2,174)

Rockport Plant unit 2 Investment Tax Credit 374 Removal Costs (3,220)

Investment Tax Credits (net) (3,448) (4,972) (5,207) (3,991 5ý t) (8,152)

State Income Taxes 467 3,305 6,965 8 (4,635)

Other 305 (456) (11,585) (3,70. 1) (6,096)

Total Income Taxes as Reported Effective Income Tax Rate N. M. 3*Z 35-f3% M6A%

KPCo oPco PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands)

Net Income $25,430 $212,157 $61,508 $ 83,194 $26,406 Extraordinary Loss 4,632 8,402 Income Tax Benefit 15,777 (1,621) (2,941) 132,492 31.292 Income Taxes 33,431 14,937 Pre-Tax Income $14 3 $1,62 $3924800 Income Tax on Pre-Tax Income

$14,423 $120,628 $ 32,480 at Statutory Rate (35%) $ 41,873 $16,382 Increase (Decrease) in Income Tax Resulting from the Following Items:

Depreciation 1,843 17,517 1,120 Corporate Owned Life Insurance 198 Removal costs (420)

Investment Tax Credits (net) (1,292) (3,458) (1,791) (4,565) (1,275)

State Income Taxes 1,809 1,090 3,054 2,924 other (586_) (3.483) (2,451) (6.801) (1_290)

Total Income Taxes as Reported $132,492 r 33..43 Effective Income Tax Rate 3S_ýY 33__% 32I0%

L-56

The following tables show the elements of the net deferred tax liability and the significant temporary differences for AEP Consolidated and each registrant subsidiary:

December 31, 2001 2000 (in millions)

Deferred Tax Assets $ 1,248 $ 1,248 Deferred Tax Liabilities (6,071) (6,123)

Net Deferred Tax Liabilities Property Related Temporary Differences $(3,963) $(3,935)

Amounts Due From Customers For Future (252)

Federal Income Taxes (245)

Deferred State Income Taxes (160) (251)

Transition Regulatory Assets (268) (163)

Regulatory Assets Designated for securitization (332) (332)

Al other (net) 145 58

$(4.875)

Net Deferred Tax Liabilities AEGCo APCc CPL CsPco I&M December 31, 2001 (in thousands)

$ 75,856 $ 162,334 $ 130,863 $ 74,767 $ 332,225 Deferred Tax Assets (732,756)

Deferred Tax Liabilities (103,831) (865,909) (1,294,658) (518,489)

Net Deferred Tax Liabilities Property Related Temporary Differences $ (70,581) $(530,298) $ (808,922) $(323,139) $(306,151)

Amounts Due From Customers For Future Federal Income Taxes 9,292 (55,206) (70,174) (9,839) (46,756)

Deferred State Income Taxes (3,822) (56,747) - (8,968) (38,015)

Translation Regulatory Assets (34,783) - (78,298)

Net Deferred Gain on sale and Leaseback-Rockport Plant Unit 2 40,816 - - 27,157 Accrued Nuclear Decommissioning Expense - - - 43,707 Deferred Fuel and Purchased Power - - - (26,270)

Deferred cook Plant Restart Costs - - - (28,000)

Nuclear Fuel - - - (16,062)

Regulatory Assets Designated for Securitization - (332,198) -

All Other (net) (3.680) (26,541) 47,499 (23,478) (10,141)

$ 2Z7) $(0,7) ILI-Ik*3_Zu)$4372)$4051 Net Deferred Tax Liabilities KPCo OPCo PSO SWEPCo WTU December 31, 2001 (in thousands)

Deferred Tax Assets $ 30,927 $ 135,938 $ 59,421 $ 56,189 $ 22,888 Deferred Tax Liabilities (199,231) (933,827) (356.298) (425,970) (167,937)

Net Deferred Tax Liabilities Property Related Temporary Differences $(118,147) $(595,974) $(320,900) $(362,884) $(149,309)

Amounts Due From Customers For Future Federal Income Taxes (20,215) (61,130) 10,199 (6,441) 4,757 Deferred state Income Taxes (25,267) (18,440)

Translation Regulatory Assets - (154,947)

Deferred Fuel and Purchased Power - 20,323 Provision for Mine shutdown Costs 18,365 All Other (net) (4.675) (6,086) 13,824 (456) (497)

Net Deferred Tax Liabilities

$ 4) $7789 AEGCo APCo CPL CSPCo I&M December 31, 2000 (in thousands)

Deferred Tax Assets $ 81,480 $ 178,487 $ 67,184 $ 88,198 $ 342,900 Deferred Tax Liabilities (114,408) (860.961) (1309,981) (510.957) (830,845)

$(487=945)

Net Deferred Tax Liabilities Property Related Temporary Differences $ (78,113) $(510,950) $ (773,454) $(343,045) $(324,198)

Amounts Due From Customers For Future Federal Income Taxes 10,317 (55,085) (72,426) (11,142) (55,218)

Deferred state Income Taxes (5,478) (86,351) (69,982)

Translation Regulatory Asset - (40,554) - (68,817)

Net Deferred Gain on sale and Leaseback-Rockport Plant unit 2 42,766 - 28,454

- 34,702 Accrued Nuclear Decommissioning Expense Deferred Fuel and Purchased Power - (39,395)

- (42,000)

Deferred cook Plant Restart Costs - (28,319)

Nuclear Fuel Regulatory Assets Designated for Securitization - (332,198)

All other (net) (2,420) 10,466 (64,719) 245 8.011

• (2.5) $(i48794)

Net Deferred Tax Liabilities L$3292) $(682.474) L)

L-57

KPCo OPCo PSO SWEPCo WTU December 31, 2000 (in thousands)

Deferred Tax Assets $ 32,807 $ 330,878 $ 60,010 $ 47,615 $ 16,604 Deferred Tax Liabilities (198,742) (952,819) .372,070) (446,819) (173,642)

Net Deferred Tax Liabilities $ ) I2 4) 1_(LP) _1_(3 9$Z ) l 0)

Property Related Temporary Differences $(116,109) $(586,039) $(313,248) $(375,427) $(150,264)

Amounts Due From Customers For Future Federal Income Taxes (19,680) (57,759) 11,082 (6,015) 4,723 Deferred state Income Taxes (29,695) (14,282) (36,487)

Translation Regulatory Asset - (53,149) - -

Deferred Fuel and Purchased Power - (116,224) - -

Provision for Mine Shutdown costs - 63,995 - -

Postretirement Benefits - 93,306 - -

All other (net) (451) 48,211 26 593 (17,762) (11,497)

Net Deferred Tax Liabilities $(6(59)

(41) ) * ) _

We have settled with the IRS all issues from the audits of our consolidated federal income tax returns for the years prior to 1991. We have received Revenue Agent's Reports from the IRS for the years 1991 through 1996, and have filed protests contesting certain proposed adjustments.

Returns for the years 1997 through 2000 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

COLI Litigation - 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 returns related to its COLI program. AEP had filed suit to resolve the IRS' assertion that interest deductions for AEP's COLI program should not be allowed. In 1998 and 1999 the Company paid the disputed taxes and interest 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 matter.

As a result of the U.S. District Court's decision to deny the COLI interest deductions, net income was reduced by $319 million in 2000. The Company has filed an appeal of the U.S. District Court's decision with the U.S. Court of Appeals for the 6 th Circuit.

The earnings reductions for affected registrant subsidiaries are as follows:

(in millions)

APCo $ 82 CSPCo 41 I&M 66 KPCO 8 oPco 118 The Company has not recognized a deferred tax liability for temporary differences related to investments in certain subsidiaries located outside of the United States because such differences are deemed to be essentially permanent in duration. If the investments were sold, the temporary differences may become taxable resulting in a tax liability of approximately $66 million.

The Company joins in the filing of a consolidated federal income tax return with its affiliated companies in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determing their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

L-58

15. Basic and Diluted Earnings Per Share:

The calculation of basic and diluted earnings per share is based on the amounts of income and weighted average shares shown in the table below.

2001 2000 1999 (in millions - except per share amounts)

Income:

Income before Extraordinary Item and cumulative Effect $1,003 $302 $986 Extraordinary Losses (net of tax) (50) (35) (14) cumulative Effect of Accounting change (net of tax) 18 Net Income $ 9Z1 SZ1Z $-97U weighted Average shares:

Average common shares outstanding 322 322 321 Assumed conversion of stock options (see Note 11)

Diluted average comon shares outstanding 323 322 321 Basic and Diluted Earnings Per share:

Income before Extraordinary item and cumulative effect $3.11 $ 0.94 $ 3.07 .

Extraordinary losses (net of tax) (0.16) (0.11) (0.04) cumulative effect of accounting change (net of tax) 0.06 -

S-3-01, 5-0--U 5-A-U The assumed conversion of stock options does not affect income for purposes of calculating diluted earnings per share. Basic and diluted EPS are the same in 2001, 2000 and 1999 since the effect on weighted average shares outstanding is little or nil.

16. Supplementary Information:

Year Ended December 31, 2001 2000 1999 (in millions)

AEP consolidated Purchased Power ohio valley Electric Corporation (44.2% owned by AEP system) $127 $86 $64 cash was paid for:

Interest (net of capitalized amounts) $972 $842 $979 Income Taxes $569 $449 $270 Noncash Investing and Financing Activities:

Acquisitions under capital Leases $17 $118 $80 Assumption of Liabilities Related to Acquisitions $171 Exchange of communication Investment for Common stock $5 L-59

The amounts of power purchased by the registrant subsidiaries from Ohio Valley Electric Corporation, which is 44.2% owned by the AEP System, for the years ended December 31, 2001, 2000, and 1999 were:

APCo CSPCo I&M OPCo (in thousands)

Year Ended December 31, 2001 $45,542 $12,626 $20,723 $47,757 Year Ended December 31, 2000 30,998 8,706 15,204 31,134 Year Ended December 31, 1999 21,774 6,006 10,227 25,623

17. Power, Distribution and Distribution Projects Communications Projects:

We own a 44% equity interest in Vale, a Power Projects Brazilian electric operating company which was purchased for a total of $149 million. On AEP owns interests of 50% or less in December 1, 2001 we converted a $66 million domestic unregulated power plants with a note receivable and accrued interest into a 20% equity Interest in Caiua (Brazilian electric capacity of 1,483 MW located in Colorado, operating company), a subsidiary of Vale.

Florida and Texas. In addition to the Vale and Caiua have experienced losses from domestic projects, AEP has equity interests in operations and our investment has been international power plants totaling 1,788 MW.

affected by the devaluation of the Brazilian AEP has other projects in various stages of Real. The cumulative equity share of development. operating and foreign currency translation losses through December 31, 2001 is Investments in power projects that are 50% or approximately $46 million and $54 million, less owned are accounted for by the equity respectively, net of tax. The cumulative equity method and reported in investments in power, share of operating and foreign currency distribution and communications projects on translation losses through December 31, 2000 the balance sheet. At December 31, 2001, six is approximately $33 million and $49 million, domestic and four international power projects respectively, net of tax. Both investments are are accounted for under the equity method. covered byla put option, which, if exercised, The six domestic projects are combined cycle requires our partners in Vale to purchase our gas turbines that provide steam to a host Vale and Caiua shares at a minimum price commercial customer and are considered equal to the U.S. dollar equivalent of the Qualifying Facilities (QF) under the Public original purchase price. As a result, Utilities Regulatory Policies Act of 1978. The management has concluded that the four international power plants are classified investment carrying amount should not be as Foreign Utility Companies (FUCO) under reduced below the put option value unless it is the Energy Policies Act of 1992. All of the deemed to be an other than temporary power projects accounted for under the equity impairment and our partners in Vale are method have unrelated third-party partners. deemed unable to fulfill their responsibilities under the put option. Management has All of the above power projects have project evaluated through an independent third-party, level financing, which is non-recourse to AEP. the ability of its Vale partners to fulfill their responsibilities under the put option AEP or AEP subsidiaries have guaranteed agreement and has concluded that our

$30 million of domestic partnership partners should be able to fulfill their obligations for performance under power responsibilities.

purchase agreements and for debt service reserves in lieu of cash deposits. AEP has Management believes that the decline in the guaranteed $94 million of additional equity for value of its investment in Vale in US dollars is two projects. not other than temporary. As a result and pursuant to the put option agreement, these losses have not been applied to reduce the carrying values of the Vale and Caiua investment} As a result we will not recognize L-60

any future earnings from Vale and Caiua until AEP has a 50% ownership interest in a joint the operating losses are recovered. Should venture, American Fiber Touch, LLC (AFT),

the impairment of our investment become that is constructing a fiber optic line from other than temporary due to our partners in Missouri to Illinois. AEP accounts for AFT Vale becoming unable to fulfill their under the equity method of accounting and responsibilities, it would have an adverse has recorded its pro rata share of the losses effect on future results of operations. of AFT during the start up phase. AEP has recently decided to withdraw from this venture Management will continue to monitor both the and fully provided for the expected loss in status of the losses and of its partners ability exiting the joint venture in December 2001.

to fulfill its obligations under the put.

18. Leases:

Communication Projects Leases of property, plant and equipment are AEP provides telecommunication services to for periods up to 35 years and require businesses and telecommunication payments of related property taxes, companies through a broadband fiber optic maintenance and operating costs. The network. AEP's investment in the network majority of the leases have purchase or include fiber optic cable, electronic equipment renewal options and will be renewed or and colocation facilities that house the replaced by other leases.

equipment. The investments are both owned and leased with a majority of the leased Lease rentals for both operating and capital investments being indefeasible rights of use leases are generally charged to operating (IRUs) for fiber optic cable for periods ranging expenses in accordance with rate-making from 20 to 30 years. Telecommunication treatment for regulated operations. Capital revenue is accounted for using the accrual leases for non-regulated property are method of accounting as service is rendered accounted for as if the assets were owned over the contractual term. Lease obligations and financed. The components of rental related to these investment are included in the costs are as follows:

lease payment amounts disclosed in the lease note.

AEP has a 46.25% ownership interest in a joint venture, AFN networks, LLC (AFN),

which is engaged in the operation and construction of a fiber optic network. AFN both owns and leases fiber optic cable and electronic equipment with the majority of leases being IRUs of fiber optic cable for periods ranging from 20 to 25 years. AEP accounts for AFN under the equity method of accounting and has recorded its pro rata share of the losses during the start up phase.

AEP has a credit agreement with AFN that enables AFN to borrow up to $91.5 million at market interest rates to finance their construction and operations. The amount available to AFN at December 31, 2001 is $61 million.

L-61

AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 2001 (in thousands)

Lease Payments on operating Leases $296,000 $76,262 $ 6,142 $5,948 $ 7,063 $104,574 $1,191 Amortization of Capital Leases 85,000 281 12,099 7,206 17,933 2,740 Interest on Capital Leases 22,000 55 3_,789 2,396 4,424 808 Total Lease Rental Costs OPCo PSO SWEPCo WTU Year Ended December 31, 2001 (in thousands)

Lease Payments on operating Leases $63,913 $4,010 $2,277 $1,534 Amortization of Capital Leases 14,443 Interest on Capital Leases 5,818 Total Lease Rental Costs AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 2000 (in thousands)

Lease Payments on Operating Leases $237,000 $73,858 $ 7,128 $ $ 7,683 $ 81,446 $1,978 Amortization of Capital Leases 121,000 281 13,900 7,776 26,341 3,931 Interest on Capital Leases 38,000 55 3,930 2_,690 10,908 1,054 Total Lease Rental costs $396000Q OPCo PSO SWEPCo will Year Ended December 31, 2000 (in thousands)

Lease Payments on operating Leases $51,981 Amortization of Capital Leases 37,280 Interest on Capital Leases 9 584 Total Lease Rental Costs AEP AEGCo APCo CPL CSPCo I&M KPCo Year Ended December 31, 1999 (in thousands)

Lease Payments on operating Leases $247,000 $74,269 $ 5,647 $ 5,687 $ 81,611 $ 199 Amortization of Capital Leases 97,000 364 13,749 7,427 11,320 4,299 Interest on Capital Leases 35.000 64 4,2_*67 2,720 9,338 1,162 Total Lease Rental Costs $379.000 $102,269 $.6 OPCo PSO SWEPCo WTU Year Ended December 31, 1999 (in thousands)

Lease Payments on operating Leases $ 60,026 $ - $ - $

Amortization of Capital Leases 35,622 - -

Interest on Capital Leases 9,552 -

Total Lease Rental Costs Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:

AEP AEGCo APCo CSPco I&M KPCo OPCo Year Ended December 31, 2001 (in thousands)

Property, Plant and Equipment under capital Leases Production $ 40,000 $1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477 Distribution 177,000 14,593 other:

Mining Assets and Other 722,000 129 82,292 $54._999 86,267 17,658 114,944 Total Property, Plant and Equipment 939,000 2,112 85,004 61,379 105,686 18,796 137,421 Accumulated Amortization 256,000 1,801 38,745 26,044 43,768 9,213 57,429 Net Property, Plant and Equipment under Capital Leases 8.00$ 311 U4=,

$3,3 5 obligations under capital Leases:

Noncurrent Liability $356,000 $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261 Liability Due within one Year 95,000 235 12,357 7,835 10,840 2,841 16,405 Total obligations under Capital Leases $45 $ 61.93 3 $ 80 666 L-62

AEP AEGCo APCo CSPCo I&M KPCo OPCo Year Ended December 31, 2000 (in thousands)

Property, Plant and Equipment under capital Leases Production $ 42,000 $2,017 $ 6,276 $ 2 $ 7,023 $ 1,730 $ 24,709 151,000 14,595 Distribution other:

Nuclear Fuel (net of amortization) 90,000 89,872 177 93 437 $68 352 97,383 22,072 200,308 Mining Assets and Other 619,000 Total Property, Plant 902,000 99,713 68,354 208,873 23,802 225,017 and Equipment 2,194 288,000 36,553 25,422 45,700 9,618 108,436 Accumulated Amortization 1,603 Net Property, Plant and Equipment under capital Leases $614,000 $ 591 IEI-ILQ 142-9-U obligations under capital Leases:

Noncurrent Liability $419,000 $ 358 $50,350 $35,199 $ 62,325 $11,091 $ 83,866 233 12,810 7,733 100,848 3,093 32,715 Liability Due within one Year 195,000 Total obligations under ILU-I

$ 59Z capital Leases $614,000 Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.

CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under capital leases.

Future minimum lease payments consisted of the following at December 31, 2001:

AEP AEGCO APCo CSPCo I&M KPCo OPCO Capital (in thousands)

$ 96,000 $217 $13,718 $ 8,932 $11,759 $ 3,093 $ 18,516 2002 10,028 2,441 17,521 2003 81,000 132 11,625 7,284 63,000 20 9,371 6,111 7,947 1,824 14,701 2004 6,282 1,449 11,520 2005 49,000 6 6,440 5,248 42,000 1 4,690 3,903 5,335 891 10,305 2006 Later Years 397,000 11,400 17,882 1,548 28,948 Total Future Minimum 376 42,878 59,233 11,246 101,511 Lease Payments 728,000 53,457 7,991 (2,700) 1,663 20,845 Less Estimated Interest Element 277,000 65 Estimated Present value of Future Minimum Lease Payments 53-U AEP AEGCo APCO CPL CSPCo I&M KPCo (in thousands)

Noncancellable Operal tina Leases $ 717 2002 $ 286,000 $ 73,854 $ 3,193 $ 5,948 $ 2,104 $ 82,627 691 271,000 73,854 3,108 5,948 1,991 79,923 2003 1,623 77,104 571 2004 255,000 73,854 2,402 5,948 245,000 73,854 2,155 5,948 1,308 75,736 544 2005 5,948 1,279 75,595 398 2006 243,000 73,854 1,887 4,563 1,186,678 1,842 Later Years 2,671,000 1,181,664 Total Future Minimum Lease Payments oPCo PSO SWEPCo WTU (in thousands)

Noncancellable operating Leases $1,534 2002 $ 62,945 $4,010 $ 2,277 62,914 4,010 2,277 1,534 2003 2,277 1,534 2004 63,323 4,010 2005 62,836 4,010 2,277 1,534 2006 63,242 4,010 2,277 1,534 Later Years 244,069 Total Future Minimum Lease Payments L-63

Operating leases include lease agreements with The registrant subsidiaries incurred interest special purpose entities related to Rockport Plant expense for amounts borrowed from the AEP Unit 2 and the Gavin Plant's flue gas money pool as follows:

desulfurization system (Gavin Scrubbers). The Rockport Plant lease resulted from a sale and Year Ended December 31, 2001 2000 1999 leaseback transaction in 1989. The gain from the (in millions)

AEGCo 0.8 sale was deferred and is being amortized over the APCo 9.8 term of the lease which expires in 2022. The CPL 11.4 16.9 14.1 CSPCo 5.0 1.4 Gavin Scrubber lease expires in 2009. AEP has I&M 13.1 0.8 KPCo 2.3 no ownership interest in the special purpose OPCo 14.6 9.2 entities and does not guarantee their debt. The PSO 6.3 7.5 2.0 SWEPCo 3.4 4.2 special purpose entities are not consolidated in WTU 3.1 2.7 4.7 0.6 AEP's financial statements in accordance with applicable accounting standards. As a result, Interest income earned from amounts advanced neither the leased plant and equipment nor the to the AEP money pool by the registrant debt of the special purpose entities is included on subsidiaries were:

AEP's balance sheet. The future lease payment Year Ended December 31.

obligations to the special purpose entities are 2001 2000 1999 (in milTions) included in the above table of future minimum APCo 1.7 -

lease payments under noncancellable operating CPL 0.1 CSPCo 0.8 1.1 leases. T&M 1.6 9.0 KPCo 0.1 1.8 OPCo 8.6 3.4

19. Lines of Credit and Sale of Receivables: SWEPCo 0.1 - 0.1 WTU - 0.2 The AEP System uses short-term debt, primarily commercial paper, to meet fluctuations in working Outstanding short-term debt for AEP capital requirements and other interim capital Consolidated consisted of:

needs. AEP has established a money pool to December 31, coordinate short-term borrowings for certain 2001 2000 (in millions) subsidiaries, including AEGCo, APCo, CPL, Balance Outstanding:

CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and Notes Payable $ 207 $ 193 commercial paper WTU and also incurs borrowings outside the Total 4,140 money pool for other subsidiaries. As of AEP Credit, which does not participate in the December 31, 2001, AEP had revolving credit money pool, issued commercial paper on a stand facilities totaling $3.5 billion to support its alone basis up to May 30, 2001. AEP Credit commercial paper program. At December 31, 2001, AEP had $3.2 billion outstanding in short provides low-cost financing for utilities, including both AEP's electric utility operating companies term borrowings of which $2.9 billion was under and non-affiliates, through factoring receivables these credit facilities. The maximum amount of which arise primarily from the sale and delivery of such short-term borrowings outstanding during electricity in the ordinary course of business. In the year, which had a weighted average interest January 2002 AEP Credit stopped purchasing rate for the year of 4.95%, was $3.3 billion during accounts receivable from non-affiliated electric March 2001. utility companies.

On May 30, 2001, AEP Credit stopped issuing commercial paper and allowed its $2 billion unsecured revolving credit facility to mature.

Funding needs were replaced on May 30, 2001 by a $1.5 billion variable funding note. The variable funding note was, in turn, replaced on December 31, 2001 when AEP Credit entered into a sale of receivables agreement with a group of banks and commercial paper conduits.

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Under the sale of receivables agreement, AEP receivables agreement declines to $1.1 billion on Credit sells an interest in the receivables it January 31, 2002 and to $900 million on February acquired from its clients to the commercial paper 28, 2002, where it remains until the expiration of conduits and banks and receives cash. This the commitment on May 30, 2002. AEP Credit transaction constitutes a sale of receivables in maintains a retained interest in the receivables accordance with SFAS 140 allowing the sold and this interest is pledged as collateral for receivables to be taken off of AEP Credit's the collection of the receivables sold. The fair balance sheet. AEP has no ownership interest in value of the retained interest is based on book the commercial paper conduits and does not value due to the short-term nature of the accounts consolidate these entities in accordance with receivable less an allowance for anticipated GAAP. We continue to service the receivables. uncollectible accounts.

At December 31, 2001, the banks had a $1.2 billion commitment under the sale of receivables agreement to purchase receivables from AEP Credit of which $1 billion was outstanding. Of the

$1 billion of receivables sold, $485 million respresented non-affiliate receivables. The commitment available under the sale of At year ended December 31, 2001, AEP Credit had:

$ Millions Accounts Receivable sold 1,045 Accounts Receivable Retained Interest Less uncol Iecti bl e Accounts and Pledged as collateral 143 Deferred Revenue from Servicing Accounts Receivab1e 5 Loss on sale of Accounts Receivable 8 Initial variable Discount Rate 2.28%

Retained Interest if 10%

Adverse change in Uncollectible Accounts 142 Retained Interest if 20%

Adverse change in Uncoll ecti bl e Accounts 140 Historical loss and delinquency amount for the Customer Accounts Receivable managed portfolio for the year ended December 31, 2001.

Face value December 31. 2001

$ Millions Customer Accounts Receivable Retained $ 626 Miscellaneous Accounts Receivable Retained 1,365 Allowance for uncollectible Accounts Retained (109)

Total Net Balance sheet Accounts Receivable 1,882 Customer Accounts Receivable Securitized (Affiliate) 560 Customer Accounts Receivable securitized (Non-Affiliate) 485 Total Accounts Receivable managed Net uncollectible Accounts written off for the Year Ended December 31, 2001 87 L-65

Customer Accounts receivable retained and The fees paid by the registrant subsidiaries to securitized for the domestic electric operating AEP Credit for factoring customer accounts companies are managed by AEP Credit as a receivable were:

pool between affiliate and non-affiliate Year Ended December 31, accounts receivable. Miscellaneous Account 2001 2000 1999 (in millions)

Receivable have been fully retained and not securitized. APCO $ 5.2 CPL 14.7 15.7 14.7 CSPCo 15.2 10.8 I&M 8.5 6.8 Delinquent Customer Accounts Receivable KPCO 2.7 1.9 over 60 days old at December 31, 2001: OPCo 12.8 8.4 PSO 9.6 8.3 6.5 SWEPCO 7.4 9.2 9.3 (in millions) WTU 3.8 4.0 3.5 Affiliated $ 92 Non-Affiliated 17 Total Sio~

Under the factoring arrangement the registrant subsidiaries (excluding AEGCo) sell without recourse certain of their customer accounts receivable and accrued utility revenue balances to AEP Credit and are charged a fee based on AEP Credit financing costs, uncollectible accounts experience for each company's receivables and administrative costs. The costs of factoring customer accounts receivable is reported as an operating expense. At December 31, 2001 the amount of factored accounts receivable and accrued utility revenues for each registrant subsidiary was as follows:

Company (in millions)

APCO $ 61 CPL 89 CSPCo 106

AG, I&M 95 KPCo 26 OPCO 100 Pso 43 SWEPCo 47 WTU 23 L-66

20. Unaudited Quarterly Financial Information:

The unaudited quarterly financial information for AEP Consolidated follows:

2001 Quarterly Periods Ended M.arch 31 June 30 Sept. 30 Dec. 31 (In Millions - Except Per share Amounts) operating Revenues $ 14,165 $14,528 $18,385 $14,179 operating Income 601 672 862 260 Income Before Extraordi nary Items and cumulative Effect 266 280 403 54 Net Income 266 232 421 52 Earnings per share Before Extraordinary Items And cumulative Effect* 0.83 0.87 1.25 0.17 Earnings per Share** 0.83 0.72 1.31 0.16 2000 Quarterly Periods Ended March 31 June 30 Sept. 30 Dec. 31 (In Millions - Except Per Share Amounts)

Operating Revenues $6,117 $8,137 $11,608 $10,844 operating Income 428 308 873 395 Income (Loss) Before Extraordinary Items and Cumulative Effect 140 (18) 403 (223)

Net Income (Loss) 140 (9) 359 (223)

Earnings (LOSS) per share Before Extraordinary Items and Cumulative Effect 0.43 (0.06) 1.25 (0.68)

Earnings (LOSS) per share 0.43 (0.03) 1.11 (0.68)

• Amounts for 2001 do not add to $3.11 earnings per share before extraordinary items and cumulative effect due to rounding.

• • Amounts for 2001 do not add to $3.01 earnings per share due to rounding.

The unaudited quarterly financial information for each AEP registrant subsidiary follows:

Quarterly Periods Ended AEGCo APCo CPL CsPco I&M (in thousands) 2001 March 31 Operating Revenues $60,507 $1,974,127 $603,412 $1,125,573 $1,291,538 Operating Income 1,807 88,152 64,152 51,932 52,698 Income (Loss) Before Extraordinary Items 1,980 61,787 35,031 37,671 32,363 Net Income (Loss) 1,980 61,787 35,031 37,671 32,363 June 30 Operating Revenues $52,217 $1,849,304 $648,499 $1,109,095 $1,259,874 Operating Income 1,882 59,362 82,351 62,894 47,340 Income (LOSS) Before Extraordinary Items 2,063 36,419 52,518 47,418 27,374 Net Income (LOSS) 2,063 36,419 52,518 21,011 27,374 seotember 30 Operating Revenues $57,417 $2,017,159 $1,235,941 $1,297,704 $1,402,178 Operating Income 1,615 60,381 112,598 76,920 44,509 Income Before Extraordinary Items 2,051 30,317 83,702 65,318 25,064 Net Income 2,051 30,317 83,702 65,318 25,064 December 31 Operating Revenues $57,407 $1,158,840 $833,875 $767,491 $850,035 Operating Income 1,673 67,091 36,630 60,431 15,158 Income (LOSS) Before Extraordinary Items 1,781 33,295 13,536 41,493 (9,013)

Net Income (Loss) 1,781 33,295 11,027 37,876 (9,013)

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Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU (in thousands) 2001 March 31 Operating Revenues $459,157 $1,699,665 $356,139 $425,689 $195,006 Operating Income 12,604 64,756 8,340 33,986 5,392 Income Before Extraordinary Items 7,075 53,397 (1,560) 19,869 891 Net Income 7,075 53,397 (1,560) 19,869 891 June 30 Operating Revenues $439,131 $1,627,177 $398,194 $434,795 $192,839 Operating Income 8,364 47,067 21,942 32,649 12,428 Income Before Extraordinary Items 2,742 32,094 11,921 17,784 6,133 Net Income 2,742 10,579 11,921 17,784 6,133 September 30 operating Revenues $485,820 $1,819,792 $910,428 $1,028,742 $429,623 Operating Income 12,587 69,668 59,914 60,194 17,745 Income Before Extraordinary Items 5,312 51,378 51,069 46,357 14,067 Net Income 5,312 51,378 51,069 46,357 14,067 December 31 Operating Revenues $275,287 $1,115,768 $536,488 $685,222 $246,803 Operating Income 14,123 59,219 6,793 19,378 (2,175)

Income (Loss) Before Extraordinary Items 6,436 28,924 (3,670) 5,357 (8,781)

Net Income (LOSS) 6,436 32,091 (3,670) 5,357 (8,781)

Quarterly Periods Ended AEGCo APCo CPL CSPCo I&M (in thousands) 2000 March 31 operating Revenues $56,866 $1,021,678 $316,328 $633,305 $708,150 Operating Income 2,395 78,246 38,650 44,124 (15,251)

Income Before Extraordinary Items 2,445 47,664 8,139 27,471 (36,553)

Net Income 2,445 47,664 8,139 27,471 (36,553)

June 30 Operating Revenues $56,928 $1,460,774 $437,911 $928,332 $1,011,706 operating Income 1,746 58,208 95,717 50,798 (18,599)

Income Before Extraordinary Items 1,653 30,240 67,553 35,335 (39,181)

Net Income 1,653 39,178 67,553 35,335 (39,181) september 30 operating Revenues $55,658 $1,538,340 $795,794 $960,837 $1,060,654 Operating Income 2,209 65,750 120,653 83,562 36,056 Income Before Extraordinary Items 1,972 36,112 89,974 65,542 15,190 Net Income 1,972 36,112 89,974 40,306 15,190 December 31 Operating Revenues $59,064 $1,066,516 $799,470 $643,141 $ 761,574 Operating Income 2,074 (1,050) 52,078 17,393 (36,908)

Income (Loss) Before Extraordinary Items 1,914 (49,110) 23,901 (8,146) (71,488)

Net Income (LOSS) 1,914 (49,110) 23,901 (8,146) (71,488)

Quarterly Periods Ended KPCo OPCo PSO SWEPCo WTU (in thousands) 2000 March 31 Operating Revenues $231,454 $1,047,837 $161,329 $207,756 $ 93,335 operating Income 15,557 65,113 10,860 22,731 9,781 Income Before Extraordinary Items 8,052 46,216 1,165 7,663 3,833 Net Income 8,052 46,216 1,165 7,663 3,833 June 30 operating Revenues $342,660 $1,436,330 $209,172 $272,409 $130,742 Operating Income 9,456 79,968 24,502 33,296 16,938 Income Before Extraordinary Items 2,449 58,233 14,700 18,786 8,070 Net Income 2,449 58,233 14,700 18,786 8,070 September 30 Operating Revenues $359,296 $1,484,663 $555,236 $573,891 $249,330 Operating Income 13,790 96,652 56,437 61,312 16,565 Income Before Extraordinary Items 6,761 77,061 54,329 47,537 10,670 Net Income 6,761 58,185 54,329 47,537 10,670 December 31 Operating Revenues $243,457 $1,023,270 $504,282 $628,670 $286,155 Operating Income 10,935 (14,906) 4,870 10,939 9,057 Income (Loss) Before Extraordinary Items 3,501 (78,897) (3,531) (1,314) 4,877 Net Income (LOSS) 3,501 (78,897) (3,531) (1,314) 4,877 L-68

primarily due to the Earnings for the fourth quarter 2001 increased $275 million from the prior year disallowing interest deductions from effect of charges recorded in 2000 from a ruling by the IRS Fourth quarter 2001 AEP's COLI program and a write down for the proposed sale of Yorkshire.

of Unit 1 of the earnings were also favorably impacted by the return to service in December 2000 fee from a non Cook Plant after an extended outage and the receipt of a contract cancellation affiliated factoring client of AEP Credit.

21. Trust Preferred Securities:

trusts of The following Trust Preferred Securities issued by the wholly-owned statutory business 31, 2000. They CPL, PSO and SWEPCo were outstanding at December 31, 2001 and December Redeemable are classified on the balance sheets as Certain Subsidiaries Obligated, Mandatorily Holding Solely Junior Subordinated Debentures of Such Preferred Securities of Subsidiary Trusts mature on April 30, 2037. CPL reacquired Subsidiaries. The Junior Subordinated Debentures 490,000 and 60,000 trust preferred units during 2001 and 2000, respectively.

units issued/ Description of outstanding underlying of Registrant Security At 12/31/01 Amount at December 31. Debentures Business Trust 2000 2001 (in millions) 8.00%, series A 5,450,000 $136 $149 CPL, $141 million, CPL capital 1 a5 8.00%, Series A 8.00%, series A 3,000,000 75 75 PSO, $77 million, Pso Capital I 8.00%, series A Series A 4,400,000 110 110 SWEPCO, $113 million, SWEPCo capital I 7.875%, series A

$800 ____ 7.875%,

assets of the Each of the business trusts is treated as a subsidiary of its parent company. The only by their parent company as specified business trusts are the subordinated debentures issued debentures, each of the parent above. In addition to the obligations under their subordinated a full and unconditional companies has also agreed to a security obligation which represents guarantee of its capital trust obligation.

22. Minority Interest in Finance Subsidiary:

and sold In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated subsidiary, to an unconsolidated special purpose entity a non-controlling preferred member interest in Caddis the Caddis formation agreements, the (Steelhead) for $750 million. Under the provisions of return equal to an adjusted floating preferred member interest receives quarterly a preferred funding reference rate (4.413% at December 31, 2001). The $750 million received replaces interim used to acquire Houston Pipe Line Company in June 2001.

of preferred The preferred interest is supported by natural gas pipeline assets and $321.4 million interest in stock issued by an AEP subsidiary to the AEP affiliate which has the managing member of Caddis. Such preferred stock is convertible into common stock of AEP upon the occurrence supported by such preferred stock if the certain events. AEP can elect not to have the transaction to redeem the preferred interest were reduced by $225 million. In addition, Caddis has the right preferred member interest at any time.

The initial period of the preferred interest is through August 2006. At the end of the initial period, to new Caddis will either reset the preferred rate, re-market the preferred member interests return, or investors, redeem the preferred member interests, in whole or in part including accrued liquidate in accordance with the provisions of applicable agreements.

of Steelhead has the right to terminate the transaction and liquidate Caddis upon the occurrence certain events including a default in the payment of the preferred return. Steelhead's rights include:

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forcing a liquidation of Caddis and acting as the liquidator, and requiring the conversion of the

$321.4 million of AEP subsidiary preferred stock into AEP common stock. If the preferred member interest exercised its rights to liquidate under these conditions, then AEP would evaluate whether to refinance at that time or relinquish the assets that support the preferred member interest.

Liquidation of the preferred interest or of Caddis could impact AEP's liquidity.

Caddis and the AEP subsidiary which acts as its managing member are each a limited liability company, with a separate existence and identity from its members, and the assets of each are separate and legally distinct from AEP. The results of operations, cash flows and financial position of Caddis and such managing member are consolidated with AqP for financial reporting purposes.

The preferred member interest and payments of the preferred return are reported on AEP's income statement and balance sheet as Minority Interest in Finance Subsidiary.

23. Jointly Owned Electric Utility Plant:

CPL, CSPCo, PSO, SWEPCo and WTU have generating units that are jointly owned with unaffiliated companies. Each of the participating companies is obligated to pay its share of the costs of any such jointly owned facilities in the same proportion as its ownership interest. Each AEP registrant subsidiary's proportionate share of the operating costs associated with such facilities is included in its statements of income and the investments are reflected in its balance sheets under utility plant as follows:

Compn' Share Deoe'mbe 31.

2001 2000 Percent Utility Construction Utility Construction of Plant work Plant work Ownership in service in Proqr ss in service in Progress (in thoulý (in thousands)

CPL:

Oklaunion Generating Station (Unit No. 1) 7.8 $ 37,728 $ 318 $ 37,236 South Texas Project Generating $ 395 Station (Units No. 1 and 2) 25.2 2.360.452 .1

.M -

373575 19,292 CSP:

W.C. Beckjord Generating Station (Unit No. 6) 12.5 $ 14,292 $ 884 $ 14,108 Conesville Generating Station $ 178 (Unit No. 4) 43.5 81,697 494 80,103 J.M. Stuart Generating Station 261 26.0 193,760 27,758 191,875 10,086 Wm. H. Zimmer Generating Station 25.4 704,951 Transmission 2,634 706,549 61,820 5,265 (a) 61.476 91 451 PSO:

oklaunion Generating Station (Unit No. 1) 15.6 $ 82,646 $88,a8 S R17 SWEPCo:

Dolet Hills Generating Station (Unit No. 1) 40.2 $ 234,747 $ 675 $ 231,442 Flint creek Generating Station $ 1,984 (Unit No. 1) 50.0 83,953 213 82,899 Pirkey Generating Station 852 (Unit No. 1) 85.9 439,.430 437,069 435

$ 51430 WTU:

Oklaunion Generating Station (Unit No. 1) 54.7 $9.295 3 ,277.624 (a) varying percentages of ownership.

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The accumulated depreciation with respect to majority of these transactions represent each AEP registrant subsidiary's share of physical forward contracts in the AEP jointly owned facilities is shown below: System's traditional marketing area and are typically settled by entering into offsetting December 31, contracts. The regulated physical forward 2001 2000 contracts are recorded on a gross basis in the (in thousands) month when the contract settles.

CPL $863,130 $834,722 CSPCO 410,756 389,558 Pso 35,653 33,669 In addition, the AEP Power Pool enters into SWEPCO 392,728 367,558 transactions for the purchase and sale of WTU 100,430 98,045 electricity options, futures and swaps, and for the forward purchase and sale of electricity

24. Related Party Transactions outside of the AEP System's traditional marketing area.

AEP System Power Pool CPL, PSO, SWEPCo, WTU and AEP Service APCo, CSPCo, I&M, KPCo and OPCo are Corporation are parties to a Restated and parties to the Interconnection Agreement, Amended Operating Agreement originally dated July 6, 1951, as amended (the dated as of January 1, 1997 (CSW Operating Interconnection Agreement), defining how Agreement). The CSW Operating Agreement they share the costs and benefits associated requires the operating companies of the west with their generating plants. This sharing is zone to maintain specified annual planning based upon each company's "member-load reserve margins and requires the subsidiaries ratio," which is calculated monthly on the that have capacity in excess of the required basis of each company's maximum peak margins to make such capacity available for demand in relation to the sum of the sale to other AEP subsidiaries as capacity maximum peak demands of all five commitments. The CSW Operating companies during the preceding 12 months. Agreement also delegates to AEP Service In addition, since 1995, APCo, CSPCo, I&M, Corporation the authority to coordinate the KPCo and OPCo have been parties to the acquisition, disposition, planning, design and AEP System Interim Allowance Agreement construction of generating units and to which provides, among other things, for the supervise the operation and maintenance of transfer of S02 Allowances associated with a central control center. The CSW Operating transactions under the Interconnection Agreement has been accepted for filing and Agreement. As part of AEP's restructuring allowed to become effective by FERC.

settlement agreement filed with FERC, CSPCo and OPCo would no longer be parties AEP's System Integration Agreement to the Interconnection agreement and certain provides for the integration and coordination other modifications to its terms would also be of AEP's east and west zone operating made. subsidiaries, joint dispatch of generation within the AEP System, and the distribution, Power marketing and trading transactions between the two operating zones, of costs (trading activities) are conducted by the AEP and benefits associated with the System's Power Pool and shared among the parties generating plants. It is designed to function under the Interconnection Agreement. as an umbrella agreement in addition to the Trading activities involve the purchase and AEP Interconnection Agreement and the sale of electricity under physical forward CSW Operating Agreement, each of which contracts at fixed and variable prices and the will continue to control the distribution of costs trading of electricity contracts including and benefits within each zone.

exchange traded futures and options and over-the-counter options and swaps. The L-71

The following table shows the revenues derived from sales to the Pools and direct sales to affiliates for years ended December 31, 2001, 2000 and 1999:

APCo CSPCo I&M KPCo OPCo AEGCo Related Party Revenues (in thousands) 2001 Sales to East System Pool $ 91,977 $44,185 $239,277 $34,735 $431,637 $

sales to west system Pool 24,892 13,971 15,596 6,117 19,797 Direct sales To East Affiliatess 54,777 - - - 55,450 227,338 Direct Sales To west Affiliatess (3,133) (1,705) (1,905) (744) (2,590)

Other .772 11.060S$2ss~~~o 2,0711'54,LV.3b6$27*

2.258 7,072 Total Revenues 2000 Sales to East System Pool $ 81,013 $36,884 $200,4741$36,554 $502,140 $

Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 Direct Sales To East Affiliatess 59,106 66,487 227,983 Direct Sales To West Affiliatess 4,092 2,262 2,510 972 3,421 other 2 770 6,124 2 710 2,466 4,043 -

Total Revenues 1999 Sales to East System Pool $ 41,869 $15,136 $50,624 $43,157 $337,699 $

Direct Sales To East Affiliates 57,201 - - 50,968 152,559 other 1 162 4.582 345$ 1 145 825 -

Total Revenues CPL PSO SWEPCo WTU Related Party Revenues (in thousands) 2001 Sales to East System Pool $ - $ 4 $ - $

Sales to west system Pool 19,865 3,317 8,073 322 Direct Sales To East Affiliates 3,697 2,833 3,238 1,228 Direct Sales TO west Affiliates 12,617 30,668 67,930 9,350 other 5 583 (51) $

Total Revenues 7 81 2000 Sales to East System Pool Sales to West System Pool 23,421 7,323 5,546 194 Direct Sales To East Affiliates (3,348) (1,990) (3,008) (1,116)

Direct Sales To West Affiliates 12,516 21,995 62,178 7,645 Other 5 163 (12.680)

Total Revenues 1999 Sales to West System Pool $ 6,124 $ 3,097 $ 4,527 $ 401 Direct Sales To west Affiliates 7,470 7,968 49,542 2,576 other 14 177 2 652 48 11 790 Total Revenues The following table shows the purchased power expense incurred from purchases from the Pools and affiliates for the years ended December 31, 2001, 2000, and 1999:

APCo CSPCo I&M KPCo OPCo Related Party Purchases (in thousands) 2001 Purchases from East System Pool $346,582 $292,034 $ 79,030 $ 61,816 Purchases from west System Pool $62,350 296 165 185 72 235 Direct Purchases from East Affiliates 159,022 68,316 -

Direct Purchases from west Affiliates -

Total Purchases 2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 Purchases from west System Pool $50,339 455 260 285 108 390 Direct Purchases from East Affiliates 158,537 69,446 Direct Purchases from west Affiliates 14 8 Total Purchases 9 3 12 1999 Purchases from East System Pool $130,991 $199,574 $112,350 $19,502 $ 20,864 Direct Purchases from East Affiliates $200.372 88.022 4 498 Total Purchases L-72

CPL PSO SWEPCO WTU (in thousands)

Related Party Purchases Pool $ $ 1,327 $- $ 4 2001 Purchases from East System 415 5,877 3,810 11,689 Purchases from West System Pool Affiliates 12,657 37,445 27,744 4,614 Direct Purchases from East 34,603 9,696 40 349 Direct Purchases from West Affiliates 45.569 Total Purchases

$- $5 2000 Purchases from East System Pool $ - $20,100 4,379 18,444 Purchases from west System Pool 1,696 5,386 695 71 Direct Purchases from East Affiliates 251 2,117 Direct Purchases from west Affiliates 301644 8 264 39 ,258 Total Purchases HEM Purchases from west system Pool $ 895 $ 6,992 $1,295 $ 7,266 1999 6,256 19.325 Direct Purchases from west Affiliates 15,778 27,627 Total Purchases L 6 $2659 The above summarized related party revenues and expenses are reported in their entirely, without elimination, and are presented as operating revenues affiliated and purchased power affiliated on the income statement of each AEP Power Pool member. Since all of the above pool members are included in AEP's consolidated results, the above summarized related party transactions are eliminated in total in AEP's consolidated revenues and expenses.

L-73

AEP System TransmissionPool AEP's System Transmission Integration Agreement provides for the integration and APCo, CSPCo, I&M, KPCo and OPCo are coordination of the planning, operation and parties to the Transmission Agreement, dated maintenance of the transmission facilities of April 1, 1984, as amended (the Transmission AEP's east and west zone operating Agreement), defining how they share the subsidiaries. Like the System Integration costs associated with their relative ownership Agreement, the System Transmission of the extra-high-voltage transmission system Integration Agreement functions as an (facilities rated 345 kv and above) and certain umbrella agreement in addition to the AEP facilities operated at lower voltages (138 kv Transmission Agreement and the and above). Like the Interconnection Transmission Coordination Agreement. The Agreement, this sharing is based upon each System Transmission Integration Agreement company's "member-load-ratio." contains two service schedules that govern:

The following table shows the net (credits) or "* The allocation of transmission costs and charges allocated among the parties to the revenues.

Transmission Agreement during the years "* The allocation of third-party transmission ended December 31, 1998, 1999 and 2000: costs and revenues and System dispatch costs.

1999 2000 2001 (in thousands)

$ (8,300)

The Transmission Integration Agreement APCo $ (3,400) $ (3,100)

CSPCo 39,000 38,300 40,200 anticipates that additional service schedules I&M (43,900) (43,800) (41,300) may be added as circumstances warrant.

KPCo (4,300) (6,000) (4,600) opco 17,500 14,900 8,800 Unit PowerAgreements and Other CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission A unit power agreement between AEGCo and Coordination Agreement originally dated as of I&M (the I&M Power Agreement) provides for January 1, 1997 (TCA). The TCA established the sale by AEGCo to I&M of all the power a coordinating committee, which is charged (and the energy associated therewith) with the responsibility of overseeing the available to AEGCo at the Rockport Plant.

coordinated planning of the transmission I&M is obligated, whether or not power is facilities of the west zone operating available from AEGCo, to pay as a demand subsidiaries, including the performance of charge for the right to receive such power transmission planning studies, the interaction (and as an energy charge for any associated of such subsidiaries with independent system energy taken by I&M) such amounts, as when operators (ISO) and other regional bodies added to amounts received by AEGCo from interested in transmission planning and any other sources, will be at least sufficient to compliance with the terms of the Open enable AEGCo to pay all its operating and Access Transmission Tariff (OATT) filed with other expenses, including a rate of return on the FERC and the rules of the FERC relating the common equity of AEGCo as approved by to such tariff. FERC, currently 12.16%. The I&M Power Agreement will continue in effect until the Under the TCA, the west zone operating expiration of the lease term of Unit 2 of the subsidiaries have delegated to AEP Service Rockport Plant unless extended in specified Corporation the responsibility of monitoring circumstances.

the reliability of their transmission systems and administering the OATT on their behalf. Pursuant to an assignment between I&M and The TCA also provides for the allocation KPCo, and a unit power agreement between among the west zone operating subsidiaries KPCo and AEGCo, AEGCo sells KPCo 30%

of revenues collected for transmission and of the power (and the energy associated ancillary services provided under the OATT. therewith) available to AEGCo from both units of the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for the right to receive sucl power the same amounts which L-74

Year Ended December 31, I&M would have paid AEGCo under the terms 2001 2000 1999 of the I&M Power Agreement for such Company (in millions) entitlement. The KPCo unit power agreement I&M - revenues $30.2 $23.5 $28.1 AEGCo - expense 8.5 8.8 8.5 expires on December 31, 2004. APCo - expense 11.5 7.8 10.5 OPCo - expense 10.2 6.9 9.1 APCo and OPCo, jointly own two power plants. The costs of operating these facilities American Electric Power Service Corporation are apportioned between the owners based (AEPSC) provides certain managerial and on ownership interests. Each company's professional services to AEP System share of these costs is included in the companies. The costs of the services are appropriate expense accounts on each billed to its affiliated companies by AEPSC on company's consolidated statements of a direct-charge basis, whenever possible, and income. Each company's investment in these on reasonable bases of proration for shared plants is included in electric utility plant on its services. The billings for services are made consolidated balance sheets. at cost and include no compensation for the use of equity capital, which is furnished to I&M provides barging services to AEGCo, AEPSC by AEP Co., Inc. Billings from AEPSC APCo and OPCo. I&M records revenues from are capitalized or expensed depending on the barging services as nonoperating income. nature of the services rendered. AEPSC and AEGCo, APCo and OPCo record costs paid its billings are subject to the regulation of the to I&M for barging services as fuel expense. SEC under the 1935 Act.

The amount of affiliated revenues and affiliated expenses were:

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS The following is a combined Year-end ratings of AEP's subsidiaries' presentation of management's discussion and first mortgage bonds are listed in the following analysis of financial condition, contingencies table:

and other matters for AEP and certain of its Company Moody's S&P Fitch registrant subsidiaries. Management's discussion and analysis of results of APCo A3 A A CPL A3 A A operations for AEP and each of its subsidiary CSPCo A3 A A registrants is presented with their financial I&M Baal A BBB+

KPCo Baal A BBB+

statements earlier in this document. The OPCo A3 A A PSO Al A A+

following is a list of sections of management's SWEPCO Al A A+

discussion and analysis of financial condition, WTU A2 A- A contingencies and other matters and the registrant to which they apply: The ratings at the end of the year for senior unsecured debt are listed in the Financial condition AEP, APCo, CPL, I&M, OPCo, SWEPCo following table:

Market Risks AEP, AEGCo, APCo, Comran_ Moody's s&P Fitch CPL, CSPCo, I&M, KPCO, OPCO, PSO, AEP Baal BBB+ BBB+

SWEPCo, WTU AEP Resources* Baal BBB+ BBB+

APCo Baal BBB+ BBB+

Industry Restructuring AEP, APCo, CPL, CPL Baal BBB+ A CSPCo, I&M, OPCo, CSPCo A3 BBB+ A PSO, SWEPCo, WTU I&M Baa2 BBB+ BBB KPCo Baa2 BBB+ BBB Litigation AEP, AEGCo, APCo, OPCo A3 BBB+ BBB+

CPL, CSPCo, PSO A2 BBB+ A I&M, KPCo, OPCo, PSO, SWEPCO A2 BBB+ A SWEPCo, WTU

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

and Issues AEP, APCo, CPL, CSPCo, I&M, OPCo, SWEPCo The ratings are presently stable.

AEP's commercial paper program has short other Matters AEP, AEGCo, APCo, CPL, CSPCo, I&M, term ratings of A2 and P2 by Moody's and KPCo, OPCo, PSO, Standard and Poor's, respectively.

SWEPCo, WTU Financial Condition - Affecting AEP, AEP's common equity to total APCo, CPL, I&M, OPCo and SWEPCo capitalization declined to 33% in 2001 from 34% in 2000. Total capitalization includes We measure our financial condition by long-term debt due within one year, minority the strength of the balance sheet and the interests and short-term debt. Preferred stock liquidity provided by cash flows and earnings. at 1% remained unchanged. Long-term debt increased from 47% to 50% while short-term Balance sheet capitalization ratios and debt decreased from 18% to 13% and cash flow ratios are principal determinants of minority interest in finance subsidiary our credit quality. increased to 3%. In 2001 and 2000, AEP did not issue any shares of common stock to meet the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the Employee Savings Plan.

M-1

We plan to strengthen the balance acquisitions will be announced as arranged.

sheet in 2002 by issuing AEP common stock Long-term funding arrangements for specific and mandatory convertible preferred stock assets are often complex and typically not and using the proceeds from asset sales to completed until after the acquisition.

reduce debt. The issuance of common stock has the potential to dilute future earnings per Earnings for 2001 resulted in a share but will enhance the equity to dividend payout ratio of 80%, a considerable capitalization ratio. improvement over the 289% payout ratio in 2000. The abnormally high ratio in 2000 was Rating agencies have become more the result of the adverse impact on 2000 focused in their evaluation of credit quality as earnings from the Cook Plant extended a result of the Enron bankruptcy. They are outage and related restart expenditures, focusing especially on the composition of the merger costs and the write-off related to COLI balance sheet (off-balance sheet leases, debt and non-regulated subsidiaries. We expect and special purpose financing structures), the continued improvement of the payout ratio as cash liquidity profile and the impact of credit a result of earnings growth in 2002.

quality downgrades on financing transactions.

We have worked closely with the agencies to Cash from operations and short-term provide them with all the information they borrowings provide working capital and meet need, but we are unable to predict what other short-term cash needs. We generally actions, if any, they may take regarding our use short-term borrowings to fund property current ratings. acquisitions and construction until long-term funding mechanisms are arranged. Some During 2001 AEP's cash flow from acquisitions of existing business entities operations was $2.9 billion, including $971 include the assumption of their outstanding million from net income and $1.5 billion from debt and certain liabilities. Sources of long depreciation, amortization and deferred taxes. term funding include issuance of AEP Capital expenditures including acquisitions common stock, minority interest or long-term were $4 billion and dividends on common debt and sale-leaseback or leasing arrange stock were $773 million. Cash from ments. The domestic electric subsidiaries operations less dividends on common stock generally issue short-term debt to provide for financed 52% of capital expenditures. interim financing of capital expenditures that exceed internally generated funds and During 2001, the proceeds of AEP's periodically reduce their outstanding short

$1.25 billion global notes issuance and term debt through issuances of long-term debt proceeds from the sale of a UK distribution and additional capital contributions from their company and two generating plants provided parent company. We operate a money pool cash to purchase assets, fund construction, and sell accounts receivables to provide retire debt and pay dividends. Major liquidity for the domestic electric subsidiaries.

construction expenditures include amounts for Short-term borrowings in the U.S. are a wind generating facility and emission control supported by two revolving credit agreements.

technology on several coal-fired generating At December 31, 2001, approximately $554 units (see discussion in Note 8). Asset million remained available for short-term purchases include HPL, coal mines, a barge borrowings in the US.

line, a wind generating facility and two coal fired generating plants in the UK. These Subsidiaries that trade energy acquisitions accounted for the increase in commodities in Europe have a separate total debt in 2001. During the third quarter of multicurrency revolving loan and letters of 2001, permanent financing was completed for credit agreement allowing them to borrow up the acquisition of HPL by the issuance of a to 150 million Euros of which 42 million Euros minority interest which provided $735 million were available on December 31, 2001. In net of expenses (See Note 22 for discussion February 2002 they also originated a of the terms). HPL's permanent financing temporary second line of 50 million Euros for increased funds available for other corporate three months which is expected to be purposes. Long-term financings for the other replaced with a 150 million Euro line, M-2

providing for a total of 300 million Euros. Our revolving credit agreements SEEBOARD, Nanyang and Citipower which include covenants that require us to maintain operate in the UK, China and Australia, specified financial ratios and describe non respectively, each have independent performance of certain actions as events of financing arrangements which provide for default. At December 31, 2001 we complied borrowing in the local currency. SEEBOARD with the covenants of these agreements. In has a 320 million pound revolving credit general, a default in excess of $50 million agreement it uses for short-term funding under one agreement is considered a default purposes. At December 31, 2001, under the other agreements. In the case of a SEEBOARD had 117 million pounds default on payments under these agreements, available. all amounts outstanding would be immediately payable.

M-3

The contractual obligations of AEP include amounts reported on the balance sheet and other obligations disclosed in our footnotes. The following table summarizes AEP's contractual cash obligations at December 31, 2001:

Payments Due by Period (in millions)

Contractual Cash obligations Less Than 1 year 2-3 years 4-5 years After 5 years Total Long-term Debt $2,300 $2,988 $2,559 $ 4,246 $12,093 3,155 - 3,155 short-term Debt 321 321 Trust Preferred Securities Minority Interest In Finance 750 Subsidiary (a) 750 Preferred stock subject to 95 24 4 67 Mandatory Redem tion 397 728 capital Lease obligations 96 144 91 ilncnnditinnal purrchase obligatio*os (b).. 317 1,658 1,299 3,559 6,833 Noncancellable operating Leases 286 526 488 2,671 3,971 other Long-term obligations (c) 31 30 - - 61 Total Contractual cash obligations (a) The initial period of the preferred interest is through August 2006. At the end of the initial period, the preferred rate may be reset, the preferred member interests may be re-marketed to new investors, the preferred member interests may be redeemed, in whole or in part including accrued return, or the preferred member interest may be liquidated.

(b) Represents contractual obligations to purchase coal and natural gas as fuel for electric generation along with related transportation of the fuel.

(c) Represents contractual obligations to loan funds to a joint venture accounted for under the equity method.

For the subsidiary registrants, please see each registrant's schedules of capitalization and long term debt included with each registrants' financial statements in sections B through J for the timing of debt payment obligations and the lease footnote (Note 18) in section L for the timing of rent payments.

Special purpose entities have been employed for some of the contractual cash obligations reported in the above table. The lease of Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers), the permanent financing of HPL and the sale of accounts receivable use special purpose entities. Neither AEP nor any AEP related parties has an ownership interest in the special purpose entities. AEP does not guarantee the debt of these entities. These special purpose entities are not consolidated in AEP's financial statements in accordance with generally accepted accounting principles. As a result, neither the assets nor the debt of the special IL4Z purpose entities is included on AEP's balance sheet. The future cash obligations payable to the special purpose entities are included in the above table In addition to the amounts disclosed in the contractual cash obligations table above, AEP and certain subsidiaries make commitments in the normal course of business. These commitments include standby letters of credit, guarantees for the payment of obligation performance bonds, and other commitments. AEP's commitments outstanding at December 31, 2001 under these agreements are summarized in the table below:

Amount of Commitment Expiration Per Period (in millions) other commercial commitments Less Than 1 year 2-3 years 4-5 years After 5 years Total standby Letters of Credit $ 101 $ 53 - $36 $ 190 Guarantees 815 161 - 15 991 Construction of Generating and Transmission Facilities for Parties (a)

Third cnmmrrcial 168 540 708 nthier commitments (b) 6 45 40 24 115 Total commercial Commitments i, IM M M (a) As construction agent for third party owners of power plants and transmission facilities, the company has committed by contract terms to complete construction by dates specified in the contracts. should the company default on these obligations, financial payments could be up to 100% of contract value (amount shown in table) or other remedies reguired by contract terms.

(b) Represents estimated future payments for power to be generated at facilities under construction.

M-4

With the exceptions of SWEPCo's sold and the proceeds from the sale are guarantanee of an unaffiliated mine operator's insufficient to repay the Investors, AEP may obligations (payable upon their default) of be required to make a payment to the Lessor

$111 million at December 31, 2001, and of up to 85% of the project's cost. AEP has OPCo's obligations under a power purchase guaranteed a portion of the obligations of its agreement of $6 million in 2002 and $16 subsidiaries to the SPE during the million each year in 2003 through 2005, the construction and post-construction periods.

obligations in the above table are commitments of AEP and its non-registrant As of December 31, 2001, project subsidiaries. costs subject to these agreements totaled

$168 million, and total costs for the completed AEP, through certain subsidiaries, has facility are expected to be approximately $450 entered into agreements with an unrelated, million. Since the lease is accounted for as an unconsolidated special purpose entity (SPE) operating lease for financial accounting to develop, construct, finance and lease a purposes, neither the facility nor the related power generation facility. The SPE will own obligations are reported on AEP's balance the power generation facility and lease it to an sheets. The lease is a variable rate obligation AEP consolidated subsidiary after indexed to three-month LIBOR. Consequently construction is completed. The lease will be as market i interest rates increase, the accounted for as an operating lease with the payments under this operating lease will also payment obligations included in the lease increase. Annual payments of approximately footnote. Payments under the operating $12 million represent future minimum lease are expected to commence in the first payments under the first five-year lease term quarter of 2004. AEP will in turn sublease the calculated using the indexed LIBOR rate of facility to an unrelated industrial company 2.85% at December 31, 2001.

which will both use the energy produced by the facility and sell excess energy. Another The lease payments and the guarantee affiliate of AEP has agreed to purchase the of construction commitments are included in excess energy from the subleasee for resale. the Other Commercial Commitments table above.

The SPE has an aggregate financing commitment from equity and debt participants OPCo has entered into a purchased (Investors) of $427 million. AEP, in its role as power agreement to purchase electricity pro construction agent for the SPE, is responsible duced by an unaffiliated entity's three-unit for completing construction by December 31, natural gas fired plant that is under 2003. In the event the project is terminated construction. The first unit is anticipated to be before completion of construction, AEP has completed in October 2002 and the agree the option to either purchase the project for ment will terminate 30 years after the third unit 100% of project costs or terminate the project begins operation. Under the terms of the and make a payment to the Lessor for 89.9% agreement OPCo has the option to run the of project costs. plant until December 31, 2005 taking 100% of the power generated. For the remainder of the The term of the operating lease 30 year contract term, OPCo will pay the between the SPE and the AEP subsidiary is variable costs to generate the electricity it pur five years with multiple extension options. If chases which could be up to 20% of the all extension options are exercised the total plant's capacity. The estimated fixed pay term of the lease would be 30 years. AEP's ments through December 2005 are $55 lease payments to the SPE are sufficient to million and are included in the Other provide a return to the Investors. At the end Commercial Commitments table shown of the first five-year lease term or any above.

extension, AEP may renew the lease at fair market value subject to Investor approval; purchase the facility at its original construction cost; or sell the facility, on behalf of the SPE, to an independent third party. If the project is M-5

Minority Interest in Finance Subsidiary Steelhead has the right to terminate the transaction and liquidate Caddis upon the In August 2001, AEP formed Caddis occurrence of certain events including a Partners, LLC (Caddis), a consolidated default in the payment of the preferred return.

subsidiary, and sold a non-controlling pre Steelhead's rights include: forcing a ferred member interest in Caddis to an liquidation of Caddis and acting as the unconsolidated special purpose entity liquidator, and requiring the conversion of the (Steelhead) for $750 million. Under the $321.4 million of AEP subsidiary preferred provisions of the Caddis formation agree stock into AEP common stock. If the ments, the preferred member interest preferred member interest exercised its rights receives quarterly a preferred return equal to to liquidate under these conditions, then AEP an adjusted floating reference rate (4.413% at would evaluate whether to refinance at that December 31, 2001). The $750 million time or relinquish the assets that support the received replaced interim funding used to preferred member interest. Liquidation of the acquire Houston Pipe Line Company in June preferred interest or of Caddis could impact 2001. AEP's liquidity.

The preferred interest is supported by Caddis and the AEP subsidiary which natural gas pipeline assets and $321.4 million acts as its managing member are each a of preferred stock issued by an AEP limited liability company, with a separate subsidiary to the AEP affiliate which has the existence and identity from its members, and managing member interest in Caddis. Such the assets of each are separate and legally preferred stock is convertible into common distinct from AEP. The results of operations, stock of AEP upon the occurrence of certain cash flows and financial position of Caddis events. AEP can elect not to have the and such managing member are consolidated transaction supported by such preferred stock with AEP for financial reporting purposes.

ifthe preferred interest were reduced by $225 The preferred member interest and payments million. In addition, Caddis has the right to of the preferred return are reported on AEP's redeem the preferred member interest at any income statement and balance sheet as time. Minority Interest in Finance Subsidiary.

The initial period of the preferred Expenditures for domestic electric interest is through August 2006. At the end of utility construction are estimated to be $4.6 the initial period, Caddis will either reset the billion for the next three years. Approximately preferred rate, re-market the preferred 100% of those construction expenditures are member interests to new investors, redeem expected to be financed by internally the preferred member interests, in whole or in generated funds.

part including accrued return, or liquidate in accordance with the provisions of applicable Construction expenditures for the agreements. registrant subsidiaries for the next three years excluding AFUDC are:

The credit agreement between Caddis and the AEP subsidiary that acts as its Construction Projected Expenditures managing member contains covenants that construction Financed with restrict incremental liens and indebtedness, Expenditures Internal Funds (in millions) asset sales, investments, acquisitions, and APCo $ 815.5 92%

distributions. Financial covenants impose CPL 573.1 80%

minimum financial ratios. At December 31, I&M 556.9 ALL OPCo 1,008.0 68%

2001, we satisfied all of the financial ratio SWEPCo 321.4 92%

requirements. In general, a default in excess of $50 million under another agreement is In 1998 SEEBOARD's 80% owned considered a default under this agreement. subsidiary, SEEBOARD Powerlink, signed a 30-year contract for $1.6 billion to operate, maintain, finance and renew the high-voltage power distribution network of the London M-6

Underground transportation system. With corporate separation, a newly created SEEBOARD Powerlink will be responsible for holding company for the unregulated business distributing high voltage electricity to supply is expected to issue all debt needed to fund 270 London Underground stations and 250 the wholesale business and unregulated miles of the rail system's track. SEEBOARD's generating companies. The size and maturity partners in Powerlink are an international lengths of the original offering is presently electrical engineering group and an being determined.

international cable and construction group.

The regulated holding company is FinancingActivity expected to issue the debt needed by the wires companies in Ohio and Texas. The AEP issued $1.25 billion of global notes regulated integrated utility companies will in May 2001 (with intermediate maturities). continue their current debt structure until the The proceeds were loaned to regulated and regulatory commissions approve changes. At non-regulated subsidiaries. that time, the regulated holding company may also issue the debt for the regulated companies' funding needs.

In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5 million and We have requested credit ratings for

$175.6 million, respectively, of first mortgage the holding companies consistent with our bonds in preparation for corporate separation. existing credit quality, but we cannot predict what the outcome will be.

AEP Credit purchases, without recourse, the accounts receivable of most of AEP Uses a money pool to meet the the domestic utility operating companies and short-term borrowings for certain of its certain non-affiliated electric utility companies. subsidiaries, primarily the domestic electric AEP Credit's financing for the purchase of utility operations. Following corporate receivables changed during 2001. Starting separation, management will evaluate the December 31, 2001, AEP Credit entered into advantages of establishing a money pool for a sale of receivables agreement. The the unregulated business subsidiaries. The agreement allows AEP Credit to sell certain current money pool which was approved by receivables and receive cash meeting the the appropriate regulatory authorities will requirements of SFAS 140 for the receivables continue to service the regulated business to be removed from the balance sheet. The subsidiaries, Presently, AEP also funds the agreement expires in May 2002 and is short-term debt requirements of other expected to be renewed. At December 31, subsidiaries that are not included in the 2001, AEP Credit had $1.0 billion sold under money pool. As of December 31, 2001, AEP this agreement of which $485 million are non had credit facilities totaling $3.5 billion to affiliated receivables. In January 2002, AEP support its commercial paper program. At Credit stopped purchasing accounts December 31, 2001, AEP had $2.9 billion receivables from non-affiliated electric utility outstanding in short-term borrowing subject to companies. these credit facilities.

In February 2002 CPL issued $797 Market Risks - Affecting AEP, AEGCo, million of securitization notes that were APCo, CPL, CSPCo, I&M, KPCo, OPCo, approved by the PUCT as part of Texas PSO, SWEPCo and WTU restructuring to help decrease rates and recover regulatory assets. The proceeds were As a major power producer and trader used to reduce CPL's debt and equity. of wholesale electricity and natural gas, we have certain market risks inherent in our In 2002 AEP plans to continue business activities. These risks include com restructuring its debt for corporate separation modity prico risk, interest rate risk, foreign assuming receipt of all necessary regulatory exchange riik and credit risk. They represent approvals. Corporate separation will require the risk of loss that may impact us due to the transfer of assets between legal entities. changes in the underlying market prices or M-7

rates. AEP's exposure to interest rates, primarily related to long-term debt with fixed interest Policies and procedures are rates, was $673 million at December 31, 2001 established to identify, assess, and manage and $998 million at December 31, 2000.

market risk exposures in our day to day However, since we would not expect to operations. Our risk policies have been liquidate our entire debt portfolio in a one year reviewed with the Board of Directors, holding period, a near term change in interest approved by a Risk Management Committee rates should not materially affect results of and administered by a Chief Risk Officer. The operations or consolidated financial position.

Risk Management Committee establishes risk limits, approves risk policies, assigns The following table shows the potential responsibilities regarding the oversight and loss in fair value as measured by VaR management of risk and monitors risk levels. allocated to the AEP registrant subsidiaries This committee receives daily, weekly, and based upon debt outstanding:

monthly reports regarding compliance with policies, limits and procedures. The VaR for Registrant Subsidiaries:

committee meets monthly and consists of the December 31, 2001 2000 Chief Risk Officer, Chief Credit Officer, V.P. (in millions)

Market Risk Oversight, and senior financial Coman AEGCo $ 5 $ 4 and operating managers. APCo 100 149 CPL 80 135 CSPCo 60 84 We use a risk measurement model I&M 86 129 KPCo 16 31 which calculates Value at Risk (VaR) to OPCo 59 112 measure our commodity price risk. The VaR PSO 17 44 SWEPCo 36 60 is based on the variance - covariance method WTU 20 24 using historical prices to estimate volatilities and correlations and assuming a 95% AEGCo is not exposed to risk from confidence level and a one-day holding changes in interest rates on short-term and period. Based on this VaR analysis, at long-term borrowings used to finance December 31, 2001 a near term typical operations since financing costs are change in commodity prices is not expected to recovered through the unit power have a material effect on our results of agreements.

operations, cash flows or financial condition.

The following table shows the high, average, AEP is exposed to risk from changes in and low market risk as measured by VaR at: the market prices of coal and natural gas used to generate electricity where generation December 31. is no longer regulated or where existing fuel 2001 2000 High Average Low High Average LOW clauses are suspended or frozen. The (in millions) protection afforded by fuel clause recovery AEP $28 $14 $5 $32 $10 $1 mechanisms has either been eliminated by APCo 4 1 6 2 the implementation of customer choice in CPL 3 1 4 CSPCo 2 1 11 Ohio (effective January 1, 2001 for CSPCo 3

I&M 3 1 4 1 and OPCo) and in the ERCOT area of Texas KPCo 1 1 OPCo 3 1 5 2 (effective January 1, 2002 for CPL and WTU) 1 1 PSO 2 1

3 1

or frozen by settlement agreements in SWEPCo 3 4 WTU 1 1 1 Indiana, Michigan and West Virginia. To the extent the fuel supply of the generating units We also utilize a VaR model to in these states is not under fixed price long measure interest rate market risk exposure. term contracts AEP is subject to market price The interest rate VaR model is based on a risk. AEP continues to be protected against Monte Carlo simulation with a 95% market price changes by active fuel clauses in confidence level and a one year holding Oklahoma, Arkansas, Louisiana, Kentucky, period. The volatilities and correlations were Virginia and the SPP area of Texas.

based on three years of weekly prices. The risk of potential loss in fair value attributable to M-8

We employ physical forward purchase daily. We believe that our credit and market and sale contracts, exchange futures and exposures with any one counterparty is not options, over-the-counter options, swaps, and material to financial condition at December other derivative contracts to offset price risk 31, 2001. At December 31, 2001 less than where appropriate. However, we engage in 5% of the counterparties were below trading of electricity, gas and to a lesser investment grade as expressed in terms of degree coal, oil, natural gas liquids, and Net Mark to Market Assets. Net Mark to emission allowances and as a result the Market Assets represents the aggregate Company is subject to price risk. The amount difference (either positive or negative) of risk taken by the traders is controlled by the between the forward market price for the management of the trading operations and remaining term of the contract and the the Company's Chief Risk Officer and his contractual price. The following table staff. When the risk from trading activities approximates counterparty credit quality and exceeds certain pre-determined limits, the exposure for AEP.

positions are modified or hedged to reduce Futures, the risk to the limits unless specifically Forward ar approved by the Risk Management Counterparty Swap Committee. Credit Quality: Contracts Options Total December 31, 2001 (in millions)

We employ fair value hedges, cash AAA/Exchanges $ 147 $ 147 AA 140 4 144 flow hedges and swaps to mitigate changes in 304 7 311 A

interest rates or fair values on short and long BBB 932 34 966 term debt when management deems it Below Investment Grade 56 23 79 necessary. We do not hedge all interest rate risk. Total ssaM

= 14 We employ cash flow forward hedge The counterparty credit quality and contracts to lock-in prices on transactions exposure for the registrant subsidiaries is denominated in foreign currencies where generally consistent with that of AEP.

deemed necessary. International subsidiaries use currency swaps to hedge exchange rate We enter into transactions for fluctuations in debt denominated in foreign electricity anid natural gas as part of wholesale currencies. We do not hedge all foreign trading operations. Electric and gas currency exposure. transactions are executed over the counter with counterparties or through brokers. Gas AEP limits credit risk by extending transactions are also executed through unsecured credit to entities based on internal brokerage accounts with brokers who are ratings. In addition, AEP uses Moody's registered with the Commodity Futures Investor Service, Standard and Poor's and Trading Commission. Brokers and qualitative and quantitative data to counterpartles require cash or cash related independently assess the financial health of instruments to be deposited on these counterparties on an ongoing basis. This transactions as margin against open data, in conjunction with the ratings positions. The combined margin deposits at information, is used to determine appropriate December 31, 2001 and 2000 was $55 million risk parameters. AEP also requires cash and $95 million. These margin accounts are deposits, letters of credit and parental/affiliate restricted and therefore are not included in guarantees as security from certain below cash and cash equivalents on the Balance investment grade counterparties in our normal Sheet. We can be subject to further margin course of business. requirements should related commodity prices change.

We trade electricity and gas contracts with numerous counterparties. Since our We recognize the net change in the open energy trading contracts are valued fair value Of all open trading contracts, a based on changes in market prices of the practice ccimmonly called mark-to-market related commodities, our exposures change accountingj in accordance with generally M-9

accepted accounting principles and include The following table shows net the net change in mark-to-market amounts on revenues (revenues less fuel and purchased a net discounted basis in revenues. energy expense) and their relationship to the Unrealized mark-to-market revenues totaled mark-to-market revenues (the change in fair

$257 million in 2001. The fair values of open value of open trading contracts).

short-term trading contracts are based on exchange prices and broker quotes. The fair December 31, 2001 2000 1999 value of open long-term trading contracts are (in millions) based mainly on Company developed Revenues (including valuation models. The valuation models mark- to market produce an estimated fair value for open long adjustment) $61,257 $36,706 $24,745 term trading contracts. This fair value is Fuel and Purchased present valued and reduced by appropriate Energy reserves for counterparty credit risks and Expense 52,753 28,718 17.244 Net Revenues liquidity risk. The models are derived from Mark-to-Market I23.5p internally assessed market prices with the Revenues Sim0 M2 Percentage of exception of the NYMEX gas curve, where we Net Revenues Represented by use daily settled prices. Forward price curves Mark-to-Market 2%

2%

are developed for inclusion in the model based on broker quotes and other available 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 z.'

and the bid price of the bid ask prices if we have a long position and the ask side 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 trading contracts has inherent risks relating to the underlying assumptions employed by such models. Independent controls are in place to evaluate the reasonableness of the price curve models.

Significant adverse or favorable effects on future results of operations and cash flows could occur if market risks, at the time of settlement, do not correlate with the Company developed price models.

The effect on the Consolidated Statements of Income of marking to market open electricity trading contracts in the Company'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 gains and losses from trading are reported as assets or liabilities.

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The following tables analyze the changes in fair values of trading assets and liabilities. The first table "Net Fair Value of Energy Trading Contracts" shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet line item "energy trading and derivative contracts." The next table "Energy Trading Contracts" disaggregates realized and unrealized changes in fair value; identifies changes in fair value as a result of changes in valuation methodologies; and reconciles the net fair value of energy trading contracts at the beginning of the year of $63 million to the end of the year of $448 rillion. Contracts realized/settled during the period include both sales and purchase contracts. The third table "Energy Trading Contract Maturities" shows exposures to changes in fair values and realization periods over time for each method used to determine fair value.

Net Fair Value of Energy Trading Contracts December 31, 2001 2000 (in millions)

Energy Trading Contracts:

Current Asset $ 8,536 $ 15,495 Long-term Asset 2,367 1,552 Current Liability (8,279) (15,671)

Long-term Liability (2.176) (1,313)

Net Fair value of Energy Trading contracts $ 44 i$ 63 The net fair value of energy trading contracts includes $257 million at December 31, 2001 and

$170 million at December 31, 2000 of unrealized mark-to-market gains that are recognized in the income statement. Also included in the above net fair value of energy trading contracts are option premiums that are deferred until the related contracts settle and the portion of changes in fair values of electricity trading contracts that are deferred for ratemaking purposes.

Energy Trading Contracts AEP consolidated (in millions)

Total Net Fair value of Energy Trading contracts at December 31, 2000 $ 63 Gain from Contracts realized/settled during period (352) (a)

Fair value of new open contracts when entered into during period 73 (b)

Adjustments for Contracts entered into and settled during period 310 (a)

Net option premium payments 24 change in fair value due to valuation Methodology changes (1) (c) changes in market value of contracts 331 (d)

Net Fair value of Energy Trading contracts at December 31, 2001 $A48 (e)

(a) Gains from Contracts Realized or Otherwise Settled During the Period" include realized gains from energy trading contracts that settled during 2001 that were entered into prior to 2001, as well as during 2001. "Adjustment for Contracts Entered into and settled During the Period" discloses the realized gains from settled energy trading contracts that were both entered into and closed within 2001 that are included in the total gains of $352 million, but not included in the ending balance of open contracts.

(b) The "Fair value of New Open Contracts when Entered Into during period" represents the fair value of long-term contracts entered into with customers during 2001. The fair value is calculated as of the execution of the contract. Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. The contract prices are valued against market curves representative of the delivery location.

(c) The Company changed its methodology for calculating and reporting load based transactions.

The previous methodology estimated a baseload volume based on historical takes and sold a call option for potential load increases from the baseloaq. The current methodology uses a modified version of a straddle load follow model to estimate the baseload volume and call option volume. This methodogy change more accurately estimates the load volume forecast.

The dollar impact on existing deals was a decrease of injfair value of $1.2 million.

(d) "Change in market value of contracts" represents the fair value change in the trading portfolio due to market fluctuations during the current period. Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.

(e) The net change in the fair value of energy trading contracts for 2001 that resulted in an increase of $385 million ($448 million less $63 million) represents the balance sheet change. The net mark-to-market gain on energy trading contracts of $257 million represents the impact on earnings. The difference is related primarily to regulatory deferrals of certain mark-to-market gains that were recorded as regulatcry liabilities and not reflected in the income statement for those companies that operate in regulated jurisdictions, and deferrals of option premiums included in the above analysis, which do not have a mark-to market income statement impact.

M-11

Energy Trading Contracts (in thousand)

APCo CPL CSPCo Net Fair Value of Energy Trading Contracts at December 31, 2000 $ 7,447 $(8,191) $ 3,769 Loss/(Gain) from Contracts Realized/settled during period (12,478) 4,221 (11,522)

Fair value of new open Contracts when entered into during period 13,441 9,635 8,245 Adjustments for Contracts Entered into and settled during period 40,755 2,602 24,998 Net option premium payments 1,072 658 change in fair value due to valuation Methodology changes (220) (158) (135) changes in market value of Contracts 25,684 (425) 22,436 Net Fair Value of Energy Trading Contracts at December 31, 2001 Energy Trading Contracts (in thousands)

Net Fair Value of Energy Trading I&M KPCo OPCO Contracts at December 31, 2000 $ (6,845) $ 1,678 $ 5,613 Loss/(Gain) from contracts Realized/settled during period (10,982) (3,298) (10,861)

Fair Value of new open contracts when entered into During period 8,921 3,315 11,213 Adjustments for Contracts Entered into and settled During period 27,049 10,051 34,001 Net option premium payments 712 264 894 change in fair value due to valuation Methodology changes (146) (54) (183) changes in market value of Contracts 42.636 773 24,769 Net Fair Value of Energy Trading Contracts at December 31, 2001 Energy Trading Contracts (in thousands)

PSO SWEPCo WTU Net Fair Value of Energy Trading Contracts at December 31, 2000 $(6,508) $(7,795) $(2,590)

LosS/(Gain) from contracts Realized/settled during period 2,483 2,938 5,881 Fair value of new open Contracts when entered into During period 7,338 8,422 2,861 Adjustments for Contracts Entered into and settled during period 1,981 2,274 773 Net option premium payments Change in fair value due to valuation Methodology changes (120) (138) (46) changes in market value of contracts (2,740) (2,801) (5_96)

Net Fair Value of Energy Trading Contracts at December 31, 2001 M-12

Energy Trading Contract Maturities Fair Value of Contracts at December 31,2001 Maturities (in millions)

AEP consolidated Less than In Excess Tot al Fair source of Fair value 1 Year 1-3 years 4-5 years of 5 years val ue Prices actively quoted (a) $ 46 $ 8 $ 54 Prices provided by other external 33 185 sources (b) 152 Prices based on models and other 13 133 35 28 209 valuation methods (c)

Total 117A M35 S448 Energy Trading Contract Maturities Fair value of Contracts at December 31,2001 Maturities (in thousands)

Less than In Excess Total Fair source of Fair value 1 year 1-3 years 4-5 years of 5 years value APCO Other External Sources 13,366 9,588 22,954 3,215 34,318 6,801 52,747 Model s/other valuation Total CPL (3,564) other External sources (5,245) 1,681 6016 1 1,192 7421 Models/other valuation (

Total !_M5 119 CSP 15,739 other External sources 9,867 5,872 2,373 21,018 5,153 32,710 Model s/other valuation Total 5,153 KEPCo 886 other External sources (1,475) 2,361 Models/Other valuation (355) 8451 1,675 112843 Total I&M 23,718 Other External sources 17,237 6,481 37,627 4,146 23,197 Models/other valuation Total OPCo 21,045 other External sources 13,058 7,987 Models/other valuation 3,141 28 587 5,665 44,40 Total PSO (3,120) other External sources (4,400) 1,280 908 5,554 (1058) 48 1.123 Model s/Other valuation SS2 .861 Total SWEPCo (3,496) other External Sources (4,965) 1,469 (1,194) 5259 1042 6,396 Models/other valuation Total WTU (1,244) other External Sources (1,743) 499 (419) .786 354 2,159 Models/other valuation 3_5 Total (a) "Prices Actively Quoted" represents the company's exchange traded futures positions in natural gas.

(b) "Prices Provided by other External sources" represents the company's positions in natural gas, power, and coal at points where over-the-counter broker quotes are available. Prices for these various commodities can generally be obtained on the over the-counter market through 2003. some prices from external sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this category.

(c) "Prices Based on Models and other valuation Methods" contain the following: the value of the Company's adjustments for liquidity and counterparty credit exposure, the value of contracts not quoted by an exchan e or an over-the-countor broker, the value of transactions for which an internally developed price cur'e was developed as a result of the long dated nature of certain transactions, and the value of certain structured transactions.

M-13

We have investments in debt and for the generation business. The seven equity securities which are held in nuclear states in various stages of restructuring to trust funds. The trust investments and their transition power generation and supply to fair value are discussed in Note 13, "Risk market based pricing are Arkansas, Michigan, Management, Financial Instruments and Ohio, Oklahoma, Texas, Virginia, and West Derivatives." Financial instruments in these Virginia. AEP has not discontinued its trust funds have not been included in the regulatory accounting for its subsidiaries market risk calculation for interest rates as doing business in Michigan and Oklahoma these instruments are marked-to-market and pending the effective implementation of the changes in market value of these instruments legislation. Restructuring legislation, the are reflected in a corresponding status of the transition plans and the status of decommissioning liability. Any differences the electric utility companies' accounting to between the trust fund assets and the ultimate comply with the changes in each of AEP's liability are expected to be recovered through seven state regulatory jurisdictions affected by regulated rates from our regulated customers. restructuring legislation is presented in the Note 7 of the Notes to Financial Statements.

Inflation affects our cost of replacing utility plant and the cost of operating and RTO Formation maintaining plant. The rate-making process limits recovery to the historical cost of assets, FERC Order No. 2000 and many of the resulting in economic losses when the effects settlement agreements with the FERC and of inflation are not recovered from customers state regulatory commissions to approve the on a timely basis. However, economic gains AEP-CSW Merger have provisions for the that result from the repayment of long-term transfer of functional control of our debt with inflated dollars partly offset such transmission system to an RTO. Certain AEP losses. subsidiaries are participating in the formation of the Alliance RTO. Other subsidiaries are a Industry Restructuring member of ERCOT or SPP.

In 2000 California's deregulated In 2001 the Alliance companies and electricity market suffered problems including MISO entered into a settlement addressing high energy prices mainly due to short energy transmission pricing and other "seam" issues supplies and financial difficulties for retail between the two RTOs. The FERC distribution companies. This energy crisis has subsequently expressed its opinion that four highlighted the importance of risk large RTO regions serving the continental US management and has contributed to certain would best support competition and reliability state regulatory and legislative actions which of electric service. Certain state regulatory have delayed the start of customer choice and commissions have taken exception to the the transition to competitive, market based FERC's RTO actions. Louisiana's pricing for retail electricity supply in some of commission ordered utilities it regulates, the states in which AEP operates. Seven of including SWEPCo, to show the advantage of the eleven state retail jurisdictions in which large RTOs to their customers.

the AEP domestic electric utility companies operate have enacted restructuring On December 19, 2001 the FERC legislation. In general, the legislation provides approved the proposal of the Midwest ISO for for a transition from cost-based regulation of a regional transmission organization and told bundled electric service to customer choice the Alliance companies, which had submitted and market pricing for the supply of electricity. a separate RTO proposal, to explore joining As legislative and regulatory proceedings the Midwest ISO organization. The FERC's evolved, six AEP electric operating order is intended to facilitate the companies (APCo, CPL, CSPCo, OPCo, establishment of a single RTO in the Midwest SWEPCo and WTU) doing business in five of and to support the establishment of viable, the seven states that have passed for-profit transmission companies under an restructuring legislation have discontinued the RTO umbrella and concluded that the RTO application of SFAS 71 regulatory accounting proposed by Alliance companies lacks M-14

sufficient scope to exist as a stand-alone RTO Shareholders'Litigation- Affecting AEP and thus directed the Alliance companies to explore how their business plan can be On December 21, 2001, the U.S.

accommodated within the Midwest ISO. District Court for the Southern District of Ohio dismissed a class action lawsuit against AEP Management is unable to predict the and four former or present officers. The outcome of these transmission regulatory complaint alleged violation of federal actions and proceedings or their impact on securities laws by disseminating materially the timing and operation of RTOs, AEP's false and misleading statements related to the transmission operations or future results of extended Cook Plant outage.

operations and cash flows.

FERC Wholesale Fuel Complaints- Affecting AEP and WTU Litigation In November 2001 certain WTU AEP is involved in various litigation. wholesale customers filed a complaint with The details of significant litigation contin FERC alleging that WTU has overcharged gencies are disclosed in Note 8 and them since 1997 through the fuel adjustment summarized below. clause. The customers allege inappropriate costs related to purchased power were COLI - Affecting AEP, APCo, CSPCo, I&M, included in the fuel adjustment clause.

KPCo and OPCo Management is working to compute if any overcharges occurred and is unable to predict A decision by U.S. District Court for their impact on results of operations, cash the Southern District of Ohio in February 2001 flow and financial condition.

that denied AEP's deduction of interest claimed on AEP's consolidated federal Municipal FranchiseFee Litigation - Affecting income tax returns related to its COLI AEP and CPL program resulted in a $319 million reduction in net income for 2000. AEP had filed suit to In 2001 CPL paid $11 million to settle resolve the IRS' assertion that interest class action litigation regarding municipal deductions for AEP's COLI program should franchise fees in Texas. The City of San Juan, Texas had filed a class action lawsuit in not be allowed. In 1998 and 1999 AEP and 1996 seeking $300 million in damages.

the impacted subsidiaries paid the disputed taxes and interest attributable to COLI interest Texas Base Rate Litigation - Affecting AEP deductions for taxable years 1991-98 for and CPL APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment by In 2001 the Texas Supreme Court the IRS of additional interest on the contested denied CPL's request for the court to review a tax. The payments were included in other 1997 PUCT base rate order. Subsequently assets on AEP's balance sheet and other the Court also denied CPL's rehearing property and investments on the subsidiaries' request.

balance sheets pending the resolution of this matter. AEP has appealed the Court's The primary Issues CPL requested the Court decision. to review were:

• the classification of $800 million of The earnings reductions for affected invested capital in STP as ECOM and registrant subsidiaries are as follows: assigning it a lower return on equity than other generation property; (in millions)

• and an $18 million disallowance of APCo $ 82 affiliated service billings.

CSPCo 41 I&M 66 KPCo 8 OPCo 118 M-15

Lignite Mining Agreement Litigation feasible measures to improve air and water Affecting AEP and SWEPCo quality, limit emissions and protect the health of employees, customers, neighbors and In 2001 SWEPCo settled litigation others impacted by their operations. In concerning lignite mining in Louisiana. Since support of this policy, AEP and its subsidiaries 1997 SWEPCo has been involved in litigation continue to invest in research through groups concerning the mining of lignite from jointly like the Electric Power Research Institute and owned lignite reserves. SWEPCo and directly through demonstration projects for CLECO, an unaffiliated utility, are each a 50% new technology for the capture and storage of owner of the Dolet Hills Power Station Unit 1 carbon dioxide, mercury, NOx and other and jointly own lignite reserves in the Dolet emissions. The AEP System intends to Hills area of northwestern Louisiana. Under continue in a leadership role to protect and terms of a settlement, SWEPCo purchased preserve the environment while providing vital an unaffiliated mine operator's interest in the energy commodities and services to mining operations and related debt and other customers at fair prices.

obligations for $86 million.

AEP and its subsidiaries have a proven Merger Litigation - Affecting AEP and all record of efficiently producing and delivering Subsidiary Registrants electricity and gas while minimizing the impact on the environment. AEP and its subsidiaries In January 2002, a federal court ruled have spent billions of dollars to equip their that the SEC failed to prove that the June 15, facilities with the latest cost effective clean air 2000 merger of AEP with CSW meets the and water technologies and to research new requirements of the PUHCA and sent the technologies. We are proud of our award case back to the SEC for further review. winning efforts to reclaim our mining Management believes that the merger meets properties.

the requirements of the PUHCA and expects the matter to be resolved favorably.

The introduction of multi-pollutant Other - Affecting AEP and all Subsidiary control legislation is being discussed by Registrants members of Congress and the Bush Administration. The legislation being AEP and its registrant subsidiaries are considered may regulate carbon dioxide, involved in a number of other legal NOx, sulfur dioxide, mercury and other proceedings and claims. While management emissions from electric generating plants.

is unable to predict the outcome of such Management will continue to support litigation, it is not expected that the ultimate solutions which are based on sound science, resolution of these matters will have a economics and demonstrated control material adverse effect on the results of technologies. Management is unable to operations, cash flows or financial condition. predict the timing or magnitude of additional pollution control laws or regulations. If Environmental Concerns and Issues additional control technology is required on facilities owned by the electric utility The U.S. continues to debate an array companies and their costs were not of environmental issues affecting the electric recoverable from ratepayers or through utility industry including new emission market based prices or volumes of product limitations recommended by the Bush sold, they could adversely affect future results Administration in February 2002. Most of the of operations and cash flows. The following policies are aimed at reducing air emissions discussions explains existing control efforts, citing alleged impacts of such emissions on litigation and other pending matters related to public health, sensitive ecosystems or the environmental issues for AEP companies.

global climate.

AEP and its subsidiaries' policy on the environment continues to be the development and application of long-term economically M-16

Federal EPA Complaint and Notice of continuing and a settlement could impact the Violation - Affecting AEP, APCo, CSPCo, I&M operation of Zimmer Plant and W.C. Beckjord and OPCo Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until a final Since 1999 AEP, APCo, CSPCo, I&M settlement is reached, CSPCo will be unable and OPCo have been involved in litigation to determine the settlement's impact on its regarding generating plant emissions under jointly owned facilities and its future results of the Clean Air Act. Federal EPA, a number of operations and cash flows.

states and certain special interest grups alleged that APCo, CSPCo, I&M and OPCo NOx Reduction - Affecting AEP, APCo, CPL, modified certain generating units over a 20 I&M, OPCo and SWEPCo year period in violation of the Clean Air Act.

Federal EPA issued a NOx rule (the Under the Clean Air Act, if a plant Nox Rule) and granted petitions filed by undertakes a major modification that directly certain northeastern states (the Section 126 results in an emissions increase, permitting Rule) requiring substantial reductions in NOx requirements might be triggered and the plant emissions in a number of eastern states, may be required to install additional pollution including certain states in which the AEP control technology. This requirement does not System's generating plants are located.

apply to activities such as routine maintenance, replacement of degraded Federal EPA ruled that eleven states, equipment or failed components, or other including certain states in which AEP's repairs needed for the reliable, safe and generating units are located, failed to submit efficient operation of the plant. We believe our approvable plans to comply with the NOx maintenance, repair and replacement Rule. This ruling means that those states activities were in conformity with the Clean Air could face stringent sanctions including limits Act and intend to vigorously pursue our on construction of new sources of air defense. emissions, loss of federal highway funding and possible Federal EPA takeover of state The Clean Air Act authorizes civil air quality management programs. A request penalties of up to $27,500 per day per for the D.C. Circuit Court to review this ruling violation at each generating unit ($25,000 per is pending. The compliance date for the NOx day prior to January 30, 1997). In March 2001 Rule is May 31, 2004.

the District Court ruled that claims for civil penalties based on activities that occurred The D.C. Circuit Court instructed more than five years before the filing date of Federal EPA to justify methods used to the complaints cannot be imposed. There is allocate allowances and project growth for no time limit on claims for injunctive relief. both the NOx Rule and the Section 126 Rule.

In response to AEP and other utilities request Management is unable to estimate a for the D.C. Circuit Court to suspend the May loss or predict the timing of the resolution of 2003 compliance date of the Section 126 these matters due to the number of alleged Rule, the D.C. Circuit Court issued an order violations and the significant number of issues tolling the compliance schedule until Federal yet to be determined by the Court. If we do EPA responds to the Court's remand.

not prevail, any capital and operating costs of additional pollution control equipment that In April 2000 the Texas Natural may be required as well as any penalties Resource Conservation Commission adopted imposed would adversely affect future results rules requiring significant reductions in NOx of operations, cash flows and possibly emissions from utility sources, including CPL financial condition. and SWEPCo. The compliance date is May 2003 for CPL and May 2005 for SWEPCo.

An unaffiliated utility which operates certain plants jointly owned by CSPCo In 2001 selective catalytic reduction reached a tentative agreement to settle (SCR) techr ology to reduce NOx emissions on OPCo's Gavin Plant commenced litigation regarding generating plant emissions operation. Construction of SCR technology at under the Clean Air Act. Negotiations are certain othe generating units continues with M-17

completion scheduled in 2002 through 2006. Superfund addresses clean-up of hazardous substances at disposal sites and Our estimates indicate that compliance authorized Federal EPA to administer the with the NOx Rule, the Texas Natural clean-up programs. As of year-end 2001, Resource Conservation Commission rule and subsidiaries of AEP have been named by the the Section 126 Rule could result in required Federal EPA as a PRP for five sites. APCo, capital expenditures of approximately $1.6 CSPCo, and OPCo each have one PRP site billion of which approximately $450 million has and I&M has two PRP sites. There are four been spent for the AEP System. additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo have The following table shows the received information requests which could estimated compliance cost and amounts lead to PRP designation. CPL, OPCo and spent for certain of AEP's registrant SWEPCo have also been named a PRP at subsidiaries. two sites under state law. Our liability has been resolved for a number of sites with no Estimated Amounts significant effect on results of operations. In Compliance Costs Spent (in millions) those instances where AEP or its subsidiaries Company have been named a PRP or defendant, their APCo $365 $130 disposal or recycling activities were in CPL 57 4 accordance with the then-applicable laws and I&M 202 OPCo 606 277 regulations. Unfortunately, Superfund does SWEPCo 28 21 not recognize compliance as a defense, but imposes strict liability on parties who fall within Since compliance costs cannot be its broad statutory categories.

estimated with certainty, the actual cost to comply could be significantly different than the While the potential liability for each estimates depending upon the compliance Superfund site must be evaluated separately, alternatives selected to achieve reductions in several general statements can be made NOx emissions. Unless any capital and regarding AEP's and its subsidiaries' potential operating costs of additional pollution control future liability. Disposal of materials at a equipment are recovered from customers, particular site is often unsubstantiated and the they will have an adverse effect on future quantity of materials deposited at a site was results of operations, cash flows and possibly small and often nonhazardous. Although financial condition. liability is joint and several, typically many parties are named as PRPs for each site and Superfund - Affecting AEP, APCo, CPL, several of the parties are financially sound CSPCo, I&M, OPCo and SWEPCo enterprises. Therefore, our present estimates do not anticipate material cleanup costs for By-products from the generation of identified sites for which we have been electricity include materials such as ash, slag, declared PRPs. If significant cleanup costs sludge, low-level radioactive waste and SNF. are attributed to AEP or its subsidiaries in the Coal combustion by-products, which future under Superfund, results of operations, constitute the overwhelming percentage of cash flows and possibly financial condition these materials, are typically disposed of or would be adversely affected unless the costs treated in captive disposal facilities or are can be recovered from customers.

beneficially utilized. In addition, our generating plants and transmission and Global Climate Change - Affecting AEP and distribution facilities have used asbestos, all Registrant Subsidiaries PCBs and other hazardous and non hazardous materials. We are currently At the Third Conference of the Parties incurring costs to safely dispose of these to the United Nations Framework Convention substances. Additional costs could be on Climate Change held in Kyoto, Japan in incurred to comply with new laws and December 1997 more than 160 countries, regulations if enacted. including the U.S., negotiated a treaty requiring legally-binding reductions in M-18

emissions of greenhouse gases, chiefly deposited in external trust funds to provide for carbon dioxide, which many scientists believe the future disposal of SNF and $172 million are contributing to global climate change. has been remitted to the DOE. CPL has Although the U.S. signed the Kyoto Protocol collected and remitted to the DOE, $49 million on November 12, 1998, the treaty was not for the future disposal of SNF since STP submitted to the Senate for its advice and began operation in the late 1980s. Under the consent by President Clinton. In March 2001 provisions of the Nuclear Waste Policy Act, President Bush announced his opposition to collections from customers are to provide the the treaty and its U.S. ratification. At the DOE with money to build a permanent Seventh Conference of the Parties in repository for spent fuel. However, in 1996, November 2001, the parties finalized the the DOE notified the companies that it would rules, procedures and guidelines required to be unable to begin accepting SNF by the facilitate ratification of the protocol. The January 1998 deadline required by law. To protocol is expected to become effective by date DOE has failed to comply with the 2003. U.S. representatives attended the requirements of the Nuclear Waste Policy Act.

Seventh Conference but they did not take any positions on issues being negotiated or As a result of DOE's failure to make attempt to block the approval of any issue. sufficient progress toward a permanent AEP does not support the Kyoto Protocol but repository or otherwise assume responsibility intends to work with the Bush Administration for SNF, AEP on behalf of I&M and STPNOC and U.S. Congress to develop responsible on behalf of CPL and the other STP owners, public policy on this issue. Management along with a number of unaffiliated utilities expects due to President Bush's opposition to and states, filed suit in the D.C. Circuit Court legislation mandating greenhouse gas requesting, among other things, that the D.C.

emissions controls, any policies developed Circuit Court order DOE to meet its and implemented in the near future are likely obligations tinder the law. The D.C. Circuit to encourage voluntary measures to reduce, Court ordered the parties to proceed with avoid or sequester such emissions. contractual remedies but declined to order DOE to begin accepting SNF for disposal.

The acquisition of 4,000 MW of coal DOE estimates its planned site for the nuclear fired generation in the United Kingdom in waste will not be ready until at least 2010. In December 2001 exposes these assets to 1998, AEP and I&M filed a complaint in the potential carbon dioxide emission control U.S. Court of Federal Claims seeking obligations since the U.K. is expected to be a damages in excess of $150 million due to the party to the Kyoto Protocol. DOE's partial material breach of its unconditional contractual deadline to begin Costs for Spent Nuclear Fuel and disposing of SNF generated by the Cook Decommissioning - Affecting AEP, CPL and Plant. Similar lawsuits were filed by other I&M utilities. In August 2000, in an appeal of related cases involving other unaffiliated I&M, as the owner of the Cook Plant, utilities, the U.S. Court of Appeals for the and CPL, as a partial owner of STP, have a Federal Circuit held that the delays clause of significant future financial commitment to the standarcd contract between utilities and the safely dispose of SNF and decommission and DOE did not apply to DOE's complete failure decontaminate the plants. The Nuclear to perform Its contract obligations, and that Waste Policy Act of 1982 established federal the utilities' suits against DOE may continue in responsibility for the permanent off-site court. AEP's and I&M's suit has been stayed disposal of SNF and high-level radioactive pending further action by the U.S. Court of waste. By law CPL and I&M participate in the Federal Claims. As long as the delay in the DOE's SNF disposal program which is availability of a government approved storage described in Note 8 of the Notes to Financial repository for SNF continues, the cost of both Statements. Since 1983 I&M has collected temporary and permanent storage and the

$288 million from customers for the disposal cost of debommissioning will continue to of nuclear fuel consumed at the Cook Plant. increase.

$116 million of these funds have been M-19

In January 2001, I&M and STPNOC, significant or should any new concerns be on behalf of STP's joint owners, joined a uncovered that are material they could have a lawsuit against DOE, filed in November 2000 material adverse effect on results of by unaffiliated utilities, related to DOE's operations and possibly financial condition.

nuclear waste fund cost recovery settlement AEP performs environmental reviews and with PECO Energy Corporation. The audits on a regular basis for the purpose of settlement allows PECO to skip two payments identifying, evaluating and addressing to the DOE for disposal of SNF due to the environmental concerns and issues.

lack of progress towards development of a permanent repository for SNF. The APCo, AEP's subsidiary which companies believe the settlement is unlawful operates in Virginia and West Virginia, has as the settlement would force other utilities to been seeking regulatory approval to build a make up any shortfall in DOE's SNF disposal new high voltage transmission line for over a funds. decade. Through December 31, 2001 we have invested approximately $40 million in The cost to decommission nuclear this effort. If the required regulatory approvals plants is affected by both NRC regulations are not obtained and the line is not and the delayed SNF disposal program. constructed, the $40 million investment would Studies completed in 2000 estimate the cost be written off adversely affecting AEP's and to decommission the Cook Plant ranges from APCo's future results of operations and cash

$783 million to $1,481 million in 2000 non flows.

discounted dollars. External trust funds have been established with amounts collected from OTHER MATTERS customers to decommission the plant. At December 31, 2001, the total decom Enron Bankruptcy - Affecting AEP, APCo, missioning trust fund balance for Cook Plant CSPCo, I&M, KPCo and OPCo was $598 million which includes earnings on the trust investments. Studies completed in At the date of Enron's bankruptcy AEP 1999 for STP estimate CPL's share of had open trading contracts and trading decommissioning cost to be $289 million in accounts receivables and payables with 1999 non-discounted dollars. Amounts Enron. In addition, on June 1, 2001, we collected from customers to decommission purchased Houston Pipe Line from Enron and STP have been placed in an external trust. At entered into a lease arrangement with a December 31, 2001, the total decommission subsidiary of Enron for a gas storage facility.

ing trust fund for CPL's share of STP was $99 At the date of Enron's bankruptcy various HPL million which includes earnings on the trust related contingencies and indemnities investments. Estimates from the remained unsettled. In the fourth quarter of decommissioning studies could continue to 2001 AEP provided $47 million ($31 million escalate due to the uncertainty in the SNF net of tax) for our estimated losses from the disposal program and the length of time that Enron bankruptcy.

SNF may need to be stored at the plant site.

We will work with regulators and customers to The amounts for certain subsidiary recover the remaining estimated costs of registrants were:

decommissioning Cook Plant and STP.

However, AEP's, CPL's and I&M's future Amounts results of operations, cash flows and possibly Amounts Net of their financial conditions would be adversely Registrant Provided Tax affected if the cost of SNF disposal and (in millions) decommissioning continues to increase and cannot be recovered. APCo $5.2 3.4 CSPCo 3.2 2.1 AEP and its subsidiaries are exposed I&M 3.4 2.2 to other environmental concerns which are KPCo 1.3 0.8 not considered to be material or potentially OPCo 4.3 2.8 material at this time. Should they become M-20

The amounts provided were based on dollars is not other than temporary. As a an analysis of contracts where AEP and result and pursuant to the put option Enron are counterparties, the offsetting of agreement, these losses have not been receivables and payables, the application of applied to reduce the carrying values of the deposits from Enron and management's Vale and Caiua investments. As a result we analysis of the HPL related purchase will not recognize any future earnings from contingencies and indemnifications. If there Vale and Caiua until the operating losses are are any adverse unforeseen developments in recovered. Should the impairment of our the bankruptcy proceedings, our future results investment become other than temporary due of operations, cash flows and possibly to our partners in Vale becoming unable to financial condition could be adversely fulfill their responsibilities, it would have an impacted. adverse effect on future results of operations.

InternationalInvestments - Affecting AEP Management will continue to monitor both the status of the losses and the ability of We own a 44% equity interest in Vale, its partners to fulfill their obligations under the a Brazilian electric operating company which put.

was purchased for a total of $149 million. On December 1, 2001 we converted a $66 million Investments Limitations - Affecting AEP note receivable and accrued interest into a 20% equity interest in Caiua (Brazilian electric Our investment, including guarantees operating company), a subsidiary of Vale. of debt, in certain types of activities is limited Vale and Caiua have experienced losses from by PUHCA. SEC authorization under PUHCA operations and our investment has been limits us to issuing and selling securities in an affected by the devaluation of the Brazilian amount up to 100% of our average quarterly Real. The cumulative equity share of consolidated retained earnings balance for operating and foreign currency translation investment in EWGs and FUCOs. At losses through December 31, 2001 is December 31, 2001, AEP's investment in approximately $46 million and $54 million, EWGs and FUCOs was $2.9 billion, including respectively net of tax. The cumulative equity guarantees of debt, compared to AEP's limit share of operating and foreign currency of $3.3 billion.

translation losses through December 31, 2000 is approximately $33 million and $49 million, SEC rules under PUHCA permit AEP to respectively net of tax. Both investments are invest up to 15% of consolidated capitalization covered by a put option, which, if exercised, (such amount was $3.6 billion at December requires our partners in Vale to purchase our 31, 2001) in energy-related companies, Vale and Caiua shares at a minimum price including marketing and/or trading of equal to the U.S. dollar equivalent of the electricity, gas and other energy commodities.

original purchase price. As a result, Our gas trading business and our interest in management has concluded that the domestic cogeneration projects are reported investment carrying amount should not be as investments under this rule and at reduced below the put option value unless it is December 31, 2001, such investment was deemed to be an other than temporary $2.2 billion.

impairment and our partners in Vale are deemed unable to fulfill their responsibilities New Accounting Standards- Affecting AEP, under the put option. Management has AEGCo, APCo, CPL, CSPCo, I&M, KPCo, evaluated through an independent third-party, OPCo, PSO, SWEPCo and WTU the ability of its Vale partners to fulfill their responsibilities under the put option The FASB recently issued SFAS 141, agreement and has concluded that our "Business Combinations" and SFAS 142, partners should be able to fulfill their "Goodwill A d Other Intangible Assets." SFAS responsibilities. 141 requires that the purchase method of accounting be used to account for all Management believes that the decline business combinations entered into after June in the value of its investment in Vale in US 30, 2001. SFAS 142 requires that goodwill M-21

amortization cease and that goodwill and In August 2001 the FASB issued SFAS other intangible assets with indefinite lives be 144, "Accounting for the Impairment or tested for impairment upon SFAS 142 Disposal of Long-lived Assets" which sets implementation and annually thereafter. We forth the accounting to recognize and must implement these new standards in the measure an impairment loss. This standard first quarter of 2002. Amortization of goodwill replaces the previous standard, SFAS 121, and other intangible assets with indefinite "Accounting for the Long-lived Assets and for lives will cease with our implementation of Long-lived Assets to be Disposed Of." SFAS SFAS 142 beginning January 1, 2002. The 144 will apply to us beginning January 1, amortization of goodwill reduced AEP's net 2002. We do not expect that the imple income by $50 million for the twelve months mentation of SFAS 144 will materially affect ended December 31, 2001. The registrant results of operations or financial condition.

subsidiaries did not have any goodwill at December 31, 2001. We are currently in the The FASB recently revised its prior process of fair valuing our reporting units with guidance related to SFAS 133, "Accounting goodwill in order to determined potential for Deriviative Instruments and Hedging goodwill impairment. As such we have not yet Activities" with regard to certain power option determined the impact on first quarter 2002 and forward contracts. The revised guidance results of operations of adopting the provision states that power contracts, including both of these standards. forward and option contracts, that include certain qualitative characteristics are SFAS 143, "Accounting for Asset considered capacity contracts, and qualify for Retirement Obligations," will become effective the normal purchases and normal sales for us beginning January 1, 2003. SFAS 143 exception from being marked to market even established accounting and reporting for legal if they are subject to being booked out, or obligations associated with the retirement of scheduled to be booked out. As normal tangible long-lived assets and the related purchases and sales these open energy asset retirement costs. We are currently in contracts are not marked to market. Rather the process of evaluating the provisions of the they are accounted for on a settlement basis.

standard and determining its impact on future Most of AEP's power contracts that are not results of operations and financial condition. marked to market as trading transactions do To the extent AEP or it registrant subsidiaries not qualify as derivatives and thus are not are regulated entities, we anticipate that the subject to the revised guidance. The few cumulative effect of this accounting change contracts that are derivatives qualified for the on future results of operations will be exception under the previous guidance and significantly offset by a regulatory asset will continue to qualify under the new representing the right to recover legal asset guidance.

retirement obligations (ARO) relative to regulated long lived assets included in rate base. The impact on future results of operations from the implementation of this new standard on non-regulated long lived assets has not yet been determined. We anticipate that the considerable effort to identify all long lived assets with legal ARO and to determine the required discounted legal ARO will take the remainder of 2002.

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Common stock and Dividend Information The quarterly high and low sales prices for AEP common stock and the cash divi ends paid per share are shown in the following table:

Quarter Ended High Low Dividend March 2001 $48.10 $39.25 $0.60 june 2001 51.20 45.10 0.60 september 2001 48.90 41.50 0.60 December 2001 46.95 39.70 0.60 March 2000 34.94 25.94 0.60 June 2000 38.50 29.44 0.60 September 2000 40.00 29.94 0.60 December 2000 48.94 36.19 0.60 AEP common stock is traded principally on the New York stock Exchange. At December 31, 2001, AEP had approximately 150,000 shareholders of record.

ATTACHMENT 2 TO AEP:NRC:2691-11 INDIANA MICHIGAN POWER COMPANY PROJECTED CASH FLOW FOR THE YEAR 2002

Indiana Michigan Power Co.

2002 Forecasted Internal Cash Flow

$ Millions 2002 Net income After Taxes 117.4 Less: Dividends 4.5 112.9 Adjustments:

Depreciation and Amortization 169.8 Amortization of Deferred Operating Costs 85.6 Deferred Federal Income Taxes and Investment Tax Credits (41.3)

AFUDC (2.2)

Changes in Working Capital (45.5)

Total Adjustments 166.4 Internal Cash Flow 279.3 Average Quarterly Cash Flow 69.8 Average Cash Balances and Short-Term Investments 0.5 Total 70.3 Projected