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<SEC-DOCUMENT>0000004904-03-000086.txt : 20030320
<SEC-HEADER>0000004904-03-000086.hdr.sgml : 20030320
<ACCEPTANCE-DATETIME>20030320170458
ACCESSION NUMBER:		0000004904-03-000086
CONFORMED SUBMISSION TYPE:	10-K
PUBLIC DOCUMENT COUNT:		21
CONFORMED PERIOD OF REPORT:	20021231
FILED AS OF DATE:		20030320

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			AMERICAN ELECTRIC POWER CO INC
		CENTRAL INDEX KEY:			0000004904
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				134922640
		STATE OF INCORPORATION:			NY
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	001-03525
		FILM NUMBER:		03610921

	BUSINESS ADDRESS:	
		STREET 1:		1 RIVERSIDE PLZ
		CITY:			COLUMBUS
		STATE:			OH
		ZIP:			43215
		BUSINESS PHONE:		6142231000

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	KINGSPORT UTILITIES INC
		DATE OF NAME CHANGE:	19660906
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>module.txt
<DESCRIPTION>AEP AND SUBSIDIARIES
<TEXT>
<PAGE>
<PAGE>

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                          ---------------------------
                                   FORM 10-K
                          ---------------------------

(Mark One)

[X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934
     For the fiscal year ended December 31, 2002

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934
     For the transition period from -------------- to --------------

<Table>
<Caption>
    COMMISSION                  REGISTRANTS; STATES OF INCORPORATION;                  I.R.S. EMPLOYER
    FILE NUMBER                      ADDRESS AND TELEPHONE NUMBER                    IDENTIFICATION NOS.
    -----------                 -------------------------------------                -------------------
<S>                  <C>                                                            <C>
1-3525               AMERICAN ELECTRIC POWER COMPANY, INC. (A New York                          13-4922640
                     Corporation)
0-18135              AEP GENERATING COMPANY (An Ohio Corporation)                               31-1033833
0-346                AEP TEXAS CENTRAL COMPANY (A Texas Corporation)                            74-0550600
0-340                AEP TEXAS NORTH COMPANY (A Texas Corporation)                              75-0646790
1-3457               APPALACHIAN POWER COMPANY (A Virginia Corporation)                         54-0124790
1-2680               COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)                      31-4154203
1-3570               INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)                    35-0410455
1-6858               KENTUCKY POWER COMPANY (A Kentucky Corporation)                            61-0247775
1-6543               OHIO POWER COMPANY (An Ohio Corporation)                                   31-4271000
0-343                PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)               73-0410895
1-3146               SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)               72-0323455
                     1 Riverside Plaza, Columbus, Ohio 43215
                     Telephone (614) 223-1000
</Table>

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

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

     Indicate by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company, Indiana Michigan Power Company or Ohio Power Company
pursuant to Item 405 of Regulation S-K (229.405 of this chapter) is not
contained herein, and will not be contained, to the best of registrant's
knowledge, in definitive proxy or information statements of Appalachian Power
Company or Ohio Power Company incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K.  X

     Indicate by check mark whether American Electric Power Company, Inc. is an
accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of
1934). Yes  X No __

     Indicate by check mark whether AEP Generating Company, AEP Texas Central
Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio
Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company are accelerated filers (as defined in Rule 12b-2 of the Securities
Exchange Act of 1934). Yes __ No  X

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<Table>
<Caption>
                                                                                            NAME OF EACH EXCHANGE
            REGISTRANT                              TITLE OF EACH CLASS                      ON WHICH REGISTERED
            ----------                              -------------------                     ---------------------
<S>                                 <C>                                                  <C>
AEP Generating Company              None

AEP Texas Central Company           None

AEP Texas North Company             None

American Electric                   Common Stock,
  Power Company, Inc.                 $6.50 par value..................................  New York Stock Exchange
                                    9.25% Equity Units.................................  New York Stock Exchange

Appalachian Power Company           7.20% Senior Notes, Series A, Due 2038.............  New York Stock Exchange
                                    7.30% Senior Notes, Series B, Due 2038.............  New York Stock Exchange

Columbus Southern Power Company     None

CPL Capital I                       8.00% Cumulative Quarterly Income
                                      Preferred Securities, Series A, Liquidation
                                      Preference $25 per Preferred Security............  New York Stock Exchange

Indiana Michigan                    8% Junior Subordinated Debentures, Series A, Due
  Power Company                       2026.............................................  New York Stock Exchange
                                    7.60% Junior Subordinated Deferrable
                                      Interest Debentures, Series B, Due 2038..........  New York Stock Exchange
                                    6% Senior Notes, Series D, Due 2032................  New York Stock Exchange

Kentucky Power Company              8.72% Junior Subordinated Deferrable
                                      Interest Debentures, Series A, Due 2025..........  New York Stock Exchange

Ohio Power Company                  7 3/8% Senior Notes, Series A, Due 2038............  New York Stock Exchange

Public Service Company              6% Senior Notes, Series B, Due 2032................  New York Stock Exchange
  of Oklahoma

PSO Capital I                       8.00% Trust Originated Preferred
                                      Securities, Series A, Liquidation
                                      Preference $25 per Preferred Security............  New York Stock Exchange

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

Southwestern Electric               None
  Power Company
</Table>
<PAGE>

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

<Table>
<Caption>
                 REGISTRANT                                         TITLE OF EACH CLASS
                 ----------                                         -------------------
<S>                                             <C>
AEP Generating Company                          None
AEP Texas Central Company                       4.00% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                4.20% Cumulative Preferred Stock, Non-Voting, $100 par value
AEP Texas North Company                         None
American Electric Power Company, Inc.           None
Appalachian Power Company                       4.50% Cumulative Preferred Stock, Voting, no par value
Columbus Southern Power Company                 None
Indiana Michigan Power Company                  4.125% Cumulative Preferred Stock, Non-Voting, $100 par
                                                value
Kentucky Power Company                          None
Ohio Power Company                              4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma              None
Southwestern Electric Power Company             4.28% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                4.65% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                5.00% Cumulative Preferred Stock, Non-Voting, $100 par value
</Table>

<Table>
<Caption>
                                                    AGGREGATE MARKET VALUE
                                                   OF VOTING AND NON-VOTING              NUMBER OF SHARES
                                                      COMMON EQUITY HELD                 OF COMMON STOCK
                                                     BY NON-AFFILIATES OF                 OUTSTANDING OF
                                                      THE REGISTRANTS AT                THE REGISTRANTS AT
                                                        JUNE 28, 2002                     JUNE 28, 2002
                                                   ------------------------             ------------------
<S>                                            <C>                               <C>
AEP Generating Company                                       None                             1,000
                                                                                        ($1,000 par value)
AEP Texas Central Company                                    None                           2,211,678
                                                                                         ($25 par value)
AEP Texas North Company                                      None                           5,488,560
                                                                                         ($25 par value)
American Electric Power Company, Inc.                  $13,560,125,474                     338,833,720
                                                                                        ($6.50 par value)
Appalachian Power Company                                    None                           13,499,500
                                                                                          (no par value)
Columbus Southern Power Company                              None                           16,410,426
                                                                                          (no par value)
Indiana Michigan Power Company                               None                           1,400,000
                                                                                          (no par value)
Kentucky Power Company                                       None                           1,009,000
                                                                                         ($50 par value)
Ohio Power Company                                           None                           27,952,473
                                                                                          (no par value)
Public Service Company of Oklahoma                           None                           9,013,000
                                                                                         ($15 par value)
Southwestern Electric Power Company                          None                           7,536,640
                                                                                         ($18 par value)
</Table>

          NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES

     American Electric Power Company, Inc. owns, directly or indirectly, all of
the common stock of AEP Generating Company, AEP Texas Central Company, AEP Texas
North Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company,
Public Service Company of Oklahoma and Southwestern Electric Power Company (see
Item 12 herein).
<PAGE>

                      DOCUMENTS INCORPORATED BY REFERENCE

<Table>
<Caption>
                                                                         PART OF FORM 10-K
                                                                        INTO WHICH DOCUMENT
DESCRIPTION                                                               IS INCORPORATED
- -----------                                                             -------------------
<S>                                                            <C>

Portions of Annual Reports of the following companies for                     Part II
the fiscal year ended December 31, 2002:

               AEP Generating Company
               AEP Texas Central Company
               AEP Texas North Company
               American Electric Power Company, Inc.
               Appalachian Power Company
               Columbus Southern Power Company
               Indiana Michigan Power Company
               Kentucky Power Company
               Ohio Power Company
               Public Service Company of Oklahoma
               Southwestern Electric Power Company

Portions of Proxy Statement of American Electric Power                       Part III
Company, Inc. for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002

Portions of Information Statements of the following                          Part III
companies for 2003 Annual Meeting of Shareholders, to be
filed within 120 days after December 31, 2002:

               Appalachian Power Company
               Ohio Power Company
</Table>

                               ------------------

        THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AEP TEXAS CENTRAL COMPANY, AEP TEXAS NORTH COMPANY, AMERICAN ELECTRIC POWER
COMPANY, INC., APPALACHIAN POWER COMPANY, COLUMBUS SOUTHERN POWER COMPANY,
INDIANA MICHIGAN POWER COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY,
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SOUTHWESTERN ELECTRIC POWER COMPANY.
INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY
SUCH REGISTRANT ON ITS OWN BEHALF. EXCEPT FOR AMERICAN ELECTRIC POWER COMPANY,
INC., EACH REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO THE
OTHER REGISTRANTS.

        YOU CAN ACCESS FINANCIAL AND OTHER INFORMATION AT AEP'S WEBSITE. THE
ADDRESS IS WWW.AEP.COM. AEP MAKES AVAILABLE, FREE OF CHARGE ON ITS WEBSITE,
COPIES OF ITS ANNUAL REPORT ON FORM 10-K, QUARTERLY REPORTS ON FORM 10-Q,
CURRENT REPORTS ON FORM 8-K AND AMENDMENTS TO THOSE REPORTS FILED OR FURNISHED
PURSUANT TO SECTION 13(A) OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 AS
SOON AS REASONABLY PRACTICABLE AFTER FILING SUCH MATERIAL ELECTRONICALLY OR
OTHERWISE FURNISHING IT TO THE SEC.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>

                               TABLE OF CONTENTS

<Table>
<Caption>
                                                                              PAGE
                                                                             NUMBER
                                                                             ------
<S>        <C>  <C>                                                          <C>
Glossary of Terms...........................................................    i

Forward-Looking Information.................................................    1

PART I
   Item     1.  Business....................................................    2
   Item     2.  Properties..................................................   26
   Item     3.  Legal Proceedings...........................................   29
   Item     4.  Submission of Matters to a Vote of Security Holders.........   30
   Executive Officers of the Registrants....................................   30

PART II
   Item     5.  Market for Registrant's Common Equity and Related
                  Stockholder Matters.......................................   32
   Item     6.  Selected Financial Data.....................................   32
   Item     7.  Management's Discussion and Analysis of Results of
                  Operations and Financial Condition........................   33
   Item    7A.  Quantitative and Qualitative Disclosures About Market
                  Risk......................................................   33
   Item     8.  Financial Statements and Supplementary Data.................   33
   Item     9.  Changes in and Disagreements with Accountants on Accounting
                  and Financial Disclosure..................................   33
PART III
   Item    10.  Directors and Executive Officers of the Registrants.........   33
   Item    11.  Executive Compensation......................................   34
   Item    12.  Security Ownership of Certain Beneficial Owners and
                  Management and Related Stockholder Matters................   34
   Item    13.  Certain Relationships and Related Transactions..............   37

PART IV
   Item    14.  Controls and Procedures.....................................   37
   Item    15.  Exhibits, Financial Statement Schedules, and Reports on Form
                  8-K.......................................................   37

Signatures..................................................................   39

Certifications..............................................................   42

Index to Financial Statement Schedules......................................  S-1

Independent Auditors' Report................................................  S-2

Exhibit Index...............................................................  E-1
</Table>
<PAGE>

                               GLOSSARY OF TERMS

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

<Table>
<Caption>
        ABBREVIATION OR ACRONYM                                   DEFINITION
        -----------------------                                   ----------
<S>                                      <C>
AEGCo. ................................  AEP Generating Company, an electric utility subsidiary of
                                           AEP
AEP....................................  American Electric Power Company, Inc.
AEPES..................................  AEP Energy Services, Inc., a subsidiary of AEP
AEP Power Pool.........................  APCo, CSPCo, I&M, KPCo and OPCo, as parties to the
                                           Interconnection Agreement
AEPR...................................  AEP Resources, Inc., a subsidiary of AEP
AEPSC or Service Corporation...........  American Electric Power Service Corporation, a service
                                           subsidiary of AEP
AEP System or the System...............  The American Electric Power System, an integrated electric
                                           utility system, owned and operated by AEP's electric utility
                                           subsidiaries
AEP Utilities..........................  AEP Utilities, Inc., subsidiary of AEP, formerly, Central
                                           and South West Corporation
AFUDC..................................  Allowance for funds used during construction. Defined in
                                           regulatory systems of accounts as the net cost of borrowed
                                           funds used for construction and a reasonable rate of
                                           return on other funds when so used.
APCo. .................................  Appalachian Power Company, an electric utility subsidiary of
                                           AEP
Btu....................................  British thermal unit
Buckeye................................  Buckeye Power, Inc., an unaffiliated corporation
CAA....................................  Clean Air Act
CAAA...................................  Clean Air Act Amendments of 1990
Cardinal Station.......................  Generating facility co-owned by Buckeye and OPCo
Centrica...............................  Centrica U.S. Holdings, Inc., and its affiliates
                                           collectively, unaffiliated companies
CERCLA.................................  Comprehensive Environmental Response, Compensation and
                                           Liability Act of 1980
CG&E...................................  The Cincinnati Gas & Electric Company, an unaffiliated
                                           utility company
Cook Plant.............................  The Donald C. Cook Nuclear Plant, owned by I&M, located near
                                           Bridgman, Michigan
CSPCo. ................................  Columbus Southern Power Company, a public utility subsidiary
                                           of AEP
CSW Operating Agreement................  Agreement, dated January 1, 1997, by and among PSO, SWEPCo,
                                           TCC and TNC governing generating capacity allocation
DOE....................................  United States Department of Energy
DP&L...................................  The Dayton Power and Light Company, an unaffiliated utility
                                           company
East Zone Companies of AEP.............  APCo, CSPCo, I&M, KPCo and OPCo
ECOM...................................  Excess cost over market
EMF....................................  Electric and Magnetic Fields
EPA....................................  United States Environmental Protection Agency
ERCOT..................................  Electric Reliability Council of Texas
EWG....................................  Exempt wholesale generator, as defined under PUHCA
FERC...................................  Federal Energy Regulatory Commission
Fitch..................................  Fitch Ratings, Inc.
FPA....................................  Federal Power Act
FUCO...................................  Foreign utility company as defined under PUHCA
I&M....................................  Indiana Michigan Power Company, a public utility subsidiary
                                           of AEP
I&M Power Agreement....................  Unit Power Agreement Between AEGCo and I&M, dated March 31,
                                           1982
Interconnection Agreement..............  Agreement, dated July 6, 1951, by and among APCo, CSPCo,
                                           I&M, KPCo and OPCo, defining the sharing of costs and
                                           benefits associated with their respective generating
                                           plants
IURC...................................  Indiana Utility Regulatory Commission
KPCo. .................................  Kentucky Power Company, a public utility subsidiary of AEP
LLWPA..................................  Low-Level Waste Policy Act of 1980
LPSC...................................  Louisiana Public Service Commission
MECPL..................................  Mutual Energy CPL, L.P., a Texas REP and former AEP
                                           affiliate
MEWTU..................................  Mutual Energy WTU, L.P., a Texas REP and former AEP
                                           affiliate
MISO...................................  Midwest Independent Transmission System Operator
Moody's................................  Moody's Investors Service, Inc.
</Table>

                                        i
<PAGE>

<Table>
<Caption>
        ABBREVIATION OR ACRONYM                                   DEFINITION
        -----------------------                                   ----------
<S>                                      <C>
MTM....................................  Marked-to-market
MW.....................................  Megawatt
NOx....................................  Nitrogen oxide
NPC....................................  National Power Cooperatives, Inc., an unaffiliated
                                           corporation
NRC....................................  Nuclear Regulatory Commission
OASIS..................................  Open Access Same-time Information System
OATT...................................  Open Access Transmission Tariff, filed with FERC
OCC....................................  Corporation Commission of the State of Oklahoma
Ohio Act...............................  Ohio electric restructuring legislation
OPCo. .................................  Ohio Power Company, a public utility subsidiary of AEP
OVEC...................................  Ohio Valley Electric Corporation, an electric utility
                                           company in which AEP and CSPCo together own a 44.2% equity
                                           interest
PJM....................................  PJM Interconnection, L.L.C.
Pro Serv...............................  AEP Pro Serv, Inc., a subsidiary of AEP
PSO....................................  Public Service Company of Oklahoma, a public utility
                                           subsidiary of AEP
PTB....................................  Price to beat, as defined by the Texas Act
PUCO...................................  The Public Utilities Commission of Ohio
PUCT...................................  Public Utility Commission of Texas
PUHCA..................................  Public Utility Holding Company Act of 1935, as amended
QF.....................................  Qualifying facility, as defined under the Public Utility
                                           Regulatory Policies Act of 1978
RCRA...................................  Resource Conservation and Recovery Act of 1976, as amended
REP....................................  Retail electricity provider
Rockport Plant.........................  A generating plant, consisting of two 1,300,000-kilowatt
                                           coal-fired generating units, near Rockport, Indiana
RTO....................................  Regional Transmission Organization
SEC....................................  Securities and Exchange Commission
S&P....................................  Standard & Poor's Ratings Service
SO(2)..................................  Sulfur dioxide
SO(2) Allowance........................  An allowance to emit one ton of sulfur dioxide granted under
                                           the Clean Air Act Amendments of 1990
SPP....................................  Southwest Power Pool
STPNOC.................................  STP Nuclear Operating Company, a non-profit Texas
                                           corporation which operates STP on behalf of its joint
                                           owners, including TCC
SWEPCo. ...............................  Southwestern Electric Power Company, a public utility
                                           subsidiary of AEP
TCA....................................  Transmission Coordination Agreement dated January 1, 1997 by
                                           and among, PSO, SWEPCo, TCC, TNC and AEPSC, which allocates
                                           costs and benefits in connection with the operation of the
                                           transmission assets of the four public utility
                                           subsidiaries
TCC....................................  AEP Texas Central Company, formerly Central Power and Light
                                           Company, a public utility subsidiary of AEP
TEA....................................  Transmission Equalization Agreement dated April 1, 1984 by
                                           and among APCo, CSPCo, I&M, KPCo and OPCo, which allocates
                                           costs and benefits in connection with the operation of
                                           transmission assets
Texas Act..............................  Texas electric restructuring legislation
TNC....................................  AEP Texas North Company, formerly West Texas Utilities
                                           Company, a public utility subsidiary of AEP
TVA....................................  Tennessee Valley Authority
UCOS...................................  Unbundled cost of service
Virginia Act...........................  Virginia electric restructuring legislation
VSCC...................................  Virginia State Corporation Commission
WVPSC..................................  West Virginia Public Service Commission
West Zone Companies of AEP.............  PSO, SWEPCo, TCC and TNC
</Table>

                                        ii
<PAGE>

FORWARD-LOOKING INFORMATION
- --------------------------------------------------------------------------------

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

     - Electric load and customer growth.

     - Abnormal weather conditions

     - Available sources and costs of fuels.

     - Availability of generating capacity.

     - The speed and degree to which competition is introduced to AEP's power
       generation business.

     - The ability to recover stranded costs in connection with
       possible/proposed deregulation of generation.

     - New legislation and government regulation

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

     - The ability of AEP to successfully control its costs.

     - The success of acquiring new business ventures and disposing of existing
       investments that no longer match AEP's corporate profile.

     - International and country-specific developments affecting AEP's foreign
       investments, including the disposition of any current foreign investments
       and potential additional foreign investments.

     - The economic climate and growth in AEP's service territory and changes in
       market demand and demographic patterns.

     - Inflationary trends.

     - Electricity and gas market prices.

     - Interest rates.

     - Liquidity in the banking, capital and wholesale power markets.

     - Actions of rating agencies.

     - Changes in technology, including the increased use of distributed
       generation within AEP's transmission and distribution service territory.

     - Other risks and unforeseen events, including wars, the effects of
       terrorism, embargoes and other catastrophic events.

                                        1
<PAGE>

PART I
- --------------------------------------------------------------------------------

Item 1. BUSINESS
- --------------------------------------------------------------------------------

GENERAL

OVERVIEW AND DESCRIPTION OF SUBSIDIARIES

     AEP was incorporated under the laws of the State of New York in 1906 and
reorganized in 1925. It is a registered public utility holding company under
PUHCA that owns, directly or indirectly, all of the outstanding common stock of
its public utility subsidiaries and varying percentages of other subsidiaries.

     The service areas of AEP's public utility subsidiaries cover portions of
the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma,
Tennessee, Texas, Virginia and West Virginia. The generating and transmission
facilities of AEP's public utility subsidiaries are interconnected, and their
operations are coordinated, as a single integrated electric utility system.
Transmission networks are interconnected with extensive distribution facilities
in the territories served. The public utility subsidiaries of AEP, which do
business as "American Electric Power," have traditionally provided electric
service, consisting of generation, transmission and distribution, on an
integrated basis to their retail customers. Restructuring legislation in
Michigan, Ohio, Texas and Virginia has caused or will cause AEP public utility
subsidiaries in those states to unbundle previously integrated regulated rates
for their retail customers.

     The AEP System is an integrated electric utility system and, as a result,
the member companies of the AEP System have contractual, financial and other
business relationships with the other member companies, such as participation in
the AEP System savings and retirement plans and tax returns, sales of
electricity and transportation and handling of fuel. The member companies of the
AEP System also obtain certain accounting, administrative, information systems,
engineering, financial, legal, maintenance and other services at cost from a
common provider, AEPSC.

     At December 31, 2002, the subsidiaries of AEP had a total of 22,083
employees. AEP, because it is a holding company rather than an operating
company, has no employees. The public utility subsidiaries of AEP are:

       APCo (organized in Virginia in 1926) is engaged in the generation,
  transmission and distribution of electric power to approximately 925,000
  retail customers in the southwestern portion of Virginia and southern West
  Virginia, and in supplying and marketing electric power at wholesale to other
  electric utility companies, municipalities and other market participants. At
  December 31, 2002, APCo and its wholly owned subsidiaries had 2,520 employees.
  Among the principal industries served by APCo are coal mining, primary metals,
  chemicals and textile mill products. In addition to its AEP System
  interconnections, APCo also is interconnected with the following unaffiliated
  utility companies: Carolina Power & Light Company, Duke Energy Corporation and
  Virginia Electric and Power Company. APCo has several points of
  interconnection with TVA and has entered into agreements with TVA under which
  APCo and TVA interchange and transfer electric power over portions of their
  respective systems.

       CSPCo (organized in Ohio in 1937, the earliest direct predecessor company
  having been organized in 1883) is engaged in the generation, transmission and
  distribution of electric power to approximately 689,000 retail customers in
  Ohio, and in supplying and marketing electric power at wholesale to other
  electric utilities, municipalities and other market participants. At December
  31, 2002, CSPCo had 1,171 employees. CSPCo's service area is comprised of two
  areas in Ohio, which include portions of twenty-five counties. One area
  includes the City of Columbus and the other is a predominantly rural area in
  south central Ohio. Among the principal industries served are food processing,
  chemicals, primary metals, electronic machinery and paper products. In
  addition to its AEP System interconnections, CSPCo also is interconnected with
  the following unaffiliated utility companies: CG&E, DP&L and Ohio Edison
  Company.

       I&M (organized in Indiana in 1925) is engaged in the generation,
  transmission and distribution of electric power to approximately 571,000
  retail customers in northern and eastern Indiana and southwestern Michigan,
  and in supplying and marketing electric power at wholesale to other electric
  utility companies, rural electric cooperatives, municipalities and other
  market participants. At December 31, 2002, I&M had 2,667 employees. Among the
  principal industries served are primary metals, transportation equipment,
  electrical and electronic

                                        2
<PAGE>

  machinery, fabricated metal products, rubber and miscellaneous plastic
  products and chemicals and allied products. Since 1975, I&M has leased and
  operated the assets of the municipal system of the City of Fort Wayne,
  Indiana. In addition to its AEP System interconnections, I&M also is
  interconnected with the following unaffiliated utility companies: Central
  Illinois Public Service Company, CG&E, Commonwealth Edison Company, Consumers
  Energy Company, Illinois Power Company, Indianapolis Power & Light Company,
  Louisville Gas and Electric Company, Northern Indiana Public Service Company,
  PSI Energy Inc. and Richmond Power & Light Company.

       KPCo (organized in Kentucky in 1919) is engaged in the generation,
  transmission and distribution of electric power to approximately 174,000
  retail customers in an area in eastern Kentucky, and in supplying and
  marketing electric power at wholesale to other electric utility companies,
  municipalities and other market participants. At December 31, 2002, KPCo had
  412 employees. In addition to its AEP System interconnections, KPCo also is
  interconnected with the following unaffiliated utility companies: Kentucky
  Utilities Company and East Kentucky Power Cooperative Inc. KPCo is also
  interconnected with TVA.

       Kingsport Power Company (organized in Virginia in 1917) provides electric
  service to approximately 46,000 retail customers in Kingsport and eight
  neighboring communities in northeastern Tennessee. Kingsport Power Company
  does not own any generating facilities. It purchases electric power from APCo
  for distribution to its customers. At December 31, 2002, Kingsport Power
  Company had 57 employees.

       OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is engaged
  in the generation, transmission and distribution of electric power to
  approximately 702,000 retail customers in the northwestern, east central,
  eastern and southern sections of Ohio, and in supplying and marketing electric
  power at wholesale to other electric utility companies, municipalities and
  other market participants. At December 31, 2002, OPCo had 1,988 employees.
  Among the principal industries served by OPCo are primary metals, rubber and
  plastic products, stone, clay, glass and concrete products, petroleum refining
  and chemicals. In addition to its AEP System interconnections, OPCo also is
  interconnected with the following unaffiliated utility companies: CG&E, The
  Cleveland Electric Illuminating Company, DP&L, Duquesne Light Company,
  Kentucky Utilities Company, Monongahela Power Company, Ohio Edison Company,
  The Toledo Edison Company and West Penn Power Company.

       PSO (organized in Oklahoma in 1913) is engaged in the generation,
  transmission and distribution of electric power to approximately 505,000
  retail customers in eastern and southwestern Oklahoma, and in supplying and
  marketing electric power at wholesale to other electric utility companies,
  municipalities, rural electric cooperatives and other market participants. At
  December 31, 2002, PSO had 998 employees. Among the principal industries
  served by PSO are natural gas and oil production, oil refining, steel
  processing, aircraft maintenance, paper manufacturing and timber products,
  glass, chemicals, cement, plastics, aerospace manufacturing,
  telecommunications, and rubber goods. In addition to its AEP System
  interconnections, PSO also is interconnected with Ameren Corporation, Empire
  District Electric Co., Oklahoma Gas & Electric Co., Southwestern Public
  Service Co. and Westar Energy Inc.

       SWEPCo (organized in Delaware in 1912) is engaged in the generation,
  transmission and distribution of electric power to approximately 437,000
  retail customers in northeastern Texas, northwestern Louisiana and western
  Arkansas, and in supplying and marketing electric power at wholesale to other
  electric utility companies, municipalities, rural electric cooperatives and
  other market participants. At December 31, 2002, SWEPCo had 1,372 employees.
  Among the principal industries served by SWEPCo are natural gas and oil
  production, petroleum refining, manufacturing of pulp and paper, chemicals,
  food processing, and metal refining. The territory served by SWEPCo also
  includes several military installations, colleges, and universities. In
  addition to its AEP System interconnections, SWEPCo is also interconnected
  with CLECO Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas
  & Electric Co.

       TCC (organized in Texas in 1945) is engaged in the generation,
  transmission and sale of power to affiliated and non-affiliated entities and
  the distribution of electric power to approximately 689,000 retail customers
  through REPs in southern Texas, and in supplying and marketing electric power
  at wholesale to other electric utility companies, municipalities, rural
  electric cooperatives and other market

                                        3
<PAGE>

  participants. At December 31, 2002, TCC had 1,248 employees. Among the
  principal industries served by TCC are oil and gas extraction, food
  processing, apparel, metal refining, chemical and petroleum refining,
  plastics, and machinery equipment. In addition to its AEP System
  interconnections, TCC is a member of ERCOT.

       TNC (organized in Texas in 1927) is engaged in the generation,
  transmission and sale of power to affiliated and non-affiliated entities and
  the distribution of electric power to approximately 189,000 retail customers
  through REPs in west and central Texas, and in supplying and marketing
  electric power at wholesale to other electric utility companies,
  municipalities, rural electric cooperatives and other market participants. At
  December 31, 2002, TNC had 595 employees. The principal industry served by TNC
  is agriculture. The territory served by TNC also includes several military
  installations and correctional facilities. In addition to its AEP System
  interconnections, TNC is a member of ERCOT.

       Wheeling Power Company (organized in West Virginia in 1883 and
  reincorporated in 1911) provides electric service to approximately 41,000
  retail customers in northern West Virginia. Wheeling Power Company does not
  own any generating facilities. It purchases electric power from OPCo for
  distribution to its customers. At December 31, 2002, Wheeling Power Company
  had 59 employees.

       AEGCo (organized in Ohio in 1982) is an electric generating company.
  AEGCo sells power at wholesale to I&M and KPCo. AEGCo has no employees.

 Service Company Subsidiary

     AEP also owns a service company subsidiary, AEPSC. AEPSC provides
accounting, administrative, information systems, engineering, financial, legal,
maintenance and other services at cost to the AEP System companies. The
executive officers of AEP and its public utility subsidiaries are all employees
of AEPSC. At December 31, 2002, AEPSC had 6,548 employees.

CLASSES OF SERVICE
     The principal classes of service from which the public utility subsidiaries
of AEP derive revenues and the amount of such revenues during the year ended
December 31, 2002 are as follows:

<Table>
<Caption>
                                           AEP
                                        SYSTEM(A)       APCo        CSPCo         I&M         KPCo
                                       -----------   ----------   ----------   ----------   ---------
                                                         (IN THOUSANDS)
<S>                                    <C>           <C>          <C>          <C>          <C>
Wholesale Business:
  Residential........................  $ 3,713,000   $  616,509   $  533,061   $  371,329   $ 118,654
  Commercial.........................    2,156,000      276,238      442,847      224,843      50,075
  Industrial.........................    1,903,000      353,841      138,174      330,428      96,716
  Other Retail Customers.............      385,000       80,429       38,018       61,450      16,911
  Energy Delivery....................   (3,551,000)    (594,089)    (492,278)    (321,721)   (132,054)
                                       -----------   ----------   ----------   ----------   ---------
     Total Retail....................    4,606,000      732,928      659,822      666,329     150,302
  Marketing and
     Trading-Electricity.............    2,227,000      204,878      134,836      279,705      50,056
  Marketing and Trading-Gas..........    3,021,000            0            0            0           0
  Unrealized MTM Income:
     Electric........................      136,000       18,089       13,388            0           0
     Gas.............................     (399,000)           0            0            0           0
  Other..............................    1,397,000      264,486       99,836      259,009      46,271
                                       -----------   ----------   ----------   ----------   ---------
     Total Wholesale Business........   10,988,000    1,220,381      907,882    1,205,043     246,629
                                       -----------   ----------   ----------   ----------   ---------
Energy Delivery Business:
  Transmission.......................      922,000      186,960      107,673      118,812      50,381
  Distribution.......................    2,629,000      407,129      384,605      202,909      81,673
                                       -----------   ----------   ----------   ----------   ---------
     Total Energy Delivery...........    3,551,000      594,089      492,278      321,721     132,054
                                       -----------   ----------   ----------   ----------   ---------
     Total Other Investments.........       16,000            0            0            0           0
                                       -----------   ----------   ----------   ----------   ---------
       Total Revenues................  $14,555,000   $1,814,470   $1,400,160   $1,526,764   $ 378,683
                                       ===========   ==========   ==========   ==========   =========
</Table>

                                        4
<PAGE>

<Table>
<Caption>
                                             OPCo         PSO        SWEPCo        TCC         TNC
                                          ----------   ---------   ----------   ----------   --------
                                                                (IN THOUSANDS)
<S>                                       <C>          <C>         <C>          <C>          <C>
Wholesale Business:
  Residential...........................  $  475,210   $ 315,711   $  313,023   $   49,210   $  8,651
  Commercial............................     244,943     218,718      212,626       32,518      4,098
  Industrial............................     531,085     162,386      214,622       12,395      2,134
  Other Retail Customers................      71,737      38,998       33,104        3,594      1,638
  Energy Delivery.......................    (589,673)   (275,547)    (348,236)    (554,547)   (73,353)
                                          ----------   ---------   ----------   ----------   --------
     Total Retail.......................     733,302     460,266      425,139     (456,830)   (56,832)
  Marketing and Trading-Electricity.....     219,488      17,394      157,159      811,800    283,883
  Marketing and Trading-Gas.............           0           0            0            0          0
  Unrealized MTM Income:
     Electric...........................      25,574           0       (3,686)      (8,490)    (1,473)
     Gas................................           0           0            0            0          0
  Other.................................     545,088      40,440      157,872      789,466    151,809
                                          ----------   ---------   ----------   ----------   --------
     Total Wholesale Business...........   1,523,452     518,100      736,484    1,135,946    377,387
                                          ----------   ---------   ----------   ----------   --------
Energy Delivery Business:
  Transmission..........................     162,660      63,178       92,076       68,003     25,273
  Distribution..........................     427,013     212,369      256,160      486,544     48,080
                                          ----------   ---------   ----------   ----------   --------
     Total Energy Delivery..............     589,673     275,547      348,236      554,547     73,353
                                          ----------   ---------   ----------   ----------   --------
     Total Other Investments............           0           0            0            0          0
                                          ----------   ---------   ----------   ----------   --------
       Total Revenues...................  $2,113,125   $ 793,647   $1,084,720   $1,690,493   $450,740
                                          ==========   =========   ==========   ==========   ========
</Table>

- ---------------

(a) Includes revenues of other subsidiaries not shown. Intercompany transactions
    have been eliminated, including AEGCo's total revenues of $213,281,000 for
    the year ended December 31, 2002, all of which resulted from its wholesale
    business, including its marketing and trading of power.

REGULATION

     Except for retail generation sales in Ohio, Virginia and the ERCOT area of
Texas, AEP's public utility subsidiaries' retail rates and certain other matters
are subject to traditional regulation by the state utility commissions. Retail
sales in Michigan, while still regulated, are now made at unbundled rates. Other
states in AEP's service territory have also passed restructuring legislation
that has not been implemented or has been repealed. See Electric Restructuring
and Customer Choice Legislation and Energy Delivery--Regulation--Rates. AEP's
subsidiaries are also subject to regulation by the FERC under the FPA. I&M and
TCC are subject to regulation by the NRC under the Atomic Energy Act of 1954, as
amended, with respect to the operation of the Cook Plant and STP, respectively.
AEP and its subsidiaries are also subject to the broad regulatory provisions of
PUHCA administered by the SEC.

 FERC

     Under the FPA, FERC regulates rates for interstate sales at wholesale,
transmission of electric power, accounting and other matters, including
construction and operation of hydroelectric projects. FERC regulations require
AEP to provide open access transmission service at FERC-approved rates. The
transmission service regulated by FERC is predominantly wholesale transmission
service, which is service not associated with bundled electricity sales to
retail customers. FERC also regulates unbundled transmission service to retail
customers.

     Under the FPA, the FERC regulates the sale of power for resale in
interstate commerce by (i) approving contracts for wholesale sales to municipal
and cooperative utilities and (ii) granting authority to public utilities to
sell power at wholesale at market-based rates upon a showing that the seller
lacks the ability to improperly influence market prices. AEP has

                                        5
<PAGE>

market-rate authority from FERC, under which most of its wholesale marketing
activity takes place. In November 2001, the FERC issued an order in connection
with its triennial review of AEP's market based pricing authority requiring (i)
certain actions by AEP in connection with its sales and purchases within its
control area and (ii) posting of information related to generation facility
status on AEP's website. AEP has appealed this order, and the FERC has issued an
order delaying the effective date of the order. See Note 9 to the consolidated
financial statements, entitled Commitments and Contingencies, incorporated by
reference in Item 8, for more information on the current status of this
proceeding.

 SEC

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

     PUHCA and the rules and orders of the SEC currently require that
transactions between associated companies in a registered holding company system
be performed at cost with limited exceptions. Over the years, the AEP System has
developed numerous affiliated service, sales and construction relationships and,
in some cases, invested significant capital and developed significant operations
in reliance upon the ability to recover its full costs under these provisions.

     The Division of Investment Management of the SEC has recommended the
conditional repeal of PUHCA. Under its recommendation, certain oversight
authority would be transferred to the FERC. Legislation has since been
introduced in numerous sessions of Congress that would repeal PUHCA, but such
legislation has not passed.

AEP-CSW MERGER

     On June 15, 2000, CSW (now known as AEP Utilities, Inc.) merged with and
into a wholly-owned merger subsidiary of AEP. As a result, CSW became a wholly
owned subsidiary of AEP. The four wholly owned public utility subsidiaries of
CSW--PSO, SWEPCo, TCC and TNC--became indirect wholly owned public utility
subsidiaries of AEP as a result of the merger. The merger was approved by the
FERC and the SEC (with respect to PUHCA).

     On January 18, 2002, the U.S. Court of Appeals for the District of Columbia
ruled that the SEC failed to properly explain how the merger met the
requirements of PUHCA and remanded the case to the SEC for further review. The
court held that the SEC had not adequately explained its conclusions that the
merger met PUHCA requirements that the merging entities be "physically
interconnected" and that the combined entity was confined to a "single area or
region."

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

ELECTRIC RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION

     Certain states in AEP's service area have adopted restructuring or customer
choice legislation. In general, this legislation provides for a transition from
bundled cost-based rate regulated electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan, Virginia and the ERCOT area of Texas. Electric
restructuring in the SPP area of Texas, also scheduled to begin on January 1,
2002, has been delayed by the PUCT. AEP's public utility subsidiaries operate in
both the ERCOT and SPP areas of Texas.

     Implementation of legislation enacted in Oklahoma and West Virginia to
allow retail customers to choose their electricity supplier is on hold. In 2001
Oklahoma delayed implementation of customer choice indefinitely. Before West
Virginia's choice plan can be effective, tax legislation must be passed to
preserve pre-legislation levels of funding for state and local governments. No
further legislation has been passed related to restructuring in West Virginia.
In February 2003, Arkansas repealed its restructuring legislation.

     See Note 7 to the consolidated financial statements, entitled Effects of
Regulation, incorporated by reference in Item 8, for a discussion of the effect
of restructuring and customer choice legislation on accounting procedures. See
Management's Discussion

                                        6
<PAGE>

and Analysis of Results of Operations and Financial Condition, under the
headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.

 Michigan Customer Choice

     Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Rates for retail electric service for I&M's Michigan customers were unbundled
(though they continue to be regulated) to allow customers the ability to
evaluate the cost of generation service for comparison with other suppliers. At
December 31, 2002, none of I&M's Michigan customers had elected to change
suppliers and no alternative electric suppliers are registered to compete in
I&M's Michigan service territory.

 Ohio Restructuring

     The Ohio Act requires vertically integrated electric utility companies that
offer competitive retail electric service in Ohio to separate their generating
functions from their transmission and distribution functions. Following the
market development period (which will terminate no later than December 31,
2005), retail customers will receive distribution and, where applicable,
transmission service from the incumbent utility whose distribution rates will be
approved by the PUCO and whose transmission rates will be approved by the FERC.
See General--Regulation--FERC for a discussion of FERC regulation of
transmission rates and Energy Delivery--Regulation--Rates--Ohio for a discussion
of the impact of restructuring on distribution rates.

     CSPCo and OPCo are each presently operating as functionally separated
electric utility companies and no longer charge bundled rates for retail
electric service. Each has sought and, from certain regulatory authorities,
obtained regulatory approval to legally separate its transmission and
distribution assets from its generation assets. CSPCo and OPCo are, however,
currently determining the regulatory feasibility of complying with restructuring
legislation through continued functional separation. Assuming regulatory
compliance, it is currently their intention to remain functionally separated.

 Texas Restructuring

     The Texas Act substantially amends the regulatory structure governing
electric utilities in Texas in order to allow retail electric competition for
all customers and requires each utility to separate into (i) a REP, (ii) a power
generation company and (iii) a transmission and distribution utility. Upon
separation, neither the REP nor the power generation company will be subject to
traditional cost of service rate regulation. See Energy Delivery--Regulation--
Rates--Texas for a discussion of the impact of restructuring on rates.

     SWEPCo, TCC and TNC initially filed a restructuring plan in January 2000
(which they subsequently updated) that the PUCT approved in February 2002. The
updated restructuring plan provided for the legal separation of TCC's and TNC's
assets in accordance with the Texas Act into (i) an affiliate power generation
company, (ii) a transmission and distribution utility and (iii) various REPs,
including those subsequently purchased by Centrica (see below). TCC and TNC
continue to pursue legal separation as required by the Texas Act. The PUCT has
delayed the implementation of the plan for SWEPCo operations within the SPP area
of Texas.

     Under the Texas Act, a REP, which itself cannot own any generation assets,
obtains its electricity from power generation companies, EWGs and other
generating entities and provides services at generally unregulated rates, except
that the prices that may be charged to residential and small commercial
customers by REPs affiliated with a utility within the affiliated utility's
service area are set by the PUCT until January 1, 2007. This set price is
referred to as the "price to beat" rate (PTB). Affiliate REPs are required to
offer the PTB rate to all residential and small commercial customers (with a
peak usage of less than 1,000 KW) effective January 1, 2002. As described below,
AEP sold its affiliate REPs that must provide PTB service. The PTB rate is still
relevant to AEP, however, in determining (i) the contingent portion of the sales
price of the affiliate REPs AEP sold and (ii) certain of AEP's obligations in
the 2004 true-up proceedings.

     Prior to the start of retail competition in January 2002, AEP formed MECPL
and MEWTU to act as affiliate REPs for TCC and TNC respectively. MECPL and MEWTU
were sold in December 2002 to Centrica, which assumed all of the rights and
obligations of an affiliated REP, including the provision of PTB service and the
obligation to provide data necessary for TCC's and TNC's 2004 true-up
proceeding. In connection with the sale, TCC and TNC have contracted to supply
approximately 90% of MECPL's and
                                        7
<PAGE>

MEWTU's respective power requirements relating to former TCC and TNC PTB
customers for a two-year period. See Note 12 to the consolidated financial
statements, entitled Acquisitions, Distributions and Discontinued Operations,
incorporated by reference in Item 8, for more information on the sale of these
REPs and AEP's contractual rights and obligations in connection with the sale.

     The Texas Act also allows certain transmission and distribution utilities
whose generation assets were unbundled to recover certain regulatory assets and
stranded costs related to their generation assets. For a discussion of (i)
regulatory assets and stranded costs subject to recovery by TCC and (ii) rate
adjustments made after implementation of restructuring to allow recovery of
certain costs by or with respect to TCC and TNC, see Energy Delivery--Regulatory
Assets, Stranded Cost Recovery and Certain Post-Restructuring Rate Adjustments.

 Virginia Restructuring

     The Virginia Act was enacted in 1999 providing for retail choice of
generation suppliers to be phased in over the January 1, 2002 to January 1, 2004
period. The Virginia Act required jurisdictional utilities to unbundle their
power supply and energy delivery rates and to file functional separation plans
by January 1, 2002. APCo filed its plan and, following VSCC approval of a
settlement agreement, now operates in Virginia as a functionally separated
electric utility charging unbundled rates for its retail sales of electricity.
The settlement agreement addressed functional separation, leaving decisions
related to legal separation for later VSCC consideration.

FINANCING

 General

     AEP's goal is to use cash from operations to fund capital expenditures,
dividends and working capital. Short-term debt is used as an interim bridge for
timing differences in the need for cash or to fund debt maturities until
permanent financing is arranged.

     It has been the practice of AEP's operating subsidiaries to finance current
construction expenditures in excess of available cash from operations by
initially incurring short-term debt, up to levels authorized by regulatory
agencies, and then to reduce the short-term debt with the proceeds of subsequent
sales by such subsidiaries of long-term debt securities and cash capital
contributions by AEP. In the past, short-term debt has come from AEP's
commercial paper program and revolving credit facilities. Proceeds were loaned
to the subsidiaries through intercompany notes under the AEP money pool. The
recent downgrade of AEP's commercial paper rating by Moody's, described below,
may limit AEP's access to commercial paper on terms as favorable as those of
recent years. Therefore, AEP may establish commercial paper programs for certain
of its public utility subsidiaries and AEP Utilities. Certain public utility
subsidiaries of AEP also sell accounts receivable to provide liquidity.

     AEP's revolving credit agreements (which backstop the commercial paper
program) include covenants and events of default typical for this type of
facility, including a maximum debt/capital test and a $50 million
cross-acceleration provision. At December 31, 2002, AEP was in compliance with
its debt covenants. With the exception of a voluntary bankruptcy or insolvency,
any event of default has either or both a cure period or notice requirement
before termination of the agreements. A voluntary bankruptcy or insolvency would
be considered an immediate termination event.

     AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as leasing arrangements, including the
leasing of utility assets and coal mining and transportation equipment and
facilities.

 Credit Ratings

     The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries. The agencies are also reviewing many companies in the
energy sector due to issues that impact the entire industry.

     In February 2003 Moody's completed its review of AEP and its rated
subsidiaries. The results of that review were downgrades of the following
ratings for unsecured debt: AEP from Baa2 to Baa3, APCo from Baa1 to Baa2, TCC
from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1. TNC, which had
no senior unsecured notes outstanding at the time of the ratings action, had its
mortgage bond debt downgraded from A2 to A3. AEP's commercial paper was also
concurrently downgraded from P-2 to P-3. The completion of this review was a
culmination of earlier ratings action in 2002 that had included a downgrade of
AEP from Baa1 to Baa2. With the completion of the reviews, Moody's has placed
AEP and its rated subsidiaries on stable outlook.

                                        8
<PAGE>

     In March 2003 S&P completed its review of AEP and its rated subsidiaries.
The results of that review were downgrades of the ratings for unsecured debt for
AEP and its rated subsidiaries from BBB+ to BBB. AEP's commercial paper rating
was affirmed at A-2. With the completion of the reviews, S&P has placed AEP and
its rated subsidiaries on stable outlook.

     In March 2003 Fitch completed its review of AEP. The result of that review
was a downgrade of AEP's unsecured debt rating from BBB+ to BBB. AEP's
commercial paper rating was affirmed at F-2. With the completion of the reviews,
Fitch has placed AEP and its rated subsidiaries on stable outlook.

     See Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters, incorporated by reference in Item 7, under the
heading entitled Financial Condition for additional information with respect to
AEP's credit ratings, liquidity and specific financing activities.

ENVIRONMENTAL AND OTHER MATTERS

   General

     AEP's subsidiaries are currently subject to regulation by federal, state
and local authorities with regard to air and water-quality control and other
environmental matters, and are subject to zoning and other regulation by local
authorities. The environmental issues that are potentially material to the AEP
system include:

     - The CAA and CAAA and state laws and regulations (including State
       Implementation Plans) that require compliance, obtaining permits and
       reporting as to air emissions.

     - Litigation with the federal and certain state governments and certain
       special interest groups regarding whether modifications to or maintenance
       of certain coal-fired generating plants required additional permitting or
       pollution control technology. See Management's Discussion and Analysis of
       Financial Condition, Accounting Policies and Other Matters under the
       heading entitled Federal EPA Complaint and Notice of Violation and Note 9
       to the consolidated financial statements entitled Commitments and
       Contingencies, incorporated by reference in Items 7 and 8 respectively
       for further information.

     - Rules issued by the EPA and certain states that require substantial
       reductions in NOx emissions. The compliance dates for these rules range
       from 2003 to 2005. AEP is installing (or has installed) emission control
       technology and is taking other measures to comply with required
       reductions. See Management's Discussion and Analysis of Financial
       Condition, Accounting Policies and Other Matters and Note 9 to the
       consolidated financial statements entitled Commitments and Contingencies,
       incorporated by reference in Items 7 and 8 respectively, under the
       heading entitled NOx Reductions for further information.

     - CERCLA, which imposes upon owners and previous owners of sites, as well
       as transporters and generators of hazardous material disposed of at such
       sites, costs for environmental remediation. AEP does not, however,
       anticipate that any of its currently identified CERCLA-related issues
       will result in material costs or penalties to the AEP System. See
       Management's Discussion and Analysis of Financial Condition, Accounting
       Policies and Other Matters, incorporated by reference in Item 7, under
       the heading entitled Superfund for further information.

     - The Federal Clean Water Act, which prohibits the discharge of pollutants
       into waters of the United States except pursuant to appropriate permits.
       There are, however, no matters material to the AEP System currently
       pending under the Clean Water Act.

     - Solid and hazardous waste laws and regulations, which govern the
       management and disposal of certain wastes. The majority of solid waste
       created from the combustion of coal and fossil fuels is fly ash and other
       coal combustion byproducts, which the EPA has determined are not
       hazardous waste governed subject to RCRA.

     In addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions.

     AEP's subsidiaries will confront several new environmental policies and
regulations over the next decade with the potential for substantial control
costs and premature retirement of some generating plants. These could include
(i) new or additional controls on sulfur dioxide, NOx and mercury emissions from
future laws or regulations, or the possibility of an

                                        9
<PAGE>

adverse decision in the new source review litigation; (ii) a new Clean Water Act
rule to reduce fish and other aquatic organisms killed at once-through cooled
power plants; (iii) finalization and implementation of more stringent water
quality-based permit limits; and (iv) a possible future requirement to reduce
carbon dioxide emissions. See Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters, incorporated by reference in
Item 7, under the heading entitled Environmental Concerns and Issues for
information on current environmental issues.

     AEP expects costs related to environmental controls to eventually be
reflected in some jurisdictions in the rates of AEP's public utility
subsidiaries. In Michigan, Ohio, Texas and Virginia, those costs may not be
recoverable if future market prices for electricity generated by plants in those
jurisdictions are insufficient to permit AEP to recover such costs. Moreover,
legislation adopted by certain states and proposed at the state and federal
level governing restructuring of the electric utility industry may also affect
the recovery of certain of these costs. There can be no assurance that these
costs will be recovered.

     AEP's international operations are subject to environmental regulation by
various authorities within the host countries. Under certain circumstances,
these authorities may require modifications to these facilities and operations
or impose fines and other costs for violations of applicable statutes and
regulations. From time to time, these operations are named as parties to various
legal claims, actions, complaints or other proceedings related to environmental
matters. AEP's UK generation facilities will be subject to additional
environmental constraints in 2008 (which become more stringent after 2015)
because they are subject to regulation governing large combustion plants. In the
fourth quarter of 2002, AEP decided not to install certain emission control
technology on its Fiddler's Ferry and Ferrybridge generation facilities in 2008.
This decision and its legal and regulatory consequences will result in a
significant reduction in the estimated economic life of those facilities.

     The cost of complying with applicable environmental laws, regulations and
rules is expected to be material to the AEP System.

     See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements entitled
Commitments and Contingencies, incorporated by reference in Items 7 and 8,
respectively, for further information with respect to environmental matters.

 Environmental Expenditures

     Expenditures related to generation facility compliance with air and water
quality standards during 2001 and 2002 and the current estimate for 2003 are
shown below. Substantial expenditures in addition to the amounts set forth below
may be required by the System in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls in order to comply with air and water quality standards which
have been or may be adopted. Future expenditures could be significantly greater
if litigation regarding whether AEP properly installed emission control
equipment on its plants is resolved against AEP. See Note 9 to the consolidated
financial statements, entitled Commitments and Contingencies, incorporated by
reference in Item 8, for more information regarding this litigation and
environmental expenditures in general.

<Table>
<Caption>
                         2001       2002       2003
                        ACTUAL     ACTUAL    ESTIMATE
                       --------   --------   --------
                               (IN THOUSANDS)
<S>                    <C>        <C>        <C>
AEGCo................  $  3,500   $  1,200   $ 11,200
APCo.................    99,200    108,400     65,700
CSPCo................    22,500     25,400     39,300
I&M..................       700      1,200     18,500
KPCo.................    11,200    110,600     39,900
OPCo.................   125,300    110,300     53,100
PSO..................       400      1,200        100
SWEPCo...............     9,200      3,400      9,000
TCC..................     2,500        600          0
TNC..................       800      1,900          0
                       --------   --------   --------
AEP System...........  $275,300   $364,200   $236,800
                       ========   ========   ========
</Table>

 Electric and Magnetic Fields

     EMF are found everywhere there is electricity. Electric fields are created
by the presence of electric charges. Magnetic fields are produced by the flow of
those charges. This means that EMF is created by electricity flowing in
transmission and distribution lines, electrical equipment, household wiring, and
appliances.

     A number of studies in the past several years have examined the possibility
of adverse health effects from EMF. While some of the epidemiological studies
have indicated some association between exposure to
                                        10
<PAGE>

EMF and health effects, none has produced any conclusive evidence that EMF does
or does not cause adverse health effects.

     Management cannot predict the ultimate impact of the question of EMF
exposure and adverse health effects. If further research shows that EMF exposure
contributes to increased risk of cancer or other health problems, or if the
courts conclude that EMF exposure harms individuals and that utilities are
liable for damages, or if states limit the strength of magnetic fields to such a
level that the current electricity delivery system must be significantly
changed, then the results of operations and financial condition of AEP and its
operating subsidiaries could be materially adversely affected unless these costs
can be recovered from customers.

WHOLESALE OPERATIONS

GENERAL

     AEP conducts its wholesale business operations through its public utility
subsidiaries (through which AEP also conducts its energy delivery operations),
AEPES, AEPR and Pro Serv. Wholesale operations use and manage the following
assets:

     - Power generation facilities (or interests therein) owned by AEP's public
       utility and other subsidiaries;

     - Natural gas pipeline, storage and processing facilities;

     - Coal mines and related facilities; and

     - Barge, rail and other fuel transportation related assets.

     Wholesale operations include the following activities:

     - Through AEP's public utility subsidiaries, the generation and sale of
       power (i) to retail customers at unbundled or bundled rates regulated at
       least in part by state public utility commissions and (ii) at wholesale
       at rates regulated, in certain instances, by the FERC.

     - Trading and marketing energy commodities in transactions predominantly
       limited to risk management around assets used or managed by AEP's
       wholesale operations, including electric power, natural gas, natural gas
       liquids, oil, coal, and SO(2) allowances in North America and, where
       applicable, Europe. Electric power transactions in the United States are
       conducted principally through AEP's public utility subsidiaries. Other
       energy commodity and allowances transactions are conducted through AEPES
       and AEPR.

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

     - Through Pro Serv, providing engineering, construction, project management
       and other consulting services for energy-related projects.

     In October 2002 AEP announced its plans to reduce the exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope and size, will generally be limited to risk management around
AEP's assets and, accordingly, focused in those regions in which AEP owns
assets.

POWER GENERATION

 General

     Power generation accounts for the majority of wholesale operations revenue.
In 2002, on an as-reported basis, power generation revenue included the
following components: (i) 63% from retail sales at predominantly regulated
rates; (ii) 33% from power marketing transactions of a type AEP intends to
continue and which are regulated in certain instances by the FERC; (iii) 3% from
retail sales at rates not regulated by states; and (iv) 1% attributable to power
marketing transactions of a type that management has stated are transitional.
This final category of transactions will be reduced consistent with AEP's
decision to scale back certain trading and marketing operations as described in
the preceding paragraph.

     AEP's public utility subsidiaries own approximately 38,000 MW of domestic
generation. See Deactivation and Planned Disposition of Generating Facilities
for a discussion of planned reductions in AEP's generating fleet. Other AEP
subsidiaries hold interests in entities owning 1,879 MW of domestic power
facilities and 5,235 MW of international power facilities. The AEP public
utility subsidiaries operate their generating plants as a single interconnected
and coordinated electric utility system. See Item 2 - Properties for more
information regarding generation facilities.

                                        11
<PAGE>

 AEP Power Pool and CSW Operating Agreement

     APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (Interconnection Agreement), defining
how they share the costs and benefits associated with their generating plants.
This sharing is based upon each company's "member-load-ratio."

     The member-load ratio is calculated monthly by dividing such company's
highest monthly peak demand for the last twelve months by the aggregate of the
highest monthly peak demand for the last twelve months for all east zone
operating companies. As of December 31, 2002, the member-load ratios were as
follows:

<Table>
<Caption>
                            PEAK
                           DEMAND   MEMBER-LOAD
                            (KW)     RATIO (%)
                           ------   -----------
<S>                        <C>      <C>
APCo.....................  6,010       28.2
CSPCo....................  4,040       19.0
I&M......................  4,323       20.3
KPCo.....................  1,551        7.3
OPCo.....................  5,360       25.2
</Table>

     Although the FERC has approved the right of withdrawal of CSPCo and OPCo
from the AEP Power Pool as part of its order approving the settlement agreements
and AEP's FERC restructuring application, CSPCo and OPCo have remained a party
to the AEP Power Pool. If CSPCo and OPCo continue to remain in the AEP Power
Pool, notification to or approval by the FERC may be required. See Management's
Discussion and Analysis of Results of Operations and Financial Condition, under
the headings entitled Industry Restructuring and Corporate Separation for a
discussion of AEP's corporate separation plan filed with the FERC and related
settlement agreements with state commissions and other intervenors.

     The following table shows the net credits or (charges) allocated among the
parties under the Interconnection Agreement and AEP System Interim Allowance
Agreement during the years ended December 31, 2000, 2001 and 2002:

<Table>
<Caption>
                         2000        2001        2002
                       ---------   ---------   ---------
                                (IN THOUSANDS)
<S>                    <C>         <C>         <C>
APCo. ...............  $(274,000)  $(256,700)  $(127,000)
CSPCo................   (250,400)   (251,200)   (267,000)
I&M..................     93,900     166,200     113,600
KPCo. ...............    (21,500)    (27,600)    (46,500)
OPCo. ...............    452,000     369,300     326,900
</Table>

     PSO, SWEPCo, TCC and TNC, and AEPSC are parties to a Restated and Amended
Operating Agreement originally dated as of January 1, 1997 (CSW Operating
Agreement). The CSW Operating Agreement requires the west zone public utility
subsidiaries to maintain specified annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other AEP west zone subsidiaries as capacity
commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center.

     The following table shows the net credits or (charges) allocated among the
parties under the CSW Operating Agreement during the years ended December 31,
2000, 2001 and 2002:

<Table>
<Caption>
                        2000      2001       2002
                       -------   -------   --------
                              (IN THOUSANDS)
<S>                    <C>       <C>       <C>
PSO..................  $(9,000)  $(6,500)  $(53,700)
SWEPCo...............   55,400    62,300     67,800
TCC..................    3,600   (13,500)    15,400
TNC..................  (50,000)  (42,300)   (29,500)
</Table>

     Power generated by or allocated or provided under the Interconnection
Agreement or CSW Operating Agreement to any public utility subsidiary is often
sold to customers (or in the case of the ERCOT area of Texas, REPs) by such
public utility subsidiary at rates approved (other than in the ERCOT area of
Texas) by the public utility commission in the jurisdiction of sale. In Ohio,
Virginia and the ERCOT area of Texas, such rates are based on a statutory
formula as those jurisdictions transition to the use of market rates for
generation. See Energy Delivery -- Regulation -- Rates.

     Under the Interconnection Agreement, power allocated to a public utility
subsidiary that is not required to serve its native load is sold at wholesale on
behalf of such subsidiary. Under the CSW Operating Agreement, power generated
that is not needed to serve the native load of any public utility subsidiary is
sold at wholesale by the generating subsidiary. See Trading and Marketing of
Energy Commodities for a discussion of the trading and marketing of such power.

     AEP's System Integration Agreement provides for the integration and
coordination of AEP's east and west zone operating subsidiaries, joint dispatch
of generation within the AEP System, and the distribu-

                                        12
<PAGE>

tion, between the two operating zones, of costs and benefits associated with the
System's generating plants. It is designed to function as an umbrella agreement
in addition to the Interconnection Agreement and the CSW Operating Agreement,
each of which controls the distribution of costs and benefits within each zone.

 Competition and Regulation

     Retail Sales: AEP's public utility subsidiaries have the right (which in
some cases is exclusive) to sell electric power at retail within their
respective service areas in the states of Arkansas, Indiana, Kentucky,
Louisiana, Oklahoma, Tennessee, West Virginia and the SPP area of Texas. In
Michigan, Ohio and Virginia, AEP's public utility subsidiaries continue to
provide service to customers who have not been offered or have not selected
alternate service from competing suppliers. In those states, service is
currently being provided according to prescribed rules and rates. In the ERCOT
area of Texas, TCC and TNC sell power to Centrica, which provides PTB service to
certain former customers of TCC and TNC and must compete for customers.

     AEP's public utility subsidiaries also compete with self-generation and
with distributors of other energy sources, such as natural gas, fuel oil and
coal, within their service areas. The primary factors in such competition are
price, reliability of service and the capability of customers to utilize sources
of energy other than electric power. With respect to competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. With respect to alternative
sources of energy, the public utility subsidiaries of AEP believe that the
reliability of their service and the limited ability of customers to substitute
other cost-effective sources for electric power place them in a favorable
competitive position, even though their prices may be higher than the costs of
some other sources of energy.

     Significant changes in the global economy in recent years have led to
increased price competition for industrial customers in the United States,
including those served by the AEP System. Some of these industrial customers
have requested price reductions from their suppliers of electric power. In
addition, industrial customers that are downsizing or reorganizing often close a
facility based upon its costs, which may include, among other things, the cost
of electric power. The public utility subsidiaries of AEP cooperate with such
customers to meet their business needs through, for example, providing various
off-peak or interruptible supply options pursuant to tariffs filed with the
various state commissions. Occasionally, these rates are first negotiated, and
then filed with the state commissions. The public utility subsidiaries believe
that they are unlikely to be materially adversely affected by this competition.

     See Energy Delivery -- Regulation -- Rates for a description of the setting
of rates for power sold at bundled or unbundled state-regulated rates.

     Wholesale Sales: The public utility subsidiaries of AEP, like the electric
industry generally, face increasing competition in the sale of available power
on a wholesale basis, primarily to other public utilities and power marketers.
The Energy Policy Act of 1992 was designed, among other things, to foster
competition in the wholesale market by creating a generation market with fewer
barriers to entry and mandating that all generators have equal access to
transmission services. As a result, there are more generators able to
participate in this market. The principal factors in competing for wholesale
sales are price (including fuel costs), availability of capacity and power and
reliability of service.

     The public utility subsidiaries of AEP are subject to regulation by the
FERC under the Federal Power Act in respect of rates for interstate sales at
wholesale. See General -- Regulation -- FERC.

 Seasonality

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

                                        13
<PAGE>

 Fuel Supply

     The following table shows the sources of power generated by the AEP System:

<Table>
<Caption>
                              2000   2001   2002
                              ----   ----   ----
<S>                           <C>    <C>    <C>
Coal........................   78%    74%    78%
Natural Gas.................   13%    12%     8%
Nuclear.....................    5%    11%    11%
Hydroelectric and other.....    4%     3%     3%
</Table>

     Variations in the generation of nuclear power are primarily related to
refueling outages and, in a portion of 2000, the shutdown of the Cook Plant to
respond to issues raised by the NRC. Variations in the generation of natural gas
power are primarily related to the availability of cheaper alternatives to
fulfill certain power requirements and to deactivate certain of its gas-fired
plants.

     Coal and Lignite: AEP System generating companies procure coal and lignite
under a combination of purchasing arrangements including long-term contracts,
affiliate operations, short-term, and spot agreements with various producers and
coal trading firms. AEP believes, but cannot provide assurances that, it will be
able to secure coal and lignite of adequate quality and in adequate quantities
to operate its coal and lignite-fired units.

     The following table shows the amount of coal delivered to the AEP System
during the past three years and the average delivered price of spot coal
purchased by System companies:

<Table>
<Caption>
                        2000      2001      2002
                       -------   -------   -------
<S>                    <C>       <C>       <C>
Total coal delivered
  to AEP operated
  plants (thousands
  of tons)...........   73,259    73,889    76,442
Average price per ton
  of spot-purchased
  coal...............  $ 24.03   $ 27.30   $ 27.06
</Table>

     The coal supplies at AEP System plants vary from time to time depending on
various factors, including customers' usage of electric power, space
limitations, the rate of consumption at particular plants, labor unrest and
weather conditions which may interrupt deliveries. At December 31, 2002, the
System's coal inventory was roughly 56 days of normal usage. This estimate
assumes that the total supply would be utilized through the operation of plants
that use coal most efficiently.

     In cases of emergency or shortage, system companies have developed programs
to conserve coal supplies at their plants. Such programs have been filed and
reviewed with officials of federal and state agencies and, in some cases, the
state regulatory agency has prescribed actions to be taken under specified
circumstances by System companies, subject to the jurisdiction of such agencies.

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

     Natural Gas: AEP, through its public utility subsidiaries, consumed over
163 billion cubic feet of natural gas during 2002 for generating power. A
majority of the gas fired electric generation plants are connected to at least
two natural gas pipelines, which provides greater access to competitive supplies
and improves reliability. A portfolio of long-term and short-term purchase and
transportation agreements (that are acquired on a competitive basis and based on
market prices) supplies natural gas requirements for each plant.

     Nuclear: I&M and STPNOC have made commitments to meet certain of the
nuclear fuel requirements of the Cook Plant and STP, respectively. Steps
currently are being taken, based upon the planned fuel cycles for the Cook
Plant, to review and evaluate I&M's requirements for the supply of nuclear fuel.
I&M has made and will make purchases of uranium in various forms in the spot,
short-term, and mid-term markets until it decides that deliveries under
long-term supply contracts are warranted. TCC and the other STP participants
have entered into contracts with suppliers for (i) 100% of the uranium
concentrate sufficient for the operation of both STP units through spring 2006
and (ii) 50% of the uranium concentrate needed for STP through spring 2007.

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

                                        14
<PAGE>

capability to store the spent nuclear fuel generated by the STP units over their
licensed lives.

  Nuclear Waste and Decommissioning

     I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The ultimate cost of retiring the
Cook Plant and STP may be materially different from estimates and funding
targets as a result of the:

     - Type of decommissioning plan selected;

     - Escalation of various cost elements (including, but not limited to,
       general inflation);

     - Further development of regulatory requirements governing decommissioning;

     - Limited availability to date of significant experience in decommissioning
       such facilities;

     - Technology available at the time of decommissioning differing
       significantly from that assumed in these studies; and

     - Availability of nuclear waste disposal facilities.

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

     See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 9 to the consolidated financial statements, entitled
Commitments and Contingencies, which are incorporated by reference in Items 7
and 8, respectively, for information with respect to nuclear waste and
decommissioning and related litigation.

     Low-Level Radioactive Waste: The LLWPA mandates that the responsibility for
the disposal of low-level radioactive waste rests with the individual states.
Low-level radioactive waste consists largely of ordinary refuse and other items
that have come in contact with radioactive materials. Michigan and Texas do not
currently have disposal sites for such waste available. AEP cannot predict when
such sites may be available, but South Carolina and Utah operate low-level
radioactive waste disposal sites and accept low-level radioactive waste from
Michigan and Texas. AEP's access to the South Carolina facility is currently
allowed through the end of fiscal year 2008.

  Deactivation and Planned Disposition of Generation Facilities

     In September 2002, AEP indicated to ERCOT its intent to deactivate 16
gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently
conducted reliability studies that determined that seven plants (4 TCC plants
and 3 TNC plants) would be required to ensure reliability of the electricity
grid. As a result of these studies, ERCOT and AEP agreed to enter into
reliability must run agreements (which expired in December 2002, but have been
renewed for all but two units of these plants) to continue operation of these
plants. With ERCOT's approval, AEP proceeded with its planned deactivation of
the remaining nine plants.

     TCC has also filed a plan of divestiture with the PUCT proposing to sell
all of its power generation assets in an effort to determine its level of
stranded costs in accordance with the Texas Act. The PUCT has dismissed its
proceeding relating to TCC's plan of divestiture in anticipation of promulgating
rules of general application regarding stranded cost determination for nuclear
facilities. See Energy Delivery-Regulatory Assets and Stranded Cost Recovery and
Post-Restructuring Wires Charges.

     The assets to be sold have a generating capacity of 4,497 MW and include
eight gas-fired generating plants, one coal-fired plant, TCC's interest in
another coal-fired plant, a hydroelectric facility and TCC's interest in STP.
See Note 8 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring, incorporated by reference in Item 8, for more
information on the planned disposition of TCC generation facilities.

TRADING AND MARKETING OF ENERGY COMMODITIES

     AEP enters into transactions for the purchase and sale of electricity and
natural gas as part of wholesale trading operations. Electric and gas
transactions are executed over-the-counter with counterparties or through
brokers. Gas transactions are also executed through brokerage accounts with
brokers who are registered with the Commodity Futures Trading Commission.
Brokers and counterparties may require cash or cash related instruments to be
deposited on these transactions as margin against open positions.

     AEP trades electricity and gas contracts with numerous counterparties.
Since AEP's open energy trading contracts are valued based on changes in
                                        15
<PAGE>

market prices of the related commodities, our exposures change daily.

     In October 2002, AEP announced its plans to reduce its exposure to energy
trading markets and to downsize the trading and wholesale marketing operations.
It is expected that in the future power trading and marketing operations will be
smaller in scope, will generally be limited to risk management around AEP assets
and, accordingly, focused in regions in which AEP owns assets.

 Energy Market Investigations

     During 2002, several governmental entities launched investigations of
participants in energy trading markets, including AEP. A number of those
investigations resulted in data requests of AEP. See Management's Discussion and
Analysis of Financial Condition, Accounting Policies and Other Matters,
incorporated by reference in Item 7, under the heading Energy Market
Investigations.

NATURAL GAS PIPELINE, STORAGE AND PROCESSING FACILITIES

     AEP, through certain subsidiaries, operates and owns an interest in a
significant amount of gas-related assets, including:

     - 6,400 miles of natural gas pipelines between two systems;

     - 128 billion cubic feet of storage among two facilities;

     - Five natural gas processing plants; and

     - Certain gas marketing contracts.

COAL MINES AND RELATED FACILITIES

     AEP, through certain subsidiaries, holds various properties, coal reserves,
mining operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio,
Pennsylvania and West Virginia.

BARGE, RAIL AND OTHER FUEL TRANSPORTATION RELATED ASSETS

     AEP, through MEMCO Barge Line Inc., is engaged in the transportation of
coal and dry bulk commodities, primarily on the Ohio, Illinois, and Lower
Mississippi rivers for AEP, as well as unaffiliated customers. AEP, through
certain subsidiaries, owns or leases 7,000 railcars, 1,800 barges, 37 tug boats
and two coal handling terminals with 20 million tons of annual capacity.

STRUCTURED ARRANGEMENTS INVOLVING CAPACITY, ENERGY, AND ANCILLARY SERVICES

 Dow

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

 Buckeye

     In January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an
agreement relating to the construction and operation of a 510 MW gas-fired
electric generating peaking facility to be owned by NPC. From the commercial
operation date (which occurred in 2002) until the end of 2005, OPCo will be
entitled to 100% of the power generated by the facility, and responsible for the
fuel and other costs of the facility. After 2005, NPC and OPCo will be entitled
to 80% and 20%, respectively, of the power of the facility, and both parties
will generally be responsible for the fuel and other costs of the facility. OPCo
will also provide certain back-up power to NPC.

CERTAIN POWER AGREEMENTS

 AEGCo

     Since its formation in 1982, AEGCo's business has consisted of the
ownership and financing of its 50% interest in Unit 1 of the Rockport Plant and,
since 1989, leasing of its 50% interest in Unit 2 of the Rockport Plant. The
operating revenues of AEGCo are derived from the sale of capacity and energy
associated with its interest in the Rockport Plant to I&M and KPCo pursuant to
unit power agreements.

     The I&M Power Agreement provides for the sale by AEGCo to I&M of all the
power (and the energy associated therewith) available to AEGCo at the Rockport
Plant. I&M is obligated, whether or not power is available from AEGCo, to pay as
a demand charge for the right to receive such power (and as an energy charge for
any associated energy taken by I&M). Such amounts, when added to amounts
received by AEGCo from any other sources, will be at least

                                        16
<PAGE>

sufficient to enable AEGCo to pay all its operating and other expenses,
including a rate of return on the common equity of AEGCo as approved by FERC,
currently 12.16%. The I&M Power Agreement will continue in effect until the date
that the last of the lease terms of Unit 2 of the Rockport Plant has expired
unless extended in specified circumstances.

     Pursuant to an assignment between I&M and KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo the same amounts which I&M would have paid AEGCo
under the terms of the I&M Power Agreement for such entitlement. The KPCo unit
power agreement expires on December 31, 2004. The agreement will be extended
until December 31, 2009 for Unit 1 and December 31, 2022 for Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes effective.

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

 OVEC

     AEP, CSPCo and several unaffiliated utility companies jointly own OVEC. The
aggregate equity participation of AEP and CSPCo in OVEC is 44.2%. Until
September 1, 2001, OVEC supplied the power requirements of a uranium enrichment
plant near Portsmouth, Ohio owned by the DOE. The sponsoring companies are now
entitled to receive and pay for all OVEC capacity (approximately 2,200 MW) in
proportion to their power participation ratios. The aggregate power
participation ratio of APCo, CSPCo, I&M and OPCo is 42.1%. The proceeds from the
sale of power by OVEC are designed to be sufficient for OVEC to meet its
operating expenses and fixed costs and to provide a return on its equity
capital. The Inter-Company Power Agreement, which defines the rights of the
owners and sets the power participation ratio of each, will expire by its terms
on March 12, 2006.

 Buckeye

     Contractual arrangements among OPCo, Buckeye and other investor-owned
electric utility companies in Ohio provide for the transmission and delivery,
over facilities of OPCo and of other investor-owned utility companies, of power
generated by the two units at the Cardinal Station owned by Buckeye and back-up
power to which Buckeye is entitled from OPCo under such contractual
arrangements, to facilities owned by 25 of the rural electric cooperatives which
operate in the State of Ohio at 342 delivery points. Buckeye is entitled under
such arrangements to receive, and is obligated to pay for, the excess of its
maximum one-hour coincident peak demand plus a 15% reserve margin over the
1,226,500 kilowatts of capacity of the generating units which Buckeye currently
owns in the Cardinal Station. Such demand, which occurred on August 1, 2002, was
recorded at 1,398,559 kilowatts.

ENERGY DELIVERY

GENERAL

     AEP's public utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item
2--Properties for more information regarding the transmission and distribution
lines. Most of the transmission and distribution services are sold, in
combination with electric power, to retail customers of AEP's public utility
subsidiaries in their service territories. These sales are made at rates
established by the state utility commissions of the states in which they
operate, and in some instances, the FERC as well. See Regulation-- Rates. The
FERC regulates and approves the rates for wholesale transmission transactions.
See General--Regulation-- FERC. As discussed below, some transmission services
also are separately sold to non-affiliated companies.

     AEP's public utility subsidiaries hold franchises or other rights to
provide electric service in various municipalities and regions in their service
areas. In some cases, these franchises provide the utility with the exclusive
right to provide electric service. These franchises have varying provisions and
expiration

                                        17
<PAGE>

dates. In general, the operating companies consider their franchises to be
adequate for the conduct of their business. For a discussion of competition in
the sale of power, see Wholesale Operations-- Generation-- Competition and
Regulation.

REGULATION

     AEP is in the business of providing generation, transmission and
distribution services. The transmission and distribution functions are part of
AEP's energy delivery segment. The generation function is part of AEP's
wholesale operations segment. This discussion covers the regulation of
transmission and distribution, but also generation sold at retail (which would
otherwise be included in the wholesale operations segment discussion).

 Rates

     Historically, state utility commissions have established electric service
rates on a cost-of-service basis, which is designed to allow a utility an
opportunity to recover its cost of providing service and to earn a reasonable
return on its investment used in providing that service. A utility's cost of
service is generally comprised of its operating expenses, including operation
and maintenance expense, depreciation expense and taxes. State utility
commissions periodically adjust rates pursuant to a review of (i) a utility's
revenues and expenses during a defined test period and (ii) such utility's level
of investment. Absent a legal limitation, such as a law limiting the frequency
of rate changes or capping rates for a period of time as part of a transition to
customer choice of generation suppliers, a state utility commission can review
and change rates on its own initiative. Some states may initiate reviews at the
request of a utility, customer, governmental or other representative of a group
of customers. Such parties may, however, agree with one another not to request
reviews of or changes to rates for a specified period of time.

     The rates of AEP's public utility subsidiaries are generally based on the
cost of providing traditional bundled electric service (i.e., generation,
transmission and distribution service). In Ohio, Virginia and the ERCOT area of
Texas, rates are transitioning from bundled cost-based rates for electric
service to unbundled cost-based rates for transmission and distribution service
on the one hand, and market pricing for and/or customer choice of generation on
the other.

     Historically, the state regulatory frameworks in the service area of the
AEP System reflected specified fuel costs as part of bundled (or, more recently,
unbundled) rates or incorporated fuel adjustment clauses in a utility's rates
and tariffs. Fuel adjustment clauses permit periodic adjustments to fuel cost
recovery from customers and therefore provide protection against exposure to
fuel cost changes. While the historical framework remains in a portion of AEP's
service territory, recovery of increased fuel costs (i) is no longer provided
for in Ohio and (ii) may be limited in Indiana and Michigan, which have capped
rates. Fuel recovery is also limited in the ERCOT area of Texas, but because AEP
sold MECPL and MEWTU, there is little impact on AEP of fuel recovery procedures
related to service in ERCOT.

     The following state-by-state analysis summarizes the regulatory environment
of each jurisdiction in which AEP operates. Several public utility subsidiaries
operate in more than one jurisdiction.

     Indiana: I&M provides retail electric service in Indiana at a bundled rate
approved by the IURC. While rates are set on a cost-of-service basis, utilities
may also generally seek to adjust fuel clause rates quarterly. I&M's base rate
is capped through December 31, 2004 and its fuel recovery rate is capped through
February 29, 2004.

     Ohio: CSPCo and OPCo operate as functionally separated utilities and
provide "default" retail electric service to customers at unbundled rates
established by the Ohio Act through December 31, 2005. Thereafter, CSPCo and
OPCo will continue to provide distribution services to retail customers at rates
approved by the PUCO. These rates will be frozen from December 31, 2005 to (i)
December 31, 2008 for CSPCo and (ii) December 31, 2007 for OPCo. Transmission
services will continue to be provided at rates established by the FERC. Default
retail generation service rates will be based on market prices pursuant to rules
currently under consideration by the PUCO.

     Oklahoma: PSO provides retail electric service in Oklahoma at a bundled
rate approved by the OCC. PSO's rates are set on a cost-of-service basis. Fuel
and purchased power costs above the amount included in base rates are recovered
by applying a fuel adjustment factor to retail kilowatt-hour sales. The factor
is adjusted quarterly and is based upon forecasted fuel and purchased power
costs. Over or under collections of fuel costs for prior periods can be
recovered when new quarterly factors are established.

     Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and
                                        18
<PAGE>

distribution assets. TCC and TNC currently operate on a functionally separated
basis. In January 2002, TCC and TNC transferred all their retail customers in
the ERCOT area of Texas to MECPL, MEWTU and AEP Commercial and Industrial REP
(an AEP affiliate). TNC's retail SPP customers were ultimately transferred to
Mutual Energy SWEPCo L.P. (an AEP affiliate). TCC and TNC provide retail
transmission and distribution service on a cost-of-service basis at rates
approved by the PUCT and wholesale transmission service under tariffs approved
by the FERC consistent with PUCT rules.

     The implementation of the business separation plan for SWEPCo operations in
the SPP area of Texas was delayed by the PUCT. As such, SWEPCo's Texas
operations continue to operate and to be regulated as a traditional bundled
utility with both base and fuel rates.

     Virginia: APCo provides unbundled retail electric service in Virginia.
APCo's unbundled generation, transmission (which reflect FERC approved
transmission rates) and distribution rates as well as its functional separation
plan were approved by the VSCC in December 2001.

     The Virginia Act capped base rates at their mid-1999 levels until the end
of the transition period (July 1, 2007), or sooner if the VSCC finds that a
competitive market for generation exists in Virginia. The Virginia Act permits
APCo to seek a one-time change to its capped non-generation rates after January
1, 2004. The Virginia Act allows adjustments to fuel rates during the transition
period and continues to permit utilities to recover their actual fuel costs, the
fuel component of their purchased power costs and certain capacity charges. APCo
recovers its generation capacity charges through capped base rates.

     West Virginia: APCo and Wheeling Power Company provide retail electric
service at bundled rates approved by the WVPSC. A plan to introduce customer
choice was approved by the West Virginia Legislature in its 2000 legislative
session. However, implementation of that plan was placed on hold pending
necessary changes to the state's tax laws in a subsequent session. Those changes
have not been made.

     While West Virginia generally allows recovery of fuel costs, the most
recent proceeding resulted in the suspension of an active fuel clause for APCo
and WPCo (though they continue to recover fuel costs through fixed bundled
rates). APCo and Wheeling Power Company are currently unable to change the
current level of fuel cost recovery, though this ability could be reinstated in
a future proceeding.

     Other Jurisdictions: The public utility subsidiaries of AEP also provide
service at regulated bundled rates in Arkansas, Kentucky, Louisiana and
Tennessee and regulated unbundled rates in Michigan.

                                        19
<PAGE>

     The table below illustrates the current rate regulation status of the
states in which the public utility subsidiaries of AEP operate:

<Table>
<Caption>
                                                                                   FUEL CLAUSE RATES                   PERCENTAGE
                                                                   -------------------------------------------------     OF AEP
                            STATUS OF BASE RATES FOR                                                  SYSTEM SALES       SYSTEM
                 -----------------------------------------------                                     PROFITS SHARED      RETAIL
JURISDICTION          POWER SUPPLY           ENERGY DELIVERY           STATUS          INCLUDES       W/RATEPAYERS     REVENUES(1)
- ------------     ----------------------   ----------------------   --------------   --------------   ---------------   -----------
<S>              <C>                      <C>                      <C>              <C>              <C>               <C>
Ohio             Frozen through 2005      Distribution frozen      None             Not applicable   Not applicable        30%
                                          through 2007 for OPCo
                                          and 2008 for CSP;
                                          Transmission frozen
                                          through 2005
Texas
  (TCC, TNC)     See footnote 2           Not capped or frozen     Not applicable   Not applicable   Not applicable        17%(2)
Texas
  (SWEPCo)       Capped until 6/15/03                              Active           Fuel and fuel    Yes, above base        3%
                                                                                    portion of       levels
                                                                                    purchased
                                                                                    power
Indiana          Capped until 1/1/05(3)                            Capped until     Fuel and fuel    No                    10%
                                                                   3/1/04(3)        portion of
                                                                                    purchased
                                                                                    power
Virginia         Capped until as late     Capped until as late     Active           Fuel and fuel    No                     9%
                 as 7/1/07(4)             as 7/1/07(4)                              portion of
                                                                                    purchased
                                                                                    power
West Virginia    Fixed(5)                                          Suspended(5)     Fuel and fuel    Yes, but               9%
                                                                                    portion of       suspended
                                                                                    purchased
                                                                                    power
Oklahoma         Cap expired 1/1/03                                Active           Fuel and fuel    Yes                    9%
                                                                                    portion of
                                                                                    purchased
                                                                                    power
Louisiana        Capped until 6/15/05                              Active           Fuel and fuel    Yes, above base        5%
                                                                                    portion of       levels
                                                                                    purchased
                                                                                    power
Kentucky         Frozen until 6/15/03(6)                           Active           Fuel and fuel    Yes, above base        3%
                                                                                    portion of       levels
                                                                                    purchased
                                                                                    power
Arkansas         Capped until 6/15/03                              Active           Fuel and fuel    Yes, above base        2%
                                                                                    portion of       levels
                                                                                    purchased
                                                                                    power
Michigan         Capped until 1/1/05(7)   Capped until 1/1/05(7)   Capped until     Fuel and fuel    Yes, in some           2%
                                                                   1/1/04(8)        portion of       areas, but
                                                                                    purchased        suspended
                                                                                    power
Tennessee        Not capped or frozen                              Active           Fuel and fuel    No                     1%
                                                                                    portion of
                                                                                    purchased
                                                                                    power
</Table>

- ---------------------------------

(1) Represents the percentage of revenues from sales to retail customers from
    AEP utility companies operating in each state to the total AEP System
    revenues from sales to retail customers for the year ended December 31,
    2002.

(2) Retail electric service in the ERCOT area of Texas is provided to most
    customers through unaffiliated REPs which must offer PTB rates until January
    1, 2007. The percentage of revenues shown includes revenues from power sales
    contracts between MECPL and TCC and MEWTU and TNC.

                                        20
<PAGE>

(3) Capped base and fuel rates pursuant to a 1999 settlement with base rate
    freeze extended pursuant to merger stipulation.

(4) Base rates are capped until the earlier of 7/1/07 or a finding by the VSCC
    that a competitive market for generation exists. One-time change in
    non-generation rates is allowed in Virginia after 1/1/04.

(5) Rates fixed and expanded net energy clause suspended in West Virginia
    pursuant to a 1999 rate case stipulation, but subject to change in a future
    proceeding.

(6) Utilities may request that an environmental surcharge be imposed to recover
    costs associated with the installation of emission control equipment.

(7) Capped base and fuel rates pursuant to a 1999 settlement and base rates
    extended pursuant to merger stipulation.

(8) Michigan fuel rates capped until 1/1/04 pursuant to a 1999 fuel settlement.

AEP TRANSMISSION POOL

 Transmission Equalization Agreement

     APCo, CSPCo, I&M, KPCo and OPCo operate their transmission lines as a
single interconnected and coordinated system and are parties to the Transmission
Equalization Agreement, dated April 1, 1984, as amended (TEA), defining how they
share the costs and benefits associated with their relative ownership of the
extra-high-voltage transmission system (facilities rated 345 KV and above) and
certain facilities operated at lower voltages (138 KV and above). This sharing
is based upon each company's "member-load ratio." The member-load ratio is
calculated monthly by dividing such company's highest monthly peak demand for
the last twelve months by the aggregate of the highest monthly peak demand for
the last twelve months for all east zone operating companies. As of December 31,
2002, the member-load ratios were as follows:

<Table>
<Caption>
                            PEAK
                           DEMAND   MEMBER-LOAD
                            (KW)     RATIO (%)
                           ------   -----------
<S>                        <C>      <C>
APCo.....................  6,010       28.2
CSPCo....................  4,040       19.0
I&M......................  4,323       20.3
KPCo.....................  1,551        7.3
OPCo.....................  5,360       25.2
</Table>

     The following table shows the net credits or (charges) allocated among the
parties to the TEA during the years ended December 31, 2000, 2001 and 2002:

<Table>
<Caption>
                         2000       2001      2002
                       --------   --------   -------
                              (IN THOUSANDS)
<S>                    <C>        <C>        <C>
APCo.................  $  3,400   $  3,100  $ 13,400
CSPCo................   (38,300)   (40,200)  (42,200)
I&M..................    43,800     41,300    36,100
KPCo.................     6,000      4,600     5,400
OPCo.................   (14,900)    (8,800)  (12,700)
</Table>

 Transmission Coordination Agreement

     PSO, SWEPCo, TCC, TNC and AEPSC are parties to a Transmission Coordination
Agreement originally dated as of January 1, 1997 (TCA). The TCA establishes a
coordinating committee, which is charged with the responsibility of overseeing
the coordinated planning of the transmission facilities of the west zone public
utility subsidiaries, including the performance of transmission planning
studies, the interaction of such subsidiaries with independent system operators
and other regional bodies interested in transmission planning and compliance
with the terms of the OATT filed with the FERC and the rules of the FERC
relating to such tariff.

     Under the TCA, the west zone public utility subsidiaries have delegated to
AEPSC the responsibility of monitoring the reliability of their transmission
systems and administering the AEP OATT on their behalf. The TCA also provides
for the allocation among the west zone public utility subsidiaries of revenues
collected for transmission and ancillary services provided under the AEP OATT.

     The following table shows the net credits or (charges) allocated among the
parties to the TCA during the years ended December 31, 2000, 2001 and 2002:

<Table>
<Caption>
                         2000     2001     2002
                        ------   ------   ------
                             (IN THOUSANDS)
<S>                     <C>      <C>      <C>
PSO................... $ 3,300  $ 4,000  $ 4,200
SWEPCo................   5,900    5,400    5,000
TCC...................  (3,400)  (3,900)  (3,600)
TNC...................  (5,800)  (5,500)  (5,600)
</Table>

 Transmission Services for Non-Affiliates

     In addition to providing transmission services in connection with their own
power sales, AEP's public utility subsidiaries and other System companies also
provide transmission services for non-affiliated compa-

                                        21
<PAGE>

nies. See Regulation--Regional Transmission Organizations. AEP's public utility
subsidiaries are subject to regulation by the FERC under the FPA in respect of
transmission of electric power.

 Coordination of East and West Zone Transmission

     AEP's System Transmission Integration Agreement provides for the
integration and coordination of the planning, operation and maintenance of the
transmission facilities of AEP's east and west zone public utility subsidiaries.
The System Transmission Integration Agreement functions as an umbrella agreement
in addition to the TEA and the TCA. The System Transmission Integration
Agreement contains two service schedules that govern:

     - The allocation of transmission costs and revenues and

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

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

COMPETITION

     The public utility subsidiaries of AEP, like many other electric utilities,
have traditionally provided electric generation and energy delivery, consisting
of transmission and distribution services, as a single product to their retail
customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia
that allows for customer choice of generation supplier. Although restructuring
legislation has been passed in Oklahoma and West Virginia, it has been delayed
indefinitely in Oklahoma and not implemented in West Virginia. In addition,
restructuring legislation in Arkansas has been repealed. See General--Electric
Restructuring Legislation. Customer choice legislation generally allows
competition in the generation and sale of electric power, but not in its
transmission and distribution.

     See Management's Discussion and Analysis of Results of Operations and
Management's Discussion and Analysis of Financial Condition, Accounting Policies
and Other Matters and Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring incorporated by reference in Items 7
and 8, respectively, for further information with respect to restructuring
legislation affecting AEP subsidiaries.

SEASONALITY

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

REGIONAL TRANSMISSION ORGANIZATIONS

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

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

     AEP is required, as a condition of FERC's approval in 2000 of AEP's merger
with CSW, to transfer functional control of its transmission facilities to one
or more RTOs. In May 2002, AEP announced an agreement with PJM to pursue terms
for its east zone public utility subsidiaries to participate in PJM, a

                                        22
<PAGE>

FERC approved RTO. In July 2002, the FERC tentatively approved AEP subsidiaries'
decision to join PJM, subject to certain conditions being met. The satisfaction
of these conditions is only partially within AEP's control. AEP's public utility
subsidiaries have filed applications with the state utility commissions of
Indiana, Kentucky, Ohio and Virginia requesting approval of the transfer of
functional control of transmission assets in those states to PJM. Those
applications are pending. In February 2003, the Virginia legislature enacted
legislation that would prohibit the transfer of functional control of
transmission assets to an RTO until at least July 2004.

     In July 2002, FERC conditionally accepted filings related to a proposed
consolidation of MISO and the SPP. In that order the FERC required AEP's west
zone subsidiaries in SPP to file reasons why those subsidiaries should not be
required to join MISO. SWEPCo has filed an application with the LPSC requesting
approval of the transfer of functional control of its Louisiana transmission
assets to MISO and intends to make a similar filing in Arkansas with respect to
its Arkansas transmission assets. AEP presently plans to transfer functional
control of its transmission facilities in SPP to MISO or the merged MISO/SPP.

TEXAS REGULATORY ASSETS AND STRANDED COST RECOVERY AND POST-RESTRUCTURING WIRES
CHARGES

     Certain transmission and distribution utilities in Texas whose generation
assets were unbundled pursuant to the Texas Act may recover generation-related
regulatory assets and generation-related stranded costs. Regulatory assets
consist of the Texas jurisdictional amount of generation-related regulatory
assets and liabilities in the audited financial statements as of December 31,
1998. Stranded costs consist of the positive excess of the net regulated book
value of generation assets over the market value of those assets, taking
specified factors into account. The Texas Act allows alternative methods of
valuation to determine the fair market value of generation assets, including
outright sale, full and partial stock valuation and asset exchanges, and also,
for nuclear generation assets, the ECOM model.

     The Texas Act further permits utilities to establish a special purpose
entity to issue securitization bonds for the recovery of regulatory assets and,
after the 2004 true-up proceeding, the amount of stranded costs and remaining
regulatory assets not previously securitized. Securitization bonds allow for
regulatory assets and stranded costs to be refinanced with recovery of the bond
principal and financing costs ensured through a non-bypassable rate surcharge by
the regulated transmission and distribution utility over the life of the
securitization bonds. Any stranded costs not recovered through the sale of
securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to transmission and distribution customers.

 Regulatory Assets

     In 1999, TCC filed an application with the PUCT to securitize approximately
$1.27 billion of its retail generation-related regulatory assets and
approximately $47 million in other qualified restructuring costs. On March 27,
2000, the PUCT issued an order authorizing issuance of up to $797 million of
securitization bonds including $764 million for recovery of net generation-
related regulatory assets and $33 million for other qualified refinancing costs.
The securitization bonds were issued in February 2002. TCC has included a
transition charge in its distribution rates to repay the bonds over a 14-year
period. In addition, another $185 million of generation-related regulatory
assets are being recovered through distribution rates beginning in January 2002.
Remaining generation-related regulatory assets of approximately $214 million
originally included by TCC in its 1999 securitization request along with certain
other regulatory assets will be included in TCC's request to recover stranded
costs in the 2004 true-up proceeding.

 Stranded Costs

     In a March 2000 filing with the PUCT to determine unbundled transmission
and distribution charges and initial stranded cost recovery, TCC requested
recovery of an additional $1.1 billion of stranded costs and regulatory assets
that were not securitized. In October 2001, the PUCT issued an order in the UCOS
proceeding determining an initial amount of TCC ECOM or stranded costs of
approximately negative $615 million based upon the PUCT's ECOM model. The ruling
indicated that TCC costs were below market after securitization of regulatory
assets. TCC disagrees with the ruling and believes it has positive stranded
costs in addition to the securitized regulatory assets.

     As a result of this stranded cost determination, the PUCT ordered TCC to
refund $55 million of estimated excess earnings for the period 1999 through 2001
to customers through a credit applied to distribu-

                                        23
<PAGE>

tion rates over a five-year period. TCC appealed the PUCT's estimate of stranded
costs and refund of excess earnings, among other issues, to the Travis County
District Court. This estimate may be superseded by a final determination made as
part of the 2004 true-up proceedings.

     The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. Pursuant to
PUCT rules, if TCC's total stranded costs determined in the 2004 true-up
proceeding are less than the amount of securitized regulatory assets, the PUCT
can implement an offsetting credit to transmission and distribution rates. The
Texas Third Circuit Court of Appeals ruled in February 2003 that the Texas Act
does not contemplate the refunding to customers of negative stranded costs. In
addition, the Court ruled that negative stranded costs cannot be offset against
other true-up adjustments, including under-recovered fuel amounts. This ruling
may be appealed to the Texas Supreme Court, which has discretion as to whether
to accept and consider the appeal.

 2004 True-Up Proceedings

     Beginning as early as January 2004, the PUCT will conduct true-up
proceedings (with respect to the ERCOT area of Texas) for each investor-owned
utility, its affiliated REP and affiliated power generation company. The purpose
of the true-up proceeding is to (i) quantify and reconcile the amount of
stranded costs and generation-related regulatory assets that have not yet been
securitized, (ii) conduct a true-up of the PUCT ECOM model for 2002 and 2003 to
reflect market prices determined in required capacity auctions, (iii) establish
final fuel recovery balances and (iv) determine the price to beat clawback
component. The true-up proceeding will generally result in either additional
charges or credits to retail customers through transmission and distribution
rates collected by their REPs and remitted to the utility.

     Stranded Cost and Generation-Related Regulatory Asset Determination: The
Texas Act authorized the use of several valuation methodologies to quantify
stranded costs and generation-related regulatory assets in the 2004 true-up
proceeding, including by the sale of assets. TCC filed a plan of divestiture
with the PUCT in December 2002 seeking approval to sell its generation assets to
determine their market value. The PUCT has dismissed its proceeding relating to
TCC's plan of divestiture in anticipation of promulgating rules of general
application regarding stranded cost determination. If the PUCT determines the
sale of assets methodology cannot be used to determine the market value of STP,
TCC intends to pursue the use of one or more market valuation methods.
Divestiture of TCC's interest in STP to a nonaffiliate will also require NRC
approval. TNC does not have any recoverable stranded costs or generation-related
regulatory assets that can be considered as part of the 2004 true-up.

     ECOM/Capacity Auction Component: The PUCT used a computer model or
projection, called an ECOM model, to estimate stranded costs related to
generation plant assets in the UCOS proceeding. In connection with using the
ECOM model to calculate the stranded cost estimate, the PUCT estimated the
market power prices that will be received in the competitive wholesale
generation market. Any difference between the ECOM model market prices and
actual market power prices as measured by generation capacity auctions required
by the Texas Act during the period of January 1, 2002 through December 31, 2003
will be a component of the 2004 true-up proceeding, either increasing or
decreasing the amount of recovery for TCC. Auctions to date have generally
indicated that market prices have been lower than the PUCT's ECOM estimates.
Unless this is reversed, TCC's recovery in the 2004 true-up proceeding would be
increased. In the event TCC has transferred its generation assets to an
affiliate, the Texas Act would require TCC to remit to its affiliate the
recovery amount accruing after the transfer. See Note 8 to the consolidated
financial statements, entitled Customer Choice and Industry Restructuring,
incorporated by reference in Item 8, for a discussion of the current calculation
of the difference between the market price and ECOM estimate.

     Fuel Recovery Balance Determination: The amount TCC or TNC recovers in the
2004 true-up proceeding could be increased or reduced (or the amount TCC must
refund could be increased) by any under or over-recovery of fuel. The fuel
component will be determined by the amount of fuel costs and expenses the PUCT
approves based on a final fuel reconciliation that TCC filed on December 2, 2002
and that TNC filed on June 3, 2002. TCC's fuel reconciliation covers its fuel
costs from the period beginning July 1, 1998 and ending December 31, 2001. TCC's
fuel reconciliation filing seeks approval for $1.6 billion in fuel expense
collected from retail customers during that period. TCC's fuel reconciliation
filing reflects a fuel over-recovery balance, as of December 31, 2001, of $63.5
million, including

                                        24
<PAGE>

interest. A procedural schedule has been set with a hearing scheduled to begin
May 7, 2003. TNC's fuel reconciliation requests approval of $292 million in fuel
costs associated with serving both ERCOT and SPP retail customers from July 1,
2000 through December 31, 2001. It reflects a fuel under-recovery balance, as of
December 31, 2001, of $26.9 million, including interest. The amounts in this
paragraph may periodically be adjusted as filings are updated or adjusted. A
final order from the PUCT is expected in the first half of 2003. Any under or
over-recovery, plus interest thereon, will be recovered from or returned to
customers as a component of the 2004 true-up proceeding.

     Price to Beat Clawback Component: The amount TCC or TNC recovers in the
2004 true-up proceeding could be reduced (or the amount TCC or TNC must refund
could be increased) by the PTB clawback component. If MECPL and MEWTU (which are
no longer affiliated with TCC or TNC) continue to serve 60% or more of TCC's and
TNC's respective PTB load as of January 1, 2004 and the PTB (reduced by
non-bypassable wires charges) exceeds the market price of electricity, any such
excess must be credited to customers of TCC and TNC in the 2004 true-up
proceeding, by up to $150 per customer, subject to certain adjustments. The
Texas Act provides that MECPL and MEWTU effectively indemnify TCC and TNC,
respectively, for any PTB clawback amounts assessed them. The MECPL and MEWTU
sale agreements provide that Centrica (as purchaser of MECPL and MEWTU) and AEP
Utilities (the parent of TCC and TNC, as seller of MECPL and MEWTU) will share
responsibility for this indemnity.

     Further Securitization Bonds and Wires Charges: After final determination
of its stranded costs and other true-up adjustments by the PUCT, TCC expects to
issue securitization bonds in the amount of its non-securitized stranded costs
and generation-related regulatory assets determined in the 2004 true-up
proceeding. The bonds can have a maximum term of 15 years. If securitization
bonds are not issued to finance all non-securitized stranded costs and
generation-related regulatory assets, TCC will seek recovery of these amounts as
well as its other true-up adjustments, through a non-bypassable competition
transition charge in transmission and distribution rates.

     For a discussion of recovery of regulatory assets and stranded costs in
Ohio and Virginia, see Note 8 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, incorporated by reference in Item 8.

OTHER INVESTMENTS

     AEP has made certain investments in telecommunications, international
energy and other concerns. In 2002, AEP wrote down the value of certain of those
investments. See Management's Discussion and Analysis of Results of Operations
and Management's Discussion and Analysis of Financial Condition, Accounting
Policies and Other Matters and Note 13 to the consolidated financial statements
entitled Asset Impairment and Investment Value Losses, incorporated by reference
in Items 7 and 8, respectively.

     AEP also sold the following foreign investments in 2002:

     - SEEBOARD, an electricity supply and distribution company in the United
       Kingdom serving 2,000,000 customers and covering 3,000 square miles of
       service territory.

     - CitiPower, a retail electricity and gas supply and distribution
       subsidiary in Australia serving 240,000 customers.

                                        25
<PAGE>

Item 2. PROPERTIES
- --------------------------------------------------------------------------------

GENERATION FACILITIES

 General

     At December 31, 2002, the AEP System owned (or leased where indicated)
generating plants with net power capabilities (east zone public utility
subsidiaries-winter rating; west zone public utility subsidiaries-summer rating)
shown in the following table:

<Table>
<Caption>
                                            COAL    NATURAL GAS   HYDRO   NUCLEAR   LIGNITE   OTHER   TOTAL
COMPANY                      STATIONS        MW         MW         MW       MW        MW       MW       MW
- ------------------------------------------------------------------------------------------------------------
<S>                          <C>           <C>      <C>           <C>     <C>       <C>       <C>     <C>
AEGCo                            1(a)       1,300                                                      1,300
APCo                            17(b)       5,073                  777                                 5,850
CSPCo                            6(e)       2,595                                                      2,595
I&M                             10(a)       2,295                   11     2,110                       4,416
KPCo                             1          1,060                                                      1,060
OPCo                             8(b)(f)    8,472                   48                                 8,520
PSO                              8(c)       1,043      3,169                                   25(g)   4,237
SWEPCo                           9          1,848      1,797                          842              4,487
TCC                             12(c)(d)(h)   686      3,175         6       630                       4,497
TNC                             12(c)         377        999                                   16(g)   1,392
- ------------------------------------------------------------------------------------------------------------
Totals:                         84         24,749      9,140       842     2,740      842      41     38,354
- ------------------------------------------------------------------------------------------------------------
</Table>

- ------------------------------------

(a) Unit 1 of the Rockport Plant is owned one-half by AEGCo and one-half by I&M.
    Unit 2 of the Rockport Plant is leased one-half by AEGCo and one-half by
    I&M. The leases terminate in 2022 unless extended.

(b) Unit 3 of the John E. Amos Plant is owned one-third by APCo and two-thirds
    by OPCo.

(c) PSO, TCC and TNC jointly own the Oklaunion power station. Their respective
    ownership interests are reflected in this table.

(d) Reflects TCC's interest in STP.

(e) CSPCo owns generating units in common with CG&E and DP&L. Its ownership
    interest of 1,330 MW is reflected in this table.

(f) The scrubber facilities at the General James M. Gavin Plant are leased. The
    lease terminates in 2010 unless extended.

(g) PSO and TNC have 25 MW and 10 MW respectively of facilities designed
    primarily to burn oil. TNC has one 6 MW wind farm facility.

(h) See Item 1 -- Wholesale Operations -- Power Generation -- Planned
    Deactivation and Planned Disposition of Generation Facilities for a
    discussion of TCC's planned disposition of its generation facilities.

     In addition to the generating facilities described above, AEP has ownership
interests in other electrical generating facilities, both foreign and domestic.
Information concerning these facilities at December 31, 2002 is listed below.

<Table>
<Caption>
                                                                             CAPACITY   OWNERSHIP
FACILITY                                  FUEL             LOCATION          TOTAL MW   INTEREST    STATUS
- ----------------------------------------------------------------------------------------------------------
<S>                                    <C>           <C>                     <C>        <C>         <C>
Brush II                               Natural gas         Colorado              68       47.75%     QF
Eastex                                 Natural gas           Texas              440          50%     QF
Indian Mesa                               Wind               Texas              161         100%     EWG
Mulberry                               Natural gas          Florida             120       46.25%     QF
Newgulf                                Natural gas           Texas               85         100%     EWG
Orange Cogen                           Natural gas          Florida             103          50%     QF
Sweeny                                 Natural gas           Texas              480          50%     QF
Thermo Cogeneration                    Natural gas         Colorado             272          50%     QF
Trent Wind Farm                           Wind               Texas              150         100%     EWG
- ----------------------------------------------------------------------------------------------------------
Total U.S.                                                                    1,879
- ----------------------------------------------------------------------------------------------------------
</Table>

                                        26
<PAGE>

<Table>
<Caption>
                                                                             CAPACITY   OWNERSHIP
FACILITY                                  FUEL             LOCATION          TOTAL MW   INTEREST    STATUS
- ----------------------------------------------------------------------------------------------------------
<S>                                    <C>           <C>                     <C>        <C>         <C>
Bajio                                  Natural gas          Mexico              605          50%    FUCO
Ferrybridge                               Coal          United Kingdom        2,000         100%    FUCO
Fiddler's Ferry                           Coal          United Kingdom        2,000         100%    FUCO
Nanyang                                   Coal               China              250          70%    FUCO
Southcoast                             Natural gas      United Kingdom          380          50%    FUCO
- ----------------------------------------------------------------------------------------------------------
Total International                                                           5,235
- ----------------------------------------------------------------------------------------------------------
</Table>

     See Item 1 -- Wholesale Operations for information concerning natural gas
pipelines, storage and processing facilities, transportation related assets and
coal operations and reserves owned or controlled by AEP subsidiaries.

 Cook Nuclear Plant and STP

     The following table provides operating information relating to the Cook
Plant and STP.

<Table>
<Caption>
                            COOK PLANT                STP(A)
                       ---------------------   ---------------------
                        UNIT 1      UNIT 2      UNIT 1      UNIT 2
                       ---------   ---------   ---------   ---------
<S>                    <C>         <C>         <C>         <C>
YEAR PLACED IN
  OPERATION..........       1975        1978        1988        1989
YEAR OF EXPIRATION OF
  NRC LICENSE (B)....       2014        2017        2027        2028
NOMINAL NET
  ELECTRICAL RATING
  IN KILOWATTS.......  1,020,000   1,090,000   1,250,600   1,250,600
NET CAPACITY FACTORS
  2002...............       86.6%       80.5%       99.2%       75.0%
  2001 (C)...........       87.3%       83.4%       94.4%       87.1%
  2000 (D)...........        1.4%       50.0%       78.2%       96.1%
</Table>

- ------------------------------------

(a) Reflects total plant.

(b) For economic or other reasons, operation of the Cook Plant and STP for the
    full term of their operating licenses cannot be assured.

(c) The capacity factor for both units of the Cook Plant was significantly
    reduced in 2001 due to an unplanned dual maintenance outage in September
    2001 to implement design changes that improved the performance of the
    essential service water system.

(d) The Cook Plant was shut down in September 1997 to respond to issues raised
    regarding the operability of certain safety systems. The restart of both
    units of the Cook Plant was completed with Unit 2 reaching 100% power on
    July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.

     Costs associated with the operation (excluding fuel), maintenance and
retirement of nuclear plants continue to be of greater significance and less
predictable than costs associated with other sources of generation, in large
part due to changing regulatory requirements and safety standards, availability
of nuclear waste disposal facilities and experience gained in the construction
and operation of nuclear facilities. I&M and TCC may also incur costs and
experience reduced output at Cook Plant and STP, respectively, because of the
design criteria prevailing at the time of construction and the age of the
plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP
initiatives have contributed to slowing the growth of operating and maintenance
costs at these plants. However, the ability of I&M and TCC to obtain adequate
and timely recovery of costs associated with the Cook Plant and STP,
respectively, including replacement power, any unamortized investment at the end
of the useful life of the Cook Plant and STP (whether scheduled or premature),
the carrying costs of that investment and retirement costs, is not assured. See
Item 1 -- Wholesale Operations -- Power Generation -- Planned Deactivation and
Planned Disposition of Generation Facilities for a discussion of TCC's planned
disposition of its interest in STP.

POTENTIAL UNINSURED LOSSES

     Some potential losses or liabilities may not be insurable or the amount of
insurance carried may not be sufficient to meet potential losses and
liabilities, including liabilities relating to damage to the Cook Plant or STP
and costs of replacement power in the event of a nuclear incident at the Cook
Plant or STP. Future losses or liabilities which are not completely insured,
unless allowed to be recovered through rates, could have a material adverse
effect on results of operations and the financial condition of AEP, I&M, TCC and
other AEP System companies. See Note 9 to the consolidated financial statements
entitled Commitments and Contingencies, incorporated by reference in Item 8, for
information with respect to nuclear incident liability insurance.

                                        27
<PAGE>

TRANSMISSION AND DISTRIBUTION FACILITIES

     The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System and its operating
companies and that portion of the total representing 765,000-volt lines:

<Table>
<Caption>
                         TOTAL OVERHEAD
                        CIRCUIT MILES OF
                        TRANSMISSION AND     CIRCUIT MILES OF
                       DISTRIBUTION LINES   765,000-VOLT LINES
                       ------------------   ------------------
<S>                    <C>                  <C>
AEP System (a).......        226,330(b)           2,023
  APCo. .............         50,756                642
  CSPCo (a)..........         12,255                 --
  I&M................         25,128                615
  Kingsport Power
     Company.........          1,335                 --
  KPCo. .............         10,555                258
  OPCo. .............         35,551                509
  PSO................         21,539                 --
  SWEPCo.............         20,075                 --
  TCC................         33,515                 --
  TNC................         13,637                 --
  Wheeling Power
     Company.........          1,941                 --
</Table>

- ------------------------------------

(a) Includes 766 miles of 345,000-volt jointly owned lines.

(b) Includes 73 miles of transmission lines not identified with an operating
    company.

TITLES

     The AEP System's electric generating stations are generally located on
lands owned in fee simple. The greater portion of the transmission and
distribution lines of the System has been constructed over lands of private
owners pursuant to easements or along public highways and streets pursuant to
appropriate statutory authority. The rights of the System in the realty on which
its facilities are located are considered by it to be adequate for its use in
the conduct of its business. Minor defects and irregularities customarily found
in title to properties of like size and character may exist, but such defects
and irregularities do not materially impair the use of the properties affected
thereby. System companies generally have the right of eminent domain whereby
they may, if necessary, acquire, perfect or secure titles to or easements on
privately held lands used or to be used in their utility operations.

     Substantially all the fixed physical properties and franchises of the AEP
System operating companies, except for limited exceptions, are subject to the
lien of the mortgage and deed of trust securing the first mortgage bonds of each
such company.

SYSTEM TRANSMISSION LINES AND FACILITY SITING

     Legislation in the states of Arkansas, Indiana, Kentucky, Michigan, Ohio,
Texas, Virginia, and West Virginia requires prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. Delays
and additional costs in constructing facilities have been experienced as a
result of proceedings conducted pursuant to such statutes, as well as in
proceedings in which operating companies have sought to acquire rights-of-way
through condemnation, and such proceedings may result in additional delays and
costs in future years.

CONSTRUCTION PROGRAM

 General

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

 Proposed Transmission Facilities

     APCo is proceeding with its plan to build the Wyoming-Jacksons Ferry
765,000-volt transmission line. The WVPSC and the VSCC have issued certificates
authorizing construction and operation of the line. On December 31, 2002, the
U.S. Forest Service issued a final environmental impact statement and record of
decision to allow the use of federal lands in the Jefferson National Forest for
construction of a portion of the line. Additional state and federal permits are
expected to be issued in the first half of 2003. Through December 31, 2002 APCo
had invested approximately $51 million in this project. The line is estimated to
cost $287 million with completion scheduled in 2006.

                                        28
<PAGE>

 Construction Expenditures

     The following table shows construction expenditures during 2000, 2001 and
2002 and current estimates of 2003 construction expenditures, in each case
including AFUDC but excluding assets acquired under leases.

<Table>
<Caption>
                          2000         2001         2002         2003
                         ACTUAL       ACTUAL       ACTUAL      ESTIMATE
                       ----------   ----------   ----------   ----------
                                        (IN THOUSANDS)
<S>                    <C>          <C>          <C>          <C>
AEP System (a).......  $1,773,400   $1,832,000   $1,709,800   $1,458,100
  AEGCo. ............       5,200        6,900        5,300       21,400
  APCo. .............     199,300      306,000      276,500      247,900
  CSPCo. ............     128,000      132,500      136,800      142,300
  I&M................     171,100       91,100      159,400      188,000
  KPCo. .............      36,200       37,200      178,700       72,300
  OPCo. .............     254,000      344,600      354,800      241,000
  PSO................     176,900      124,900       89,400       81,500
  SWEPCo. ...........     120,200      112,100      111,800      104,900
  TCC................     199,500      194,100      151,500      126,800
  TNC................      64,500       39,800       43,600       46,500
</Table>

(a) Includes expenditures of other subsidiaries not shown.

     See Note 9 to the consolidated financial statements entitled Commitments
and Contingencies, incorporated by reference in Item 8, for further information
with respect to the construction plans of AEP and its operating subsidiaries for
the next three years.

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

Item 3. LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------

     For a discussion of material legal proceedings, see Note 9 to the
consolidated financial statements, entitled Commitments and Contingencies,
incorporated by reference in Item 8.

                                        29
<PAGE>

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
- --------------------------------------------------------------------------------

     AEP, APCO, I&M, OPCO, SWEPCO AND TCC. None.

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).

                             ---------------------

EXECUTIVE OFFICERS OF THE REGISTRANTS

     AEP.  The following persons are, or may be deemed, executive officers of
AEP. Their ages are given as of March 1, 2003.

<Table>
<Caption>
NAME                             AGE                            OFFICE (A)
- ----                             ---                            ----------
<S>                              <C>   <C>
E. Linn Draper, Jr. ...........  61    Chairman of the Board, President and Chief Executive Officer
                                       of AEP and of the Service Corporation

Thomas V. Shockley, III........  57    Vice Chairman of AEP and Vice Chairman and Chief Operating
                                       Officer of the Service Corporation

Henry W. Fayne.................  56    Vice President of AEP, Executive Vice President of the
                                       Service Corporation

Thomas M. Hagan................  58    Executive Vice President-Shared Services of the Service
                                       Corporation

Holly K. Koeppel...............  44    Executive Vice President of the Service Corporation

Robert P. Powers...............  49    Executive Vice President-Nuclear Generation and Technical
                                       Services of the Service Corporation

Susan Tomasky..................  49    Vice President of AEP, Executive Vice President-Policy,
                                       Finance and Strategic Planning of the Service Corporation
</Table>

- ---------------

(a) Dr. Draper and Mr. Fayne have been employed by the Service Corporation or
    System companies in various capacities (AEP, as such, has no employees) for
    the past five years. Prior to joining the Service Corporation in July 1998
    as Senior Vice President-Generation, Mr. Powers was Vice President of
    Pacific Gas & Electric and plant manager of its Diablo Canyon Nuclear
    Generating Station (1996-1998). Prior to joining the Service Corporation in
    July 1998 as Senior Vice President, Ms. Tomasky was a partner with the law
    firm of Hogan & Hartson (August 1997-July 1998) and General Counsel of the
    Federal Energy Regulatory Commission (May 1993-August 1997). Prior to
    joining the Service Corporation in June 2000 as Senior Vice President-
    Governmental Affairs, Mr. Hagan was Senior Vice President-External Affairs
    of CSW. Prior to joining the Service Corporation in July 2000 as Vice
    President-New Ventures, Ms. Koeppel was Regional Vice President of
    Asia-Pacific Operations for Consolidated Natural Gas International
    (1996-2000). Messrs. Hagan and Powers, Ms. Koeppel and Ms. Tomasky became
    executive officers of AEP effective with their promotions to Executive Vice
    President on September 9, 2002, October 24, 2001, November 18, 2002 and
    January 26, 2000, respectively. Prior to joining the Service Corporation in
    his current position upon the merger with CSW, Mr. Shockley was President
    and Chief Operating Officer of CSW (1997-2000) and Executive Vice President
    of CSW (1990-1997). All of the above officers are appointed annually for a
    one-year term by the board of directors of AEP, the board of directors of
    the Service Corporation, or both, as the case may be.

     APCO, I&M, OPCO, SWEPCO AND TCC.  The names of the executive officers of
APCo, I&M, OPCo, SWEPCo and TCC, the positions they hold with these companies,
their ages as of March 1, 2003, and a brief account of their business experience
during the past five years appear below. The directors and executive officers of
APCo, I&M, OPCo, SWEPCo and TCC are elected annually to serve a one-year term.

                                        30
<PAGE>

<Table>
<Caption>
NAME                             AGE                      POSITION (A)(B)                         PERIOD
- ----                             ---                      ---------------                         ------
<S>                              <C>   <C>                                                     <C>
E. Linn Draper, Jr. ...........  61    Director of SWEPCo and TCC                              2000-Present
                                       Chairman of the Board and Chief Executive Officer
                                       of SWEPCo and TCC                                       2000-Present
                                       Director of APCo, I&M and OPCo                          1992-Present
                                       Chairman of the Board and Chief Executive Officer
                                       of APCo, I&M and OPCo                                   1993-Present
                                       Chairman of the Board, President and Chief
                                       Executive Officer of AEP and the Service Corporation    1993-Present

Thomas V. Shockley, III........  57    Director and Vice President of APCo, I&M, OPCo,
                                       SWEPCo and TCC                                          2000-Present
                                       Chief Operating Officer of the Service Corporation      2001-Present
                                       Vice Chairman of AEP and the Service Corporation        2000-Present
                                       President and Chief Operating Officer of CSW               1997-2000
                                       Executive Vice President of CSW                            1990-1997

Henry W. Fayne.................  56    President of APCo, I&M, OPCo, SWEPCo and TCC            2001-Present
                                       Director of SWEPCo and TCC                              2000-Present
                                       Director of APCo                                        1995-Present
                                       Director of OPCo                                        1993-Present
                                       Director of I&M                                         1998-Present
                                       Vice President of SWEPCo and TCC                           2000-2001
                                       Vice President of APCo, I&M and OPCo                       1998-2001
                                       Vice President of AEP                                   1998-Present
                                       Chief Financial Officer of AEP                             1998-2001
                                       Executive Vice President of the Service Corporation     2001-Present
                                       Executive Vice President-Finance and Analysis of
                                       the Service Corporation                                    2000-2001
                                       Executive Vice President-Financial Services of the
                                       Service Corporation                                        1998-2000
                                       Senior Vice President-Corporate Planning & Budgeting
                                       of the Service Corporation                                 1995-1998


Thomas M. Hagan................  58    Director and Vice President of APCo, I&M, OPCo,
                                       SWEPCo and TCC                                          2002-Present
                                       Executive Vice President-Shared Services of the
                                       Service Corporation                                     2002-Present
                                       Senior Vice President-Governmental Affairs of the
                                       Service Corporation                                        2000-2002
                                       Senior Vice President-External Affairs of CSW              1996-2000

Holly K. Koeppel...............  44    Executive Vice President of the Service Corporation     2002-Present
                                       Vice President-New Ventures                                2000-2002
                                       Regional Vice President of Asia-Pacific Operations
                                       for Consolidated Natural Gas International                 1996-2000
</Table>

                                        31
<PAGE>

<Table>
<Caption>
NAME                             AGE                      POSITION (A)(B)                         PERIOD
- ----                             ---                      ---------------                         ------
<S>                              <C>   <C>                                                     <C>
Robert P. Powers...............  49    Director and Vice President of APCo, I&M, OPCo,
                                       SWEPCo and TCC                                          2001-Present
                                       Director of I&M                                         2001-Present
                                       Vice President of I&M                                   1998-Present
                                       Executive Vice President- Generation                    2003-Present
                                       Executive Vice President-Nuclear Generation and
                                       Technical Services of the Service Corporation              2001-2003
                                       Senior Vice President-Nuclear Operations of the
                                       Service Corporation                                        2000-2001
                                       Senior Vice President-Nuclear Generation of the
                                       Service Corporation                                        1998-2000
                                       Vice President of Pacific Gas & Electric and Plant
                                       Manager of its Diablo Canyon Nuclear Generating
                                       Station                                                    1996-1998

Susan Tomasky..................  49    Director and Vice President of APCo, I&M, OPCo,
                                       SWEPCo and TCC                                          2000-Present
                                       Executive Vice President-Policy, Finance and
                                       Strategic Planning of the Service Corporation           2001-Present
                                       Executive Vice President-Legal, Policy and
                                       Corporate Communications and General Counsel of
                                       the Service Corporation                                    2000-2001
                                       Senior Vice President and General Counsel of the
                                       Service Corporation                                        1998-2000
                                       Hogan & Hartson (law firm)                                 1997-1998
                                       General Counsel of the FERC                                1993-1997

</Table>

- ---------------

(a) Dr. Draper is a director of BCP Management, Inc., which is the general
    partner of Borden Chemicals and Plastics L.P.

(b) Dr. Draper, Messrs. Fayne, Hagan, Powers and Shockley and Ms. Tomasky are
    directors of AEGCo, CSPCo, KPCo, PSO and TNC. Dr. Draper and Mr. Shockley
    are also directors of AEP.

PART II
- --------------------------------------------------------------------------------

Item 5. MARKET FOR REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------

     AEP. The information required by this item is incorporated herein by
reference to the material under Common Stock and Dividend Information in the
2002 Annual Report.

     AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The common
stock of these companies is held solely by AEP. The amounts of cash dividends on
common stock paid by these companies to AEP during 2002 and 2001 are
incorporated by reference to the material under Statement of Retained Earningsin
the 2002 Annual Reports.

Item 6. SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a).

     AEP, APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item
is incorporated herein by reference to the material under Selected Consolidated
Financial Data in the 2002 Annual Reports.

                                        32
<PAGE>

Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
        FINANCIAL CONDITION
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(a).
Management's narrative analysis of the results of operations and other
information required by Instruction I(2)(a) is incorporated herein by reference
to the material under Management's Narrative Analysis of Results of Operations
in the 2002 Annual Reports.

     AEP, APCO, I&M, OPCO, SWEPCO AND TCC. The information required by this item
is incorporated herein by reference to the material under Management's
Discussion and Analysis of Results of Operations and Management's Discussion and
Analysis of Financial Condition, Contingencies and Other Matters in the 2002
Annual Reports.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------

     AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The
information required by this item is incorporated herein by reference to the
material under Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the 2002 Annual Reports.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------

     AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. The
information required by this item is incorporated herein by reference to the
financial statements and financial statement schedules described under Item 15
herein.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE
- --------------------------------------------------------------------------------

     AEGCO, AEP, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC. None.

PART III
- --------------------------------------------------------------------------------

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).

     AEP. The information required by this item is incorporated herein by
reference to the material under Nominees for Director and Section 16(a)
Beneficial Ownership Reporting Compliance of the definitive proxy statement of
AEP for the 2003 annual meeting of shareholders, to be filed within 120 days
after December 31, 2002. Reference also is made to the information under the
caption Executive Officers of the Registrants in Part I of this report.

     APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Election of Directors of the definitive
information statement of each company for the 2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.

     SWEPCO AND TCC. The information required by this item is incorporated
herein by reference to the material under Election of Directors of the
definitive information statement of APCo for the 2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.

     I&M. The names of the directors and executive officers of I&M, the
positions they hold with I&M, their ages as of March 12, 2003, and a brief
account of their business experience during the past five years appear below and
under the caption Executive Officers of the Registrants in Part I of this
report.

                                        33
<PAGE>

<Table>
<Caption>
NAME                             AGE                      POSITION (A)                          PERIOD
- ----                             ---                      ------------                          ------
<S>                              <C>   <C>                                                   <C>
K. G. Boyd.....................  51    Director                                              1997-Present
                                       Vice President (Appointed) -- Fort Wayne Region
                                       Distribution Operations                               2000-Present
                                       Indiana Region Manager                                   1997-2000

John E. Ehler..................  46    Director                                              2001-Present
                                       Manager of Distribution Systems-Fort Wayne District   2000-Present
                                       Region Operations Manager                                1997-2000

David L. Lahrman...............  51    Director and Manager, Region Support                  2001-Present
                                       Fort Wayne District Manager                              1997-2001

Marc E. Lewis..................  48    Director                                              2001-Present
                                       Assistant General Counsel of the Service
                                       Corporation                                           2001-Present
                                       Senior Counsel of the Service Corporation                2000-2001
                                       Senior Attorney of the Service Corporation               1994-2000

Susanne M. Moorman.............  53    Director and General Manager, Community Services      2000-Present
                                       Manager, Customer Services Operations                    1997-2000

John R. Sampson................  50    Director and Vice President                           1999-Present
                                       Indiana State President                               2000-Present
                                       Indiana & Michigan State President                       1999-2000
                                       Site Vice President, Cook Nuclear Plant                  1998-1999
                                       Plant Manager, Cook Nuclear Plant                        1996-1998

D. B. Synowiec.................  59    Director                                              1995-Present
                                       Plant Manager, Rockport Plant                         1990-Present

</Table>

- ---------------

(a) Positions are with I&M unless otherwise indicated.

Item 11. EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).

     AEP. The information required by this item is incorporated herein by
reference to the material under Directors Compensation and Stock Ownership
Guidelines, Executive Compensation and the performance graph of the definitive
proxy statement of AEP for the 2003 annual meeting of shareholders to be filed
within 120 days after December 31, 2002.

     APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Executive Compensation of the definitive
information statement of each company for the 2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002.

     I&M, SWEPCO AND TCC. The information required by this item is incorporated
herein by reference to the material under Executive Compensationof the
definitive information statement of APCo for the 2003 annual meeting of
stockholders, to be filed within 120 days after December 31, 2002.

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDER MATTERS
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KPCO, PSO AND TNC. Omitted pursuant to Instruction I(2)(c).

     AEP. The information required by this item is incorporated herein by
reference to the material under Share Ownership of Directors and Executive
Officers of the definitive proxy statement of AEP for the 2003 annual meeting of
shareholders to be filed within 120 days after December 31, 2002.

     APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information state-

                                        34
<PAGE>

ment of each company for the 2003 annual meeting of stockholders, to be filed
within 120 days after December 31, 2002.

     I&M. All 1,400,000 outstanding shares of Common Stock, no par value, of I&M
are directly and beneficially held by AEP. Holders of the Cumulative Preferred
Stock of I&M generally have no voting rights, except with respect to certain
corporate actions and in the event of certain defaults in the payment of
dividends on such shares.

     SWEPCO AND TCC. The information required by this item is incorporated
herein by reference to the material under Share Ownership of Directors and
Executive Officers in the definitive information statement of APCo for the 2003
annual meeting of stockholders, to be filed within 120 days after December 31,
2002.

     The table below shows the number of shares of AEP Common Stock and
stock-based units that were beneficially owned, directly or indirectly, as of
January 1, 2003, by each director and nominee of I&M and each of the executive
officers of I&M named in the summary compensation table, and by all directors
and executive officers of I&M as a group. It is based on information provided to
I&M by such persons. No such person owns any shares of any series of the
Cumulative Preferred Stock of I&M. Unless otherwise noted, each person has sole
voting power and investment power over the number of shares of AEP Common Stock
and stock-based units set forth opposite his or her name. Fractions of shares
and units have been rounded to the nearest whole number.

<Table>
<Caption>
                                                                                  STOCK
NAME                                                          SHARES (A)        UNITS (B)      TOTAL
- ----                                                          ----------        ---------    ---------
<S>                                                           <C>               <C>          <C>
Karl G. Boyd................................................     10,675              607        11,282
E. Linn Draper, Jr. ........................................    472,034(c)       117,803       589,837
John E. Ehler...............................................         11               --            11
Henry W. Fayne..............................................    139,787(d)        12,362       152,149
Thomas M. Hagan.............................................     54,392              140        54,532
David L. Lahrman............................................        430               --           430
Marc E. Lewis...............................................      3,290               --         3,290
Susanne M. Moorman..........................................        908               --           908
Robert P. Powers............................................     65,862            1,293        67,155
John R. Sampson.............................................     10,643              173        10,816
Thomas V. Shockley, III.....................................    211,067(d)(e)         --       211,067
David B. Synowiec...........................................      7,645              182         7,827
Susan Tomasky...............................................    134,449(d)         6,126       140,575
All Directors and Executive Officers........................  1,196,424(d)(f)    138,686     1,335,110
</Table>

- ---------------

(a) Includes share equivalents held in the AEP Retirement Savings Plan in the
    amounts listed below:

<Table>
<Caption>
              AEP RETIREMENT SAVINGS
    NAME      PLAN (SHARE EQUIVALENTS)
    ----      ------------------------
    <S>                                  <C>
    Mr. Boyd..........................      675
    Dr. Draper........................    4,659
    Mr. Ehler.........................       11
    Mr. Fayne.........................    5,804
    Mr. Hagan.........................    2,515
    Mr. Lahrman.......................      430
    Mr. Lewis.........................    1,207
</Table>

<Table>
<Caption>
             AEP RETIREMENT SAVINGS
    NAME    PLAN (SHARE EQUIVALENTS)
    ----    ------------------------
    <S>                                  <C>
    Ms. Moorman.......................      908
    Mr. Powers........................      596
    Mr. Sampson.......................      643
    Mr. Shockley......................    7,104
    Mr. Synowiec......................    4,312
    Ms. Tomasky.......................    1,116
    All Directors and Executive
      Officers........................   29,980
</Table>

    With respect to the share equivalents held in the AEP Retirement Savings
    Plan, such persons have sole voting power, but the investment/disposition
    power is subject to the terms of the Plan. Also, includes the following
    numbers of shares attributable to options exercisable within 60 days: Mr.
    Boyd, 10,000; Dr. Draper, 466,666;

                                        35
<PAGE>
    Mr. Hagan, 41,666; Mr. Lewis, 2,083; Mr. Powers, 65,266; Mr. Sampson,
    10,000; Mr. Shockley, 166,666; Mr. Synowiec, 3,333; and Mr. Fayne and Ms.
    Tomasky, 133,333.

(b) This column includes amounts deferred in stock units and held under AEP's
    officer benefit plans.

(c) Includes 661 shares held by Dr. Draper in joint tenancy with a family
    member.

(d) Does not include, for Messrs. Fayne, and Shockley and Ms. Tomasky, 85,231
    shares in the American Electric Power System Educational Trust Fund over
    which Messrs. Fayne and Shockley and Ms. Tomasky share voting and investment
    power as trustees (they disclaim beneficial ownership). The amount of shares
    shown for all directors and executive officers as a group includes these
    shares.

(e) Includes 496 shares held by family members of Mr. Shockley over which he
    disclaimed beneficial ownership.

(f) Represents less than 1% of the total number of shares outstanding.

EQUITY COMPENSATION PLAN INFORMATION

     The following table summarizes the ability of AEP to issue common stock
pursuant to equity compensation plans as of December 31, 2002:

<Table>
<Caption>
                                                                                             NUMBER OF SECURITIES
                                                      NUMBER OF                               REMAINING AVAILABLE
                                                  SECURITIES TO BE                            FOR FUTURE ISSUANCE
                                                     ISSUED UPON        WEIGHTED AVERAGE         UNDER EQUITY
                                                     EXERCISE OF        EXERCISE PRICE OF     COMPENSATION PLANS
                                                 OUTSTANDING OPTIONS       OUTSTANDING       (EXCLUDING SECURITIES
                                                    WARRANTS AND        OPTIONS, WARRANTS        REFLECTED IN
                                                       RIGHTS              AND RIGHTS             COLUMN (a))
PLAN CATEGORY                                            (a)                   (b)                    (c)
- -------------                                    -------------------   -------------------   ---------------------
<S>                                              <C>                   <C>                   <C>
Equity compensation plans approved by security
  holders(1)...................................       8,779,217             $33.5767               6,901,693(2)
Equity compensation plans not approved by
  security holders.............................               0                  N/A                       0
  Total........................................       8,779,217             $33.5767               6,901,693
</Table>

- ------------------------------------

(1) Consists of shares to be issued upon exercise of outstanding options granted
    under the American Electric Power System 2000 Long-Term Incentive Plan, the
    CSW 1992 Long-Term Incentive Plan (CSW Plan) and the AEP Deferred
    Compensation and Stock Plan for Non-Employee Directors. The CSW Plan was in
    effect prior to the consummation of the AEP-CSW merger. All unexercised
    options granted under the CSW Plan were converted into 0.6 options to
    purchase AEP common shares, vested on the merger date and will expire ten
    years after their grant date. No additional options will be issued under the
    CSW Plan.

(2) Excludes shares available for further issuance under the AEP Deferred
    Compensation and Stock Plan for Non-Employee Directors, which does not have
    a limit on the number of shares which may be issued. The amount of shares is
    capped, however, by the annual retainer amount paid to the Non-Employee
    Directors.

                                        36

<PAGE>

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------

     AEP, AEGCO, APCO, CSPCO, I&M, KPCO, OPCO, PSO, SWEPCO, TCC AND TNC: None.

                                                                         PART IV
- --------------------------------------------------------------------------------

Item 14. CONTROLS AND PROCEDURES
- --------------------------------------------------------------------------------

     AEP maintains disclosure controls and procedures designed to ensure that
the information AEP must disclose in its filings with the Securities and
Exchange Commission is recorded, processed, summarized and reported on a timely
basis. AEP's principal executive officer and principal financial officer have
reviewed and evaluated AEP's disclosure controls and procedures as defined in
Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as
amended (the Exchange Act) as of a date within 90 days prior to the filing date
of this report (the Evaluation Date). Such officers have concluded that, as of
the Evaluation Date, AEP's disclosure controls and procedures are effective in
accumulating and communicating to management on a timely basis information
required to be disclosed in AEP's periodic filings under the Exchange Act.

     Since the Evaluation Date, there have not been any significant changes in
AEP's internal controls, or in other factors that could significantly affect
these controls.

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
- --------------------------------------------------------------------------------

(a) The following documents are filed as a part of this report:

     1. FINANCIAL STATEMENTS:

       The following financial statements have been incorporated herein by
reference pursuant to Item 8.

<Table>
<Caption>
                                                                     PAGE
                                                                     ----
<S>   <C>                                                            <C>
AEGCo:
Statements of Income for the years ended December 31, 2002, 2001,
and 2000; Statements of Retained Earnings for the years ended
December 31, 2002, 2001, and 2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000; Statements of Capitalization as
of December 31, 2002 and 2001; Combined Notes to Financial
Statements; Independent Auditors' Report.
AEP and Subsidiary Companies:
  Consolidated Statements of Operations for the years ended
  December 31, 2002, 2001, and 2000; Consolidated Balance Sheets
  as of December 31, 2002 and 2001; Consolidated Statements of
  Cash Flows for the years ended December 31, 2002, 2001, and
  2000; Consolidated Statements of Common Shareholders' Equity and
  Comprehensive Income for the years ended December 31, 2002,
  2001, and 2000; Schedule of Consolidated Cumulative Preferred
  Stocks of Subsidiaries at December 31, 2002 and 2001; Schedule
  of Consolidated Long-term Debt of Subsidiaries at December 31,
  2002 and 2001; Combined Notes to Consolidated Financial
  Statements; Independent Auditors' Report.
APCo, CSPCo, I&M, PSO, SWEPCo and TCC:
  Consolidated Statements of Income for the years ended December
  31, 2002, 2001, and 2000; Consolidated Statements of
  Comprehensive Income for the years ended December 31, 2002,
  2001, and 2000; Consolidated Statements of Retained Earnings for
  the years ended December 31, 2002, 2001, and 2000; Consolidated
  Balance Sheets as of December 31, 2002 and 2001; Consolidated
  Statements of Cash Flows for the years ended December 31, 2002,
  2001, and 2000; Consolidated Statements of Capitalization as of
  December 31, 2002 and 2001; Schedule of Long-term Debt as of
  December 31, 2002 and 2001; Combined Notes to Consolidated
  Financial Statements; Independent Auditors' Report.
</Table>

                                        37
<PAGE>

KPCo, OPCo and TNC:
Statements of Income (or Statements of Operations) for the years
ended December 31, 2002, 2001, and 2000; Statements of
Comprehensive Income for the years ended December 31, 2002, 2001,
and 2000; Statements of Retained Earnings for the years ended
December 31, 2002, 2001, and 2000; Balance Sheets as of December
31, 2002 and 2001; Statements of Cash Flows for the years ended
December 31, 2002, 2001, and 2000; Statements of Capitalization as
of December 31, 2002 and 2001; Schedule of Long-term Debt as of
December 31, 2002 and 2001; Combined Notes to Financial
Statements; Independent Auditors' Report.
    2.  FINANCIAL STATEMENT SCHEDULES:
       Financial Statement Schedules are listed in the Index to      S-1
  Financial Statement Schedules (Certain schedules have been
  omitted because the required information is contained in the
  notes to financial statements or because such schedules are not
  required or are not applicable). Independent Auditors' Report
    3.  EXHIBITS:
       Exhibits for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO,   E-1
  SWEPCo, TCC and TNC are listed in the Exhibit Index and are
  incorporated herein by reference

(b) Reports on Forms 8-K:

<Table>
<Caption>
COMPANY REPORTING                       DATE OF REPORT                     ITEM REPORTED
- -----------------                      -----------------   ----------------------------------------------
<S>                                    <C>                 <C>
APCo, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, TCC and TNC..................  November 18, 2002   Item 5. Other Events
I&M..................................  November 22, 2002   Item 5. Other Events
                                                           Item 7. Financial Statements and Exhibits
I&M..................................  November 25, 2002   Item 5. Other Events
                                                           Item 7. Financial Statements and Exhibits
PSO..................................  November 26, 2002   Item 5. Other Events
                                                           Item 7. Financial Statements and Exhibits
</Table>

     Reports on Forms 8-K/A:

<Table>
<Caption>
COMPANY REPORTING                       DATE OF REPORT                     ITEM REPORTED
- -----------------                      -----------------   ----------------------------------------------
<S>                                    <C>                 <C>
PSO, SWEPCo, TCC and TNC.............  November 26, 2002   Item 7. Financial Statements and Exhibits
</Table>

(c) Exhibits: See Exhibit Index beginning on page E-1.

                                        38
<PAGE>

                                   SIGNATURES

     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.

                                         AMERICAN ELECTRIC POWER COMPANY, INC.

                                           By:
                                           /s/ SUSAN TOMASKY
                                           -------------------------------------
                                              (SUSAN TOMASKY, VICE PRESIDENT,
                                               SECRETARY AND CHIEF FINANCIAL
                                                           OFFICER)

Date: March 20, 2003

     PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.

<Table>
<Caption>
                   SIGNATURE                                       TITLE                          DATE
                   ---------                                       -----                          ----
<C>                                               <C>                                        <S>
      (I)    PRINCIPAL EXECUTIVE OFFICER:

              *E. LINN DRAPER, JR.                         Chairman of the Board,            March 20, 2003
                                                                 President,
                                                          Chief Executive Officer
                                                                And Director

      (II)    PRINCIPAL FINANCIAL OFFICER:

               /s/ SUSAN TOMASKY                       Vice President, Secretary and         March 20, 2003
- ------------------------------------------------          Chief Financial Officer
                (SUSAN TOMASKY)

     (III)    PRINCIPAL ACCOUNTING OFFICER:

            /s/ JOSEPH M. BUONAIUTO                            Controller and                March 20, 2003
- ------------------------------------------------          Chief Accounting Officer
             (JOSEPH M. BUONAIUTO)

      (IV)    A MAJORITY OF THE DIRECTORS:

                 *E. R. BROOKS
               *DONALD M. CARLTON
               *JOHN P. DESBARRES
                 *ROBERT W. FRI
               *WILLIAM R. HOWELL
             *LESTER A. HUDSON, JR.
               *LEONARD J. KUJAWA
               *RICHARD L. SANDOR
            *THOMAS V. SHOCKLEY, III
                *DONALD G. SMITH
            *LINDA GILLESPIE STUNTZ
              *KATHRYN D. SULLIVAN                                                           March 20, 2003

             *By: /s/ SUSAN TOMASKY
   ------------------------------------------
       (SUSAN TOMASKY, ATTORNEY-IN-FACT)
</Table>

                                        39
<PAGE>

                                   SIGNATURES

     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                         AEP GENERATING COMPANY
                                         AEP TEXAS CENTRAL COMPANY
                                         AEP TEXAS NORTH COMPANY
                                         APPALACHIAN POWER COMPANY
                                         COLUMBUS SOUTHERN POWER COMPANY
                                         KENTUCKY POWER COMPANY
                                         OHIO POWER COMPANY
                                         PUBLIC SERVICE COMPANY OF OKLAHOMA
                                         SOUTHWESTERN ELECTRIC POWER COMPANY

                                           By:
                                           /s/ SUSAN TOMASKY
                                           -------------------------------------
                                              (SUSAN TOMASKY, VICE PRESIDENT)

Date: March 20, 2003

     PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<Table>
<Caption>
                   SIGNATURE                                       TITLE                          DATE
                   ---------                                       -----                          ----
<C>                                               <C>                                        <S>
      (i)    PRINCIPAL EXECUTIVE OFFICER:

              *E. LINN DRAPER, JR.                         Chairman of the Board,            March 20, 2003
                                                                 President,
                                                          Chief Executive Officer
                                                                And Director

      (ii)    PRINCIPAL FINANCIAL OFFICER:

               /s/ SUSAN TOMASKY                         Vice President, Secretary,          March 20, 2003
- ------------------------------------------------    Chief Financial Officer and Director
                (SUSAN TOMASKY)

     (iii)    PRINCIPAL ACCOUNTING OFFICER:

            /s/ JOSEPH M. BUONAIUTO                            Controller and                March 20, 2003
- ------------------------------------------------          Chief Accounting Officer
             (JOSEPH M. BUONAIUTO)

      (iv)    A MAJORITY OF THE DIRECTORS:

                *HENRY W. FAYNE
                *THOMAS M. HAGAN
                  *A. A. PENA
               *ROBERT P. POWERS
            *THOMAS V. SHOCKLEY, III                                                         March 20, 2003

             *By: /s/ SUSAN TOMASKY
   ------------------------------------------
       (SUSAN TOMASKY, ATTORNEY-IN-FACT)
</Table>

                                        40
<PAGE>

                                   SIGNATURES

     PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. THE SIGNATURE OF THE
UNDERSIGNED COMPANY SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING REFERENCE
TO SUCH COMPANY AND ANY SUBSIDIARIES THEREOF.

                                         INDIANA MICHIGAN POWER COMPANY

                                           By:
                                           /s/ SUSAN TOMASKY
                                           -------------------------------------
                                              (SUSAN TOMASKY, VICE PRESIDENT)

Date: March 20, 2003

     PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED. THE SIGNATURE OF
EACH OF THE UNDERSIGNED SHALL BE DEEMED TO RELATE ONLY TO MATTERS HAVING
REFERENCE TO THE ABOVE-NAMED COMPANY AND ANY SUBSIDIARIES THEREOF.

<Table>
<Caption>
                   SIGNATURE                                       TITLE                          DATE
                   ---------                                       -----                          ----
<C>                                               <C>                                        <S>
      (i)    PRINCIPAL EXECUTIVE OFFICER:

              *E. LINN DRAPER, JR.                         Chairman of the Board,            March 20, 2003
                                                                 President,
                                                          Chief Executive Officer
                                                                and Director

      (ii)    PRINCIPAL FINANCIAL OFFICER:

               /s/ SUSAN TOMASKY                         Vice President, Secretary,          March 20, 2003
- ------------------------------------------------          Chief Financial Officer
                (SUSAN TOMASKY)                                 and Director

     (iii)    PRINCIPAL ACCOUNTING OFFICER:

            /s/ JOSEPH M. BUONAIUTO                            Controller and                March 20, 2003
- ------------------------------------------------          Chief Accounting Officer
             (JOSEPH M. BUONAIUTO)

      (iv)    A MAJORITY OF THE DIRECTORS:

                  *K. G. BOYD
                 *JOHN E. EHLER
                *HENRY W. FAYNE
                *THOMAS M. HAGAN
               *DAVID L. LAHRMAN
                 *MARC E. LEWIS
              *SUSANNE M. MOORMAN
               *ROBERT P. POWERS
                *JOHN R. SAMPSON
            *THOMAS V. SHOCKLEY, III
                *D. B. SYNOWIEC                                                              March 20, 2003

             *By: /s/ SUSAN TOMASKY
   ------------------------------------------
       (SUSAN TOMASKY, ATTORNEY-IN-FACT)
</Table>

                                        41
<PAGE>

                                 CERTIFICATIONS

I, E. Linn Draper, Jr., certify that:

     1.  I have reviewed this annual report on Form 10-K of:

                     American Electric Power Company, Inc.
                             AEP Generating Company
                           AEP Texas Central Company
                            AEP Texas North Company
                           Appalachian Power Company
                        Columbus Southern Power Company
                         Indiana Michigan Power Company
                             Kentucky Power Company
                               Ohio Power Company
                       Public Service Company of Oklahoma
                      Southwestern Electric Power Company

     2.  Based on my knowledge, this annual report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this annual report;

     3.  Based on my knowledge, the financial statements, and other financial
         information included in this annual report, fairly present in all
         material respects the financial condition, results of operations and
         cash flows of the registrant as of, and for, the periods presented in
         this annual report;

     4.  The registrant's other certifying officers and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
         we have:

          a)  designed such disclosure controls and procedures to ensure that
              material information relating to the registrant, including its
              consolidated subsidiaries, is made known to us by others within
              those entities, particularly during the period in which this
              annual report is being prepared;

          b)  evaluated the effectiveness of the registrant's disclosure
              controls and procedures as of a date within 90 days prior to the
              filing date of this annual report (the "Evaluation Date"); and

          c)  presented in this annual report our conclusions about the
              effectiveness of the disclosure controls and procedures based on
              our evaluation as of the Evaluation Date;

     5.  The registrant's other certifying officers and I have disclosed, based
         on our most recent evaluation, to the registrant's auditors and the
         audit committee of registrant's board of directors (or persons
         performing the equivalent function):

          a)  all significant deficiencies in the design or operation of
              internal controls which could adversely affect the registrant's
              ability to record, process, summarize and report financial data
              and have identified for the registrant's auditors any material
              weaknesses in internal controls; and

          b)  any fraud, whether or not material, that involves management or
              other employees who have a significant role in the registrant's
              internal controls; and

     6.  The registrant's other certifying officers and I have indicated in this
         annual report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.

Dated: March 20, 2003                    By:
                                          /s/ E. LINN DRAPER, JR.
                                          --------------------------------------
                                                   E. Linn Draper, Jr.
                                                 Chief Executive Officer

                                        42
<PAGE>

I, Susan Tomasky, certify that:

     1.  I have reviewed this annual report on Form 10-K of:

                     American Electric Power Company, Inc.
                             AEP Generating Company
                           AEP Texas Central Company
                            AEP Texas North Company
                           Appalachian Power Company
                        Columbus Southern Power Company
                         Indiana Michigan Power Company
                             Kentucky Power Company
                               Ohio Power Company
                       Public Service Company of Oklahoma
                      Southwestern Electric Power Company

     2.  Based on my knowledge, this annual report does not contain any untrue
         statement of a material fact or omit to state a material fact necessary
         to make the statements made, in light of the circumstances under which
         such statements were made, not misleading with respect to the period
         covered by this annual report;

     3.  Based on my knowledge, the financial statements, and other financial
         information included in this annual report, fairly present in all
         material respects the financial condition, results of operations and
         cash flows of the registrant as of, and for, the periods presented in
         this annual report;

     4.  The registrant's other certifying officers and I are responsible for
         establishing and maintaining disclosure controls and procedures (as
         defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
         we have:

          a.  designed such disclosure controls and procedures to ensure that
              material information relating to the registrant, including its
              consolidated subsidiaries, is made known to us by others within
              those entities, particularly during the period in which this
              annual report is being prepared;

          b.  evaluated the effectiveness of the registrant's disclosure
              controls and procedures as of a date within 90 days prior to the
              filing date of this annual report (the "Evaluation Date"); and

          c.  presented in this annual report our conclusions about the
              effectiveness of the disclosure controls and procedures based on
              our evaluation as of the Evaluation Date;

     5.  The registrant's other certifying officers and I have disclosed, based
         on our most recent evaluation, to the registrant's auditors and the
         audit committee of registrant's board of directors (or persons
         performing the equivalent function):

          a.  all significant deficiencies in the design or operation of
              internal controls which could adversely affect the registrant's
              ability to record, process, summarize and report financial data
              and have identified for the registrant's auditors any material
              weaknesses in internal controls; and

          b.  any fraud, whether or not material, that involves management or
              other employees who have a significant role in the registrant's
              internal controls; and

     6.  The registrant's other certifying officers and I have indicated in this
         annual report whether or not there were significant changes in internal
         controls or in other factors that could significantly affect internal
         controls subsequent to the date of our most recent evaluation,
         including any corrective actions with regard to significant
         deficiencies and material weaknesses.

Dated: March 20, 2003                    By:
                                          /s/ SUSAN TOMASKY
                                          --------------------------------------
                                                      Susan Tomasky
                                                 Chief Financial Officer

                                        43
<PAGE>

                     INDEX TO FINANCIAL STATEMENT SCHEDULES

<Table>
<Caption>
                                                               PAGE
                                                               ----
<S>                                                            <C>
INDEPENDENT AUDITORS' REPORT................................   S-2

The following financial statement schedules are included in
  this report on the pages indicated

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY
  COMPANIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-3

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-3

AEP TEXAS NORTH COMPANY
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-3

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-4

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-4

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-4

KENTUCKY POWER COMPANY
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-5

OHIO POWER COMPANY
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-5

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-5

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
     Schedule II -- Valuation and Qualifying Accounts and
      Reserves..............................................   S-6
</Table>

                                       S-1
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARIES:

     We have audited the consolidated financial statements of American Electric
Power Company, Inc. and subsidiaries and the financial statements of certain of
its subsidiaries, listed in Item 15 herein, as of December 31, 2002 and 2001,
and for each of the three years in the period ended December 31, 2002, and have
issued our reports thereon dated February 21, 2003; such financial statements
and reports are included in the 2002 Annual Reports and are incorporated herein
by reference. Our audits also included the financial statement schedules of
American Electric Power Company, Inc. and subsidiaries and of certain of its
subsidiaries, listed in Item 15. These financial statement schedules are the
responsibility of the respective company's management. Our responsibility is to
express an opinion based on our audits. In our opinion, such financial statement
schedules, when considered in relation to the corresponding basic financial
statements taken as a whole, present fairly in all material respects the
information set forth therein.

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003

                                       S-2
<PAGE>

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........   $69,416       $ 97,772       $11,766         $59,723        $119,231
                                             =======       ========       =======         =======        ========
   Year Ended December 31, 2001(c)........   $31,905       $109,635       $20,763         $92,887        $ 69,416
                                             =======       ========       =======         =======        ========
   Year Ended December 31, 2000(c)........   $27,091       $ 51,457       $11,729         $58,372        $ 31,905
                                             =======       ========       =======         =======        ========
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

 (c) 2001 and 2000 amounts have been adjusted to reflect the treatment of
     SEEBOARD and CitiPower as discontinued operations in AEP's Consolidated
     Statements of Operations.

                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $  186        $  162        $    1          $    3          $  346
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $1,675        $  186        $   --          $1,675          $  186
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $   --        $1,675        $   --          $   --          $1,675
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                            AEP TEXAS NORTH COMPANY
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $  196        $4,846        $   17          $   18          $5,041
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $  288        $   13        $   35          $  140          $  196
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $  186        $1,499        $   46          $1,443          $  288
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                                       S-3
<PAGE>

                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $1,877        $3,937        $12,367         $4,742         $13,439
                                              ======        ======        =======         ======         =======
   Year Ended December 31, 2001...........    $2,588        $2,644        $ 1,017         $4,372         $ 1,877
                                              ======        ======        =======         ======         =======
   Year Ended December 31, 2000...........    $2,609        $6,592        $ 1,526         $8,139         $ 2,588
                                              ======        ======        =======         ======         =======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $  745        $ (100)       $   --          $   11          $  634
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $  659        $  331        $   --          $  245          $  745
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $3,045        $2,082        $1,405          $5,873          $  659
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $  741        $ (161)       $   --          $    2          $  578
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $  759        $   65        $    3          $   86          $  741
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $1,848        $ (235)       $  907          $1,761          $  759
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                                       S-4
<PAGE>

                             KENTUCKY POWER COMPANY
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $  264        $  (68)       $   --          $    4          $  192
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $  282        $   --        $  (24)         $   (6)         $  264
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $  637        $  187        $    9          $  551          $  282
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                               OHIO POWER COMPANY
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $1,379        $ (457)       $   --          $   13          $  909
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $1,054        $  554        $   --          $  229          $1,379
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $2,223        $  472        $  778          $2,419          $1,054
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(a)    DEDUCTIONS(b)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $   44        $    7        $   33          $   --          $   84
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2001...........    $  467        $   44        $   --          $  467          $   44
                                              ======        ======        ======          ======          ======
   Year Ended December 31, 2000...........    $   --        $  467        $   --          $   --          $  467
                                              ======        ======        ======          ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                                       S-5
<PAGE>

              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
         SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

<Table>
<Caption>
- -------------------------------------------------------------------------------------------------------------------
                 COLUMN A                    COLUMN B             COLUMN C               COLUMN D        COLUMN E
- -------------------------------------------------------------------------------------------------------------------
                                                                  ADDITIONS
                                                          -------------------------
                                            BALANCE AT    CHARGED TO    CHARGED TO                      BALANCE AT
                                            BEGINNING     COSTS AND        OTHER                          END OF
               DESCRIPTION                  OF PERIOD      EXPENSES     ACCOUNTS(A)    DEDUCTIONS(B)      PERIOD
- -------------------------------------------------------------------------------------------------------------------
                                                                        (IN THOUSANDS)
<S>                                         <C>           <C>           <C>            <C>             <C>
 DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
   Year Ended December 31, 2002...........    $   89        $2,036        $     4         $    1          $2,128
                                              ======        ======        =======         ======          ======
   Year Ended December 31, 2001...........    $  911        $   89        $    --         $  911          $   89
                                              ======        ======        =======         ======          ======
   Year Ended December 31, 2000...........    $4,428        $  911        $(4,428)        $   --          $  911
                                              ======        ======        =======         ======          ======
</Table>

- ---------------

 (a) Recoveries on accounts previously written off.

 (b) Uncollectible accounts written off.

                                       S-6
<PAGE>

                                 EXHIBIT INDEX

     Certain of the following exhibits, designated with an asterisk (*), are
filed herewith. The exhibits not so designated have heretofore been filed with
the Commission and, pursuant to 17 C.F.R. 229.10(d) and 240.12b-32, are
incorporated herein by reference to the documents indicated in brackets
following the descriptions of such exhibits. Exhibits, designated with a dagger
(+), are management contracts or compensatory plans or arrangements required to
be filed as an Exhibit to this Form pursuant to Item 14(c) of this report.

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>

 AEGCO
     3(a)          --   Copy of Articles of Incorporation of AEGCo [Registration
                        Statement on Form 10 for the Common Shares of AEGCo, File
                        No. 0-18135, Exhibit 3(a)].
     3(b)          --   Copy of the Code of Regulations of AEGCo (amended as of June
                        15, 2000) [Annual Report on Form 10-K of AEGCo for the
                        fiscal year ended December 31, 2000, File No. 0-18135,
                        Exhibit 3(b)].
    10(a)          --   Copy of Capital Funds Agreement dated as of December 30,
                        1988 between AEGCo and AEP [Registration Statement No.
                        33-32752, Exhibit 28(a)].
    10(b)(1)       --   Copy of Unit Power Agreement dated as of March 31, 1982
                        between AEGCo and I&M, as amended [Registration Statement
                        No. 33-32752, Exhibits 28(b)(1)(A) and 28(b)(1)(B)].
    10(b)(2)       --   Copy of Unit Power Agreement, dated as of August 1, 1984,
                        among AEGCo, I&M and KPCo [Registration Statement No.
                        33-32752, Exhibit 28(b)(2)].
    10(c)          --   Copy of Lease Agreements, dated as of December 1, 1989,
                        between AEGCo and Wilmington Trust Company, as amended
                        [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
                        28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
                        28(c)(6)(C); Annual Report on Form 10-K of AEGCo for the
                        fiscal year ended December 31, 1993, File No. 0-18135,
                        Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B), 10(c)(4)(B),
                        10(c)(5)(B) and 10(c)(6)(B)].
   *13             --   Copy of those portions of the AEGCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

 AEP++
     3(a)          --   Copy of Restated Certificate of Incorporation of AEP, dated
                        October 29, 1997 [Quarterly Report on Form 10-Q of AEP for
                        the quarter ended September 30, 1997, File No. 1-3525,
                        Exhibit 3(a)].
     3(b)          --   Copy of Certificate of Amendment of the Restated Certificate
                        of Incorporation of AEP, dated January 13, 1999 [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1998, File No. 1-3525, Exhibit 3(b)].
     3(c)          --   Composite copy of the Restated Certificate of Incorporation
                        of AEP, as amended [Annual Report on Form 10-K of AEP for
                        the fiscal year ended December 31, 1998, File No. 1-3525,
                        Exhibit 3(c)].
     3(d)          --   Copy of By-Laws of AEP, as amended through January 28, 1998
                        [Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1997, File No. 1-3525, Exhibit 3(b)].
     4(a)          --   Indenture (for unsecured debt securities), dated as of May
                        1, 2001, between AEP and The Bank of New York, as Trustee
                        [Registration Statement No. 333-86050, Exhibits 4(a), 4(b)
                        and 4(c)].
    *4(b)          --   Third Supplemental Indenture, dated as of June 11, 2002,
                        between AEP and The Bank of New York, as Trustee, for 5.75%
                        Senior Notes, Series C, due August 16, 2007.
</Table>

                                       E-1
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
    *4(c)          --   Forward Purchase Contract Agreement, dated as of June 11,
                        2002, between AEP and The Bank of New York, as Forward
                        Purchase Contract Agent.
    10(a)          --   Interconnection Agreement, dated July 6, 1951, among APCo,
                        CSPCo, KPCo, OPCo and I&M and with the Service Corporation,
                        as amended [Registration Statement No. 2-52910, Exhibit
                        5(a); Registration Statement No. 2-61009, Exhibit 5(b); and
                        Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
   *10(b)          --   Restated and Amended Operating Agreement, dated as of
                        January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
    10(c)          --   Transmission Agreement, dated April 1, 1984, among APCo,
                        CSPCo, I&M, KPCo, OPCo and with the Service Corporation as
                        agent, as amended [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1985, File No. 1-3525,
                        Exhibit 10(b); and Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1988, File No. 1-3525,
                        Exhibit 10(b)(2)].
   *10(d)          --   Transmission Coordination Agreement, dated October 29, 1998,
                        among PSO, TCC, TNC, SWEPCo and AEPSC.
    10(e)          --   Lease Agreements, dated as of December 1, 1989, between
                        AEGCo or I&M and Wilmington Trust Company, as amended
                        [Registration Statement No. 33-32752, Exhibits 28(c)(1)(C),
                        28(c)(2)(C), 28(c)(3)(C), 28(c)(4)(C), 28(c)(5)(C) and
                        28(c)(6)(C); Registration Statement No. 33-32753, Exhibits
                        28(a)(1)(C), 28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C),
                        28(a)(5)(C) and 28(a)(6)(C); and Annual Report on Form 10-K
                        of AEGCo for the fiscal year ended December 31, 1993, File
                        No. 0-18135, Exhibits 10(c)(1)(B), 10(c)(2)(B), 10(c)(3)(B),
                        10(c)(4)(B), 10(c)(5)(B) and 10(c)(6)(B); Annual Report on
                        Form 10-K of I&M for the fiscal year ended December 31,
                        1993, File No. 1-3570, Exhibits 10(e)(1)(B), 10(e)(2)(B),
                        10(e)(3)(B), 10(e)(4)(B), 10(e)(5)(B) and 10(e)(6)(B)].
    10(f)          --   Lease Agreement dated January 20, 1995 between OPCo and JMG
                        Funding, Limited Partnership, and amendment thereto
                        (confidential treatment requested) [Annual Report on Form
                        10-K of OPCo for the fiscal year ended December 31, 1994,
                        File No. 1-6543, Exhibit 10(l)(2)].
    10(g)          --   Modification No. 1 to the AEP System Interim Allowance
                        Agreement, dated July 28, 1994, among APCo, CSPCo, I&M,
                        KPCo, OPCo and the Service Corporation [Annual Report on
                        Form 10-K of AEP for the fiscal year ended December 31,
                        1996, File No. 1-3525, Exhibit 10(l)].
    10(h)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        By and Among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(h)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].
   +10(i)(1)       --   AEP Deferred Compensation Agreement for certain executive
                        officers [Annual Report on Form 10-K of AEP for the fiscal
                        year ended December 31, 1985, File No. 1-3525, Exhibit
                        10(e)].
   +10(i)(2)       --   Amendment to AEP Deferred Compensation Agreement for certain
                        executive officers [Annual Report on Form 10-K of AEP for
                        the fiscal year ended December 31, 1986, File No. 1-3525,
                        Exhibit 10(d)(2)].
   +10(j)          --   AEP Accident Coverage Insurance Plan for directors [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1985, File No. 1-3525, Exhibit 10(g)].
   +10(k)(1)       --   AEP Deferred Compensation and Stock Plan for Non-Employee
                        Directors, as amended June 1, 2000 [Annual Report on Form
                        10-K of AEP for the fiscal year ended December 31, 2000,
                        File No. 1-3525, Exhibit 10(i)(1)].
</Table>

                                       E-2
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
   +10(k)(2)       --   AEP Stock Unit Accumulation Plan for Non-Employee Directors,
                        as amended January 1, 2002[Annual Report on Form 10-K of AEP
                        for the fiscal year ended December 31, 2001, File No.
                        1-3525, Exhibit 10(i)(2)].
   +10(l)(1)(A)    --   AEP System Excess Benefit Plan, Amended and Restated as of
                        January 1, 2001 [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 2000, File No. 1-3525,
                        Exhibit 10(j)(1)(A)].
   +10(l)(1)(B)    --   Guaranty by AEP of the Service Corporation Excess Benefits
                        Plan [Annual Report on Form 10-K of AEP for the fiscal year
                        ended December 31, 1990, File No. 1-3525, Exhibit
                        10(h)(1)(B)].
  *+10(l)(1)(C)    --   First Amendment to AEP System Excess Benefit Plan, dated as
                        of March 5, 2003.
   +10(l)(2)       --   AEP System Supplemental Retirement Savings Plan, Amended and
                        Restated as of June 1, 2001 (Non-Qualified) [Registration
                        Statement No. 333-66048, Exhibit 4].
   +10(l)(3)       --   Service Corporation Umbrella Trust for Executives [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1993, File No. 1-3525, Exhibit 10(g)(3)].
   +10(m)(1)       --   Employment Agreement between E. Linn Draper, Jr. and AEP and
                        the Service Corporation [Annual Report on Form 10-K of AEGCo
                        for the fiscal year ended December 31, 1991, File No.
                        0-18135, Exhibit 10(g)(3)].
   +10(m)(2)       --   Memorandum of agreement between Susan Tomasky and the
                        Service Corporation dated January 3, 2001 [Annual Report on
                        Form 10-K of AEP for the fiscal year ended December 31,
                        2000, File No. 1-3525, Exhibit 10(s)].
  *+10(m)(3)(A)    --   Letter Agreement dated June 23, 2000 between AEPSC and Holly
                        K. Koeppel.
  *+10(m)(3)(B)    --   Letter Agreement dated April 19, 2001 between AEPR and Holly
                        K. Koeppel.
  *+10(m)(4)       --   Employment Agreement dated July 29, 1998 between AEPSC and
                        Robert P. Powers.
   +10(n)          --   AEP System Senior Officer Annual Incentive Compensation Plan
                        [Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
   +10(o)(1)       --   AEP System Survivor Benefit Plan, effective January 27, 1998
                        [Quarterly Report on Form 10-Q of AEP for the quarter ended
                        September 30, 1998, File No. 1-3525, Exhibit 10].
  *+10(o)(2)       --   First Amendment to AEP System Survivor Benefit Plan, as
                        amended and restated effective January 31, 2000.
   +10(p)          --   AEP Senior Executive Severance Plan for Merger with Central
                        and South West Corporation, effective March 1, 1999 [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1998, File No. 1-3525, Exhibit 10(o)].
  *+10(q)(1)       --   AEP System Incentive Compensation Deferral Plan dated
                        January 1, 2001.
  *+10(q)(2)       --   First Amendment to AEP System Incentive Compensation
                        Deferral Plan dated December 6, 2002.
  *+10(r)          --   AEP System Nuclear Performance Long Term Incentive
                        Compensation Plan dated August 1, 1998.
  *+10(s)          --   Nuclear Key Contributor Retention Plan dated May 1, 2000.
   +10(t)          --   AEP Change In Control Agreement [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 2001, File No.
                        1-3525, Exhibit 10(o)].
   +10(u)          --   AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
                        AEP, March 10, 2000].
   +10(v)(1)       --   Central and South West System Special Executive Retirement
                        Plan as amended and restated effective July 1, 1997 [Annual
                        Report on Form 10-K of CSW for the fiscal year ended
                        December 31, 1998, File No. 1-1443, Exhibit 18].
   +10(v)(2)       --   Certified CSW Board Resolution of April 18, 1991 [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
   +10(v)(3)       --   CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                        March 13, 1992].
</Table>

                                       E-3
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
   +10(v)(4)       --   Central and South West Corporation Executive Deferred
                        Savings Plan as amended and restated effective as of January
                        1, 1997 [Annual Report on Form 10-K of CSW for the fiscal
                        year ended December 31, 1998, File No. 1-1443, Exhibit 24].
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the AEP 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
   *21             --   List of subsidiaries of AEP.
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

APCO++
     3(a)          --   Copy of Restated Articles of Incorporation of APCo, and
                        amendments thereto to November 4, 1993 [Registration
                        Statement No. 33-50163, Exhibit 4(a); Registration Statement
                        No. 33-53805, Exhibits 4(b) and 4(c)].
     3(b)          --   Copy of Articles of Amendment to the Restated Articles of
                        Incorporation of APCo, dated June 6, 1994 [Annual Report on
                        Form 10-K of APCo for the fiscal year ended December 31,
                        1994, File No. 1-3457, Exhibit 3(b)].
     3(c)          --   Copy of Articles of Amendment to the Restated Articles of
                        Incorporation of APCo, dated March 6, 1997 [Annual Report on
                        Form 10-K of APCo for the fiscal year ended December 31,
                        1996, File No. 1-3457, Exhibit 3(c)].
     3(d)          --   Composite copy of the Restated Articles of Incorporation of
                        APCo (amended as of March 7, 1997) [Annual Report on Form
                        10-K of APCo for the fiscal year ended December 31, 1996,
                        File No. 1-3457, Exhibit 3(d)].
     3(e)          --   Copy of By-Laws of APCo (amended as of October 24, 2001)
                        [Annual Report on Form 10-K of APCo for the fiscal year
                        ended December 31, 2001, File No. 1-3457, Exhibit 3(e)].
     4(a)          --   Copy of Mortgage and Deed of Trust, dated as of December 1,
                        1940, between APCo and Bankers Trust Company and R. Gregory
                        Page, as Trustees, as amended and supplemented [Registration
                        Statement No. 2-7289, Exhibit 7(b); Registration Statement
                        No. 2-19884, Exhibit 2(1); Registration Statement No.
                        2-24453, Exhibit 2(n); Registration Statement No. 2-60015,
                        Exhibits 2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), 2(b)(6),
                        2(b)(7), 2(b)(8), 2(b)(9), 2(b)(10), 2(b)(12), 2(b)(14),
                        2(b)(15), 2(b)(16), 2(b)(17), 2(b)(18), 2(b)(19), 2(b)(20),
                        2(b)(21), 2(b)(22), 2(b)(23), 2(b)(24), 2(b)(25), 2(b)(26),
                        2(b)(27) and 2(b)(28); Registration Statement No. 2-64102,
                        Exhibit 2(b)(29); Registration Statement No. 2-66457,
                        Exhibits (2)(b)(30) and 2(b)(31); Registration Statement No.
                        2-69217, Exhibit 2(b)(32); Registration Statement No.
                        2-86237, Exhibit 4(b); Registration Statement No. 33-11723,
                        Exhibit 4(b); Registration Statement No. 33-17003, Exhibit
                        4(a)(ii), Registration Statement No. 33-30964, Exhibit 4(b);
                        Registration Statement No. 33-40720, Exhibit 4(b);
                        Registration Statement No. 33-45219, Exhibit 4(b);
                        Registration Statement No. 33-46128, Exhibits 4(b) and 4(c);
                        Registration Statement No. 33-53410, Exhibit 4(b);
                        Registration Statement No. 33-59834, Exhibit 4(b);
                        Registration Statement No. 33-50229, Exhibits 4(b) and 4(c);
                        Registration Statement No. 33-58431, Exhibits 4(b), 4(c),
                        4(d) and 4(e); Registration Statement No. 333-01049,
                        Exhibits 4(b) and 4(c); Registration Statement No.
                        333-20305, Exhibits 4(b) and 4(c); Annual Report on Form
                        10-K of APCo for the fiscal year ended December 31, 1996,
                        File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1998, File No.
                        1-3457, Exhibit 4(b)].
</Table>

                                       E-4
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
     4(b)          --   Indenture (for unsecured debt securities), dated as of
                        January 1, 1998, between APCo and The Bank of New York, As
                        Trustee [Registration Statement No. 333-45927, Exhibit 4(a);
                        Registration Statement No. 333-49071, Exhibit 4(b);
                        Registration Statement No. 333-84061, Exhibits 4(b) and
                        4(c); Annual Report on Form 10-K of APCo for the fiscal year
                        ended December 31, 1999, File No. 1-3457, Exhibit 4(c);
                        Registration Statement No. 333-81402, Exhibits 4(b), 4(c)
                        and 4(d); Registration Statement No. 333-100451, Exhibit
                        4(b)].
    *4(c)          --   Copy of Company Order and Officer's Certificate, dated
                        November 6, 2002, establishing terms of 4.3148% Senior
                        Notes, Series F, due 2007.
    10(a)(1)       --   Copy of Power Agreement, dated October 15, 1952, between
                        OVEC and United States of America, acting by and through the
                        United States Atomic Energy Commission, and, subsequent to
                        January 18, 1975, the Administrator of the Energy Research
                        and Development Administration, as amended [Registration
                        Statement No. 2-60015, Exhibit 5(a); Registration Statement
                        No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No
                        2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
                        2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1989, File No.
                        1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
                        of APCo for the fiscal year ended December 31, 1992, File
                        No. 1-3457, Exhibit 10(a)(1)(B)].
    10(a)(2)       --   Copy of Inter-Company Power Agreement, dated as of July 10,
                        1953, among OVEC and the Sponsoring Companies, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(c);
                        Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and
                        Annual Report on Form 10-K of APCo for the fiscal year ended
                        December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
    10(a)(3)       --   Copy of Power Agreement, dated July 10, 1953, between OVEC
                        and Indiana-Kentucky Electric Corporation, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(e)].
    10(b)          --   Copy of Interconnection Agreement, dated July 6, 1951, among
                        APCo, CSPCo, KPCo, OPCo and I&M and with the Service
                        Corporation, as amended [Registration Statement No. 2-52910,
                        Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
                        5(b); Annual Report on Form 10-K of AEP for the fiscal year
                        ended December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
    10(c)          --   Copy of Transmission Agreement, dated April 1, 1984, among
                        APCo, CSPCo, I&M, KPCo, OPCo and with the Service
                        Corporation as agent, as amended [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 1985, File No.
                        1-3525, Exhibit 10(b); Annual Report on Form 10-K of AEP for
                        the fiscal year ended December 31, 1988, File No. 1-3525,
                        Exhibit 10(b)(2)].
    10(d)          --   Copy of Modification No. 1 to the AEP System Interim
                        Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
                        I&M, KPCo, OPCo and the Service Corporation [Annual Report
                        on Form 10-K of AEP for the fiscal year ended December 31,
                        1996, File No. 1-3525, Exhibit 10(l)].
    10(e)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        By and Among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(e)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        APCo dated December 15, 1999, File No. 1-3457, Exhibit 10].
   +10(f)(1)       --   AEP Deferred Compensation Agreement for certain executive
                        officers [Annual Report on Form 10-K of AEP for the fiscal
                        year ended December 31, 1985, File No. 1-3525, Exhibit
                        10(e)].
   +10(f)(2)       --   Amendment to AEP Deferred Compensation Agreement for certain
                        executive officers [Annual Report on Form 10-K of AEP for
                        the fiscal year ended December 31, 1986, File No. 1-3525,
                        Exhibit 10(d)(2)].
</Table>

                                       E-5
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
   +10(g)          --   AEP System Senior Officer Annual Incentive Compensation Plan
                        [Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
   +10(h)(1)(A)    --   AEP System Excess Benefit Plan, Amended and Restated as of
                        January 1, 2001 [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 2000, File No. 1-3525,
                        Exhibit 10(j)(1)(A)].
  *+10(h)(1)(B)    --   First Amendment to AEP System Excess Benefit Plan, dated as
                        of March 5, 2003.
   +10(h)(2)       --   AEP System Supplemental Retirement Savings Plan, Amended and
                        Restated as of January 1, 2001 (Non-Qualified) [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)].
   +10(h)(3)       --   Umbrella Trust for Executives [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 1993, File No.
                        1-3525, Exhibit 10(g)(3)].
   +10(i)(1)       --   Employment Agreement between E. Linn Draper, Jr. and AEP and
                        the Service Corporation [Annual Report on Form 10-K of AEGCo
                        for the fiscal year ended December 31, 1991, File No.
                        0-18135, Exhibit 10(g)(3)].
   +10(i)(2)       --   Memorandum of agreement between Susan Tomasky and the
                        Service Corporation dated January 3, 2001 [Annual Report on
                        Form 10-K of AEP for the fiscal year ended December 31,
                        2000, File No. 1-3525, Exhibit 10(s)].
  *+10(i)(3)       --   Employment Agreement dated July 29, 1998 between AEPSC and
                        Robert P. Powers.
   +10(j)(1)       --   AEP System Survivor Benefit Plan, effective January 27, 1998
                        [Quarterly Report on Form 10-Q of AEP for the quarter ended
                        September 30, 1998, File No. 1-3525, Exhibit 10].
  *+10(j)(2)       --   First Amendment to AEP System Survivor Benefit Plan, as
                        amended and restated effective January 31, 2000.
   +10(k)          --   AEP Senior Executive Severance Plan for Merger with Central
                        and South West Corporation, effective March 1, 1999[Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1998, File No. 1-3525, Exhibit 10(o)].
   +10(l)          --   AEP Change In Control Agreement [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 2001, File No.
                        1-3525, Exhibit 10(o)].
   +10(m)          --   AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
                        AEP, March 10, 2000].
   +10(n)(1)       --   Central and South West System Special Executive Retirement
                        Plan as amended and restated effective July 1, 1997 [Annual
                        Report on Form 10-K of CSW for the fiscal year ended
                        December 31, 1998, File No. 1-1443, Exhibit 18].
   +10(n)(2)       --   Certified CSW Board Resolution of April 18, 1991 [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
   +10(n)(3)       --   CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                        March 13, 1992].
  *+10(o)(1)       --   AEP System Incentive Compensation Deferral Plan dated
                        January 1, 2001.
  *+10(o)(2)       --   First Amendment to AEP System Incentive Compensation
                        Deferral Plan dated December 6, 2002.
  *+10(p)          --   AEP System Nuclear Performance Long Term Incentive
                        Compensation Plan dated August 1, 1998.
  *+10(q)          --   Nuclear Key Contributor Retention Plan dated May 1, 2000.
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the APCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of APCo [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21].
   *23             --   Consent of Deloitte & Touche LLP
</Table>

                                       E-6
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

CSPCO++
     3(a)          --   Copy of Amended Articles of Incorporation of CSPCo, as
                        amended to March 6, 1992 [Registration Statement No.
                        33-53377, Exhibit 4(a)].
     3(b)          --   Copy of Certificate of Amendment to Amended Articles of
                        Incorporation of CSPCo, dated May 19, 1994 [Annual Report on
                        Form 10-K of CSPCo for the fiscal year ended December 31,
                        1994, File No. 1-2680, Exhibit 3(b)].
     3(c)          --   Composite copy of Amended Articles of Incorporation of
                        CSPCo, as amended [Annual Report on Form 10-K of CSPCo for
                        the fiscal year ended December 31, 1994, File No. 1-2680,
                        Exhibit 3(c)].
     3(d)          --   Copy of Code of Regulations and By-Laws of CSPCo [Annual
                        Report on Form 10-K of CSPCo for the fiscal year ended
                        December 31, 1987, File No. 1-2680, Exhibit 3(d)].
     4(a)          --   Copy of Indenture of Mortgage and Deed of Trust, dated
                        September 1, 1940, between CSPCo and City Bank Farmers Trust
                        Company (now Citibank, N.A.), as trustee, as supplemented
                        and amended [Registration Statement No. 2-59411, Exhibits
                        2(B) and 2(C); Registration Statement No. 2-80535, Exhibit
                        4(b); Registration Statement No. 2-87091, Exhibit 4(b);
                        Registration Statement No. 2-93208, Exhibit 4(b);
                        Registration Statement No. 2-97652, Exhibit 4(b);
                        Registration Statement No. 33-7081, Exhibit 4(b);
                        Registration Statement No. 33-12389, Exhibit 4(b);
                        Registration Statement No. 33-19227, Exhibits 4(b), 4(e),
                        4(f), 4(g) and 4(h); Registration Statement No. 33-35651,
                        Exhibit 4(b); Registration Statement No. 33-46859, Exhibits
                        4(b) and 4(c); Registration Statement No. 33-50316, Exhibits
                        4(b) and 4(c); Registration Statement No. 33-60336, Exhibits
                        4(b), 4(c) and 4(d); Registration Statement No. 33-50447,
                        Exhibits 4(b) and 4(c); Annual Report on Form 10-K of CSPCo
                        for the fiscal year ended December 31, 1993, File No.
                        1-2680, Exhibit 4(b)].
     4(b)          --   Copy of Indenture (for unsecured debt securities), dated as
                        of September 1, 1997, between CSPCo and Bankers Trust
                        Company, as Trustee [Registration Statement No. 333-54025,
                        Exhibits 4(a), 4(b), 4(c) and 4(d); Annual Report on Form
                        10-K of CSPCo for the fiscal year ended December 31, 1998,
                        File No. 1-2680, Exhibits 4(c) and 4(d)].
    10(a)(1)       --   Copy of Power Agreement, dated October 15, 1952, between
                        OVEC and United States of America, acting by and through the
                        United States Atomic Energy Commission, and, subsequent to
                        January 18, 1975, the Administrator of the Energy Research
                        and Development Administration, as amended [Registration
                        Statement No. 2-60015, Exhibit 5(a); Registration Statement
                        No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
                        2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
                        2-67728, Exhibit 5(a)(1)(B); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1989, File No.
                        1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
                        of APCo for the fiscal year ended December 31, 1992, File
                        No. 1-3457, Exhibit 10(a)(1)(B)].
    10(a)(2)       --   Copy of Inter-Company Power Agreement, dated July 10, 1953,
                        among OVEC and the Sponsoring Companies, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(c);
                        Registration Statement No. 2-67728, Exhibit 5(a)(3)(B); and
                        Annual Report on Form 10-K of APCo for the fiscal year ended
                        December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
    10(a)(3)       --   Copy of Power Agreement, dated July 10, 1953, between OVEC
                        and Indiana-Kentucky Electric Corporation, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(e)].
</Table>

                                       E-7
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
    10(b)          --   Copy of Interconnection Agreement, dated July 6, 1951, among
                        APCo, CSPCo, KPCo, OPCo and I&M and the Service Corporation,
                        as amended [Registration Statement No. 2-52910, Exhibit
                        5(a); Registration Statement No. 2-61009, Exhibit 5(b); and
                        Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1990, File No. 1-3525, Exhibit 10(a)(3)].
    10(c)          --   Copy of Transmission Agreement, dated April 1, 1984, among
                        APCo, CSPCo, I&M, KPCo, OPCo, and with the Service
                        Corporation as agent, as amended [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 1985, File No.
                        1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
                        for the fiscal year ended December 31, 1988, File No.
                        1-3525, Exhibit 10(b)(2)].
    10(d)          --   Copy of Modification No. 1 to the AEP System Interim
                        Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
                        I&M, KPCo, OPCo and the Service Corporation [Annual Report
                        on Form 10-K of AEP for the fiscal year ended December 31,
                        1996, File No. 1-3525, Exhibit 10(l)].
    10(e)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        By and Among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(e)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10].
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the CSPCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of CSPCo [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21]
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

 I&M++
     3(a)          --   Copy of the Amended Articles of Acceptance of I&M and
                        amendments thereto [Annual Report on Form 10-K of I&M for
                        fiscal year ended December 31, 1993, File No. 1-3570,
                        Exhibit 3(a)].
     3(b)          --   Copy of Articles of Amendment to the Amended Articles of
                        Acceptance of I&M, dated March 6, 1997 [Annual Report on
                        Form 10-K of I&M for fiscal year ended December 31, 1996,
                        File No. 1-3570, Exhibit 3(b)].
     3(c)          --   Composite Copy of the Amended Articles of Acceptance of I&M
                        (amended as of March 7, 1997) [Annual Report on Form 10-K of
                        I&M for the fiscal year ended December 31, 1996, File No.
                        1-3570, Exhibit 3(c)].
     3(d)          --   Copy of the By-Laws of I&M (amended as of November 28, 2001)
                        [Annual Report on Form 10-K of I&M for the fiscal year ended
                        December 31, 2001, File No. 1-3570, Exhibit 3(d)].
</Table>

                                       E-8
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
     4(a)          --   Copy of Mortgage and Deed of Trust, dated as of June 1,
                        1939, between I&M and Irving Trust Company (now The Bank of
                        New York) and various individuals, as Trustees, as amended
                        and supplemented [Registration Statement No. 2-7597, Exhibit
                        7(a); Registration Statement No. 2-60665, Exhibits 2(c)(2),
                        2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
                        2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
                        2(c)(15), (2)(c)(16), and 2(c)(17); Registration Statement
                        No. 2-63234, Exhibit 2(b)(18); Registration Statement No.
                        2-65389, Exhibit 2(a)(19); Registration Statement No.
                        2-67728, Exhibit 2(b)(20); Registration Statement No.
                        2-85016, Exhibit 4(b); Registration Statement No. 33-5728,
                        Exhibit 4(c); Registration Statement No. 33-9280, Exhibit
                        4(b); Registration Statement No. 33-11230, Exhibit 4(b);
                        Registration Statement No. 33-19620, Exhibits 4(a)(ii),
                        4(a)(iii), 4(a)(iv) and 4(a)(v); Registration Statement No.
                        33-46851, Exhibits 4(b)(i), 4(b)(ii) and 4(b)(iii);
                        Registration Statement No. 33-54480, Exhibits 4(b)(I) and
                        4(b)(ii); Registration Statement No. 33-60886, Exhibit
                        4(b)(I); Registration Statement No. 33-50521, Exhibits
                        4(b)(I), 4(b)(ii) and 4(b)(iii); Annual Report on Form 10-K
                        of I&M for the fiscal year ended December 31, 1993, File No.
                        1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for
                        the fiscal year ended December 31, 1994, File No. 1-3570,
                        Exhibit 4(b); Annual Report on Form 10-K of I&M for the
                        fiscal year ended December 31, 1996, File No. 1-3570,
                        Exhibit 4(b)].
     4(b)          --   Copy of Indenture (for unsecured debt securities), dated as
                        of October 1, 1998, between I&M and The Bank of New York, as
                        Trustee [Registration Statement No. 333-88523, Exhibits
                        4(a), 4(b) and 4(c); Registration Statement No. 333-58656,
                        Exhibits 4(b) and 4(c); Annual Report of Form 10-K of I&M
                        for fiscal year ended December 31, 2001, File No. 1-3570,
                        Exhibit 4(c)].
    *4(c)          --   Copy of Company Order and Officer's Certificate, dated
                        November 22, 2002 establishing certain terms of the 6%
                        Senior Notes, Series D, due 2032.
     4(d)          --   Copy of Company Order and Officers' Certificate, dated
                        December 12, 2001, establishing certain terms of the 6.125%
                        Notes, Series C, due 2006. [Annual Report on Form 10-K of
                        I&M for the fiscal year ended December 31, 2001, File No.
                        1-3570, Exhibit 4(c)].
    10(a)(1)       --   Copy of Power Agreement, dated October 15, 1952, between
                        OVEC and United States of America, acting by and through the
                        United States Atomic Energy Commission, and, subsequent to
                        January 18, 1975, the Administrator of the Energy Research
                        and Development Administration, as amended [Registration
                        Statement No. 2-60015, Exhibit 5(a); Registration Statement
                        No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
                        2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
                        2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1989, File No.
                        1-3457, Exhibit 10(a)(1)(F); and Annual Report on Form 10-K
                        of APCo for the fiscal year ended December 31, 1992, File
                        No. 1-3457, Exhibit 10(a)(1)(B)].
    10(a)(2)       --   Copy of Inter-Company Power Agreement, dated as of July 10,
                        1953, among OVEC and the Sponsoring Companies, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(c);
                        Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
                        Annual Report on Form 10-K of APCo for the fiscal year ended
                        December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
    10(a)(3)       --   Copy of Power Agreement, dated July 10, 1953, between OVEC
                        and Indiana-Kentucky Electric Corporation, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(e)].
    10(a)(4)       --   Copy of Inter-Company Power Agreement, dated as of July 10,
                        1953, among OVEC and the Sponsoring Companies, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(c);
                        Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
                        Annual Report on Form 10-K of APCo for the fiscal year ended
                        December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
    10(b)          --   Copy of Interconnection Agreement, dated July 6, 1951, among
                        APCo, CSPCo, KPCo, I&M, and OPCo and with the Service
                        Corporation, as amended [Registration Statement No. 2-52910,
                        Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
                        5(b); and Annual Report on Form 10-K of AEP for the fiscal
                        year ended December 31, 1990, File No. 1-3525, Exhibit
                        10(a)(3)].
</Table>

                                       E-9
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
    10(c)          --   Copy of Transmission Agreement, dated April 1, 1984, among
                        APCo, CSPCo, I&M, KPCo, OPCo and with the Service
                        Corporation as agent, as amended [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 1985, File No.
                        1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
                        for the fiscal year ended December 31, 1988, File No.
                        1-3525, Exhibit 10(b)(2)].
    10(d)          --   Copy of Modification No. 1 to the AEP System Interim
                        Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
                        I&M, KPCo, OPCo and the Service Corporation [Annual Report
                        on Form 10-K of AEP for the fiscal year ended December 1,
                        1996, File No. 1-3525, Exhibit 10(l)].
    10(e)          --   Copy of Nuclear Material Lease Agreement, dated as of
                        December 1, 1990, between I&M and DCC Fuel Corporation
                        [Annual Report on Form 10-K of I&M for the fiscal year ended
                        December 31, 1993, File No. 1-3570, Exhibit 10(d)].
    10(f)          --   Copy of Lease Agreements, dated as of December 1, 1989,
                        between I&M and Wilmington Trust Company, as amended
                        [Registration Statement No. 33-32753, Exhibits 28(a)(1)(C),
                        28(a)(2)(C), 28(a)(3)(C), 28(a)(4)(C), 28(a)(5)(C) and
                        28(a)(6)(C); Annual Report on Form 10-K of I&M for the
                        fiscal year ended December 31, 1993, File No. 1-3570,
                        Exhibits 10(e)(1)(B), 10(e)(2)(B), 10(e)(3)(B), 10(e)(4)(B),
                        10(e)(5)(B) and 10(e)(6)(B)].
    10(g)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        By and Among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(g)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        I&M dated December 15, 1999, File No. 1-3570, Exhibit 10].
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the I&M 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of I&M [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21].
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

KPCO++
     3(a)          --   Copy of Restated Articles of Incorporation of KPCo [Annual
                        Report on Form 10-K of KPCo for the fiscal year ended
                        December 31, 1991, File No. 1-6858, Exhibit 3(a)].
     3(b)          --   Copy of By-Laws of KPCo (amended as of June 15, 2000)
                        [Annual Report on Form 10-K of KPCo for the fiscal year
                        ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].
     4(a)          --   Copy of Mortgage and Deed of Trust, dated May 1, 1949,
                        between KPCo and Bankers Trust Company (now Deutsche Bank
                        Trust Company Americas, as supplemented and amended
                        [Registration Statement No. 2-65820, Exhibits 2(b)(1),
                        2(b)(2), 2(b)(3), 2(b)(4), 2(b)(5), and 2(b)(6);
                        Registration Statement No. 33-39394, Exhibits 4(b) and 4(c);
                        Registration Statement No. 33-53226, Exhibits 4(b) and 4(c);
                        Registration Statement No. 33-61808, Exhibits 4(b) and 4(c),
                        Registration Statement No. 33-53007, Exhibits 4(b), 4(c) and
                        4(d)].
     4(b)          --   Copy of Indenture (for unsecured debt securities), dated as
                        of September 1, 1997, between KPCo and Bankers Trust
                        Company, as Trustee [Registration Statement No. 333-75785,
                        Exhibits 4(a), 4(b), 4(c) and 4(d); Registration Statement
                        No. 333-87216, Exhibits 4E) and 4(f).
    *4(c)          --   Copy of Company Order and Officer's Certificate, dated June
                        28, 2002 establishing certain terms of the 5.50% Senior
                        Notes, Series A, due 2007.
</Table>

                                       E-10
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
    *4(d)          --   Copy of Company Order and Officer's Certificate, dated
                        November 6, 2002 establishing certain terms of the 4.3148%
                        Senior Notes, Series B, due 2007.
    *4(e)          --   Copy of Company Order and Officer's Certificate, dated
                        December 12, 2002 establishing certain terms of the 4.368%
                        Senior Notes, Series C, due 2007.
    10(a)          --   Copy of Interconnection Agreement, dated July 6, 1951, among
                        APCo, CSPCo, KPCo, I&M and OPCo and with the Service
                        Corporation, as amended [Registration Statement No. 2-52910,
                        Exhibit 5(a);Registration Statement No. 2-61009, Exhibit
                        5(b); and Annual Report on Form 10-K of AEP for the fiscal
                        year ended December 31, 1990, File No. 1-3525, Exhibit
                        10(a)(3)].
    10(b)          --   Copy of Transmission Agreement, dated April 1, 1984, among
                        APCo, CSPCo, I&M, KPCo, OPCo and with the Service
                        Corporation as agent, as amended [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 1985, File No.
                        1-3525, Exhibit 10(b); and Annual Report on Form 10-K of AEP
                        for the fiscal year ended December 31, 1988, File No.
                        1-3525, Exhibit 10(b)(2)].
    10(c)          --   Copy of Modification No. 1 to the AEP System Interim
                        Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
                        I&M, KPCo, OPCo and the Service Corporation [Annual Report
                        on Form 10-K of AEP for the fiscal year ended December 31,
                        1996, File No. 1-3525, Exhibit 10(l)].
    10(d)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        By and Among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(d)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        KPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the KPCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
   *23             --   Consent of Deloitte & Touche LLP
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

OPCO++
     3(a)          --   Copy of Amended Articles of Incorporation of OPCo, and
                        amendments thereto to December 31, 1993 [Registration
                        Statement No. 33-50139, Exhibit 4(a); Annual Report on Form
                        10-K of OPCo for the fiscal year ended December 31, 1993,
                        File No. 1-6543, Exhibit 3(b)].
     3(b)          --   Copy of Certificate of Amendment to Amended Articles of
                        Incorporation of OPCo, dated May 3, 1994 [Annual Report on
                        Form 10-K of OPCo for the fiscal year ended December 31,
                        1994, File No. 1-6543, Exhibit 3(b)].
     3(c)          --   Copy of Certificate of Amendment to Amended Articles of
                        Incorporation of OPCo, dated March 6, 1997 [Annual Report on
                        Form 10-K of OPCo for the fiscal year ended December 31,
                        1996, File No. 1-6543, Exhibit 3(c)].
     3(d)          --   Copy of Certificate of Amendment to Amended Articles of
                        Incorporation of OPCo, dated June 3, 2002 [Quarterly Report
                        on Form 10-Q of OPCo for the quarter ended June 30, 2002,
                        File No. 1-6543, Exhibit 3(d)].
     3(e)          --   Composite copy of the Amended Articles of Incorporation of
                        OPCo (amended as of June 3, 2002) [[Quarterly Report on Form
                        10-Q of OPCo for the quarter ended June 30, 2002, File No.
                        1-6543, Exhibit 3(e)].
</Table>

                                       E-11
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
     3(f)          --   Copy of Code of Regulations of OPCo [Annual Report on Form
                        10-K of OPCo for the fiscal year ended December 31, 1990,
                        File No. 1-6543, Exhibit 3(d)].
     4(a)          --   Copy of Mortgage and Deed of Trust, dated as of October 1,
                        1938, between OPCo and Manufacturers Hanover Trust Company
                        (now Chemical Bank), as Trustee, as amended and supplemented
                        [Registration Statement No. 2-3828, Exhibit B-4;
                        Registration Statement No. 2-60721, Exhibits 2(c)(2),
                        2(c)(3), 2(c)(4), 2(c)(5), 2(c)(6), 2(c)(7), 2(c)(8),
                        2(c)(9), 2(c)(10), 2(c)(11), 2(c)(12), 2(c)(13), 2(c)(14),
                        2(c)(15), 2(c)(16), 2(c)(17), 2(c)(18), 2(c)(19), 2(c)(20),
                        2(c)(21), 2(c)(22), 2(c)(23), 2(c)(24), 2(c)(25), 2(c)(26),
                        2(c)(27), 2(c)(28), 2(c)(29), 2(c)(30), and 2(c)(31);
                        Registration Statement No. 2-83591, Exhibit 4(b);
                        Registration Statement No. 33-21208, Exhibits 4(a)(ii),
                        4(a)(iii) and 4(a)(iv); Registration Statement No. 33-31069,
                        Exhibit 4(a)(ii); Registration Statement No. 33-44995,
                        Exhibit 4(a)(ii); Registration Statement No. 33-59006,
                        Exhibits 4(a)(ii), 4(a)(iii) and 4(a)(iv); Registration
                        Statement No. 33-50373, Exhibits 4(a)(ii), 4(a)(iii) and
                        4(a)(iv); Annual Report on Form 10-K of OPCo for the fiscal
                        year ended December 31, 1993, File No. 1-6543, Exhibit
                        4(b)].
     4(b)          --   Copy of Indenture (for unsecured debt securities), dated as
                        of September 1, 1997, between OPCo and Bankers Trust Company
                        (now Deutsche Bank Trust Company Americas), as Trustee
                        [Registration Statement No. 333-49595, Exhibits 4(a), 4(b)
                        and 4(c); Annual Report on Form 10-K of OPCo for the fiscal
                        year ended December 31, 1998, File No. 1-6543, Exhibits 4(c)
                        and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
                        year ended December 31, 1999, File No. 1-6543, Exhibits 4(c)
                        and 4(d); Annual Report on Form 10-K of OPCo for the fiscal
                        year ended December 31, 2000, File No. 1-6543, Exhibit
                        4(c)].
    10(a)(1)       --   Copy of Power Agreement, dated October 15, 1952, between
                        OVEC and United States of America, acting by and through the
                        United States Atomic Energy Commission, and, subsequent to
                        January 18, 1975, the Administrator of the Energy Research
                        and Development Administration, as amended [Registration
                        Statement No. 2-60015, Exhibit 5(a); Registration Statement
                        No. 2-63234, Exhibit 5(a)(1)(B); Registration Statement No.
                        2-66301, Exhibit 5(a)(1)(C); Registration Statement No.
                        2-67728, Exhibit 5(a)(1)(D); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1989, File No.
                        1-3457, Exhibit 10(a)(1)(F); Annual Report on Form 10-K of
                        APCo for the fiscal year ended December 31, 1992, File No.
                        1-3457, Exhibit 10(a)(1)(B)].
    10(a)(2)       --   Copy of Inter-Company Power Agreement, dated July 10, 1953,
                        among OVEC and the Sponsoring Companies, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(c);
                        Registration Statement No. 2-67728, Exhibit 5(a)(3)(B);
                        Annual Report on Form 10-K of APCo for the fiscal year ended
                        December 31, 1992, File No. 1-3457, Exhibit 10(a)(2)(B)].
    10(a)(3)       --   Copy of Power Agreement, dated July 10, 1953, between OVEC
                        and Indiana-Kentucky Electric Corporation, as amended
                        [Registration Statement No. 2-60015, Exhibit 5(e)].
    10(b)          --   Copy of Interconnection Agreement, dated July 6, 1951, among
                        APCo, CSPCo, KPCo, I&M and OPCo and with the Service
                        Corporation, as amended [Registration Statement No. 2-52910,
                        Exhibit 5(a); Registration Statement No. 2-61009, Exhibit
                        5(b); Annual Report on Form 10-K of AEP for the fiscal year
                        ended December 31, 1990, File 1-3525, Exhibit 10(a)(3)].
    10(c)          --   Copy of Transmission Agreement, dated April 1, 1984, among
                        APCo, CSPCo, I&M, KPCo, OPCo and with the Service
                        Corporation as agent [Annual Report on Form 10-K of AEP for
                        the fiscal year ended December 31, 1985, File No. 1-3525,
                        Exhibit 10(b); Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1988, File No. 1-3525,
                        Exhibit 10(b)(2)].
    10(d)          --   Copy of Modification No. 1 to the AEP System Interim
                        Allowance Agreement, dated July 28, 1994, among APCo, CSPCo,
                        I&M, KPCo, OPCo and the Service Corporation [Annual Report
                        on Form 10-K of AEP for the fiscal year ended December 31,
                        1996, File No. 1-3525, Exhibit 10(l)].
</Table>

                                       E-12
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
    10(e)          --   Copy of Amendment No. 1, dated October 1, 1973, to Station
                        Agreement dated January 1, 1968, among OPCo, Buckeye and
                        Cardinal Operating Company, and amendments thereto [Annual
                        Report on Form 10-K of OPCo for the fiscal year ended
                        December 31, 1993, File No. 1-6543, Exhibit 10(f)].
    10(f)          --   Lease Agreement dated January 20, 1995 between OPCo and JMG
                        Funding, Limited Partnership, and amendment thereto
                        (confidential treatment requested) [Annual Report on Form
                        10-K of OPCo for the fiscal year ended December 31, 1994,
                        File No. 1-6543, Exhibit 10(l)(2)].
    10(g)(1)       --   Agreement and Plan of Merger, dated as of December 21, 1997,
                        by and among American Electric Power Company, Inc., Augusta
                        Acquisition Corporation and Central and South West
                        Corporation [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 1997, File No. 1-3525,
                        Exhibit 10(f)].
    10(g)(2)       --   Amendment No. 1, dated as of December 31, 1999, to the
                        Agreement and Plan of Merger [Current Report on Form 8-K of
                        OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].
   +10(h)          --   AEP System Senior Officer Annual Incentive Compensation Plan
                        [Annual Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
   +10(i)(1)(A)    --   AEP System Excess Benefit Plan, Amended and Restated as of
                        January 1, 2001 [Annual Report on Form 10-K of AEP for the
                        fiscal year ended December 31, 2000, File No. 1-3525,
                        Exhibit 10(j)(1)(A)].
  *+10(i)(1)(B)    --   First Amendment to AEP System Excess Benefit Plan, dated as
                        of March 5, 2003.
   +10(i)(2)       --   AEP System Supplemental Retirement Savings Plan, Amended and
                        Restated as of January 1, 2001 (Non-Qualified) [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 2000, File No. 1-3525, Exhibit 10(j)(2)].
   +10(i)(3)       --   Umbrella Trust for Executives [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 1993, File No.
                        1-3525, Exhibit 10(g)(3)].
   +10(j)(1)       --   Employment Agreement between E. Linn Draper, Jr. and AEP and
                        the Service Corporation [Annual Report on Form 10-K of AEGCo
                        for the fiscal year ended December 31, 1991, File No.
                        0-18135, Exhibit 10(g)(3)].
   +10(j)(2)       --   Memorandum of agreement between Susan Tomasky and the
                        Service Corporation dated January 3, 2001 [Annual Report on
                        Form 10-K of AEP for the fiscal year ended December 31,
                        2000, File No. 1-3525, Exhibit 10(s)].
  *+10(j)(3)       --   Employment Agreement dated July 29, 1998 between AEPSC and
                        Robert P. Powers.
   +10(k)(1)       --   AEP System Survivor Benefit Plan, effective January 27, 1998
                        [Quarterly Report on Form 10-Q of AEP for the quarter ended
                        September 30, 1998, File No. 1-3525, Exhibit 10].
  *+10(k)(2)       --   First Amendment to AEP System Survivor Benefit Plan, as
                        amended and restated effective January 31, 2000.
   +10(l)          --   AEP Senior Executive Severance Plan for Merger with Central
                        and South West Corporation, effective March 1, 1999[Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 1998, File No. 1-3525, Exhibit 10(o)].
   +10(m)          --   AEP Change In Control Agreement [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 2001, File No.
                        1-3525, Exhibit 10(o)].
   +10(n)          --   AEP System 2000 Long-Term Incentive Plan [Proxy Statement of
                        AEP, March 10, 2000].
   +10(o)(1)       --   Central and South West System Special Executive Retirement
                        Plan as amended and restated effective July 1, 1997 [Annual
                        Report on Form 10-K of CSW for the fiscal year ended
                        December 31, 1998, File No. 1-1443, Exhibit 18].
   +10(o)(2)       --   Certified CSW Board Resolution of April 18, 1991 [Annual
                        Report on Form 10-K of AEP for the fiscal year ended
                        December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
   +10(o)(3)       --   CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                        March 13, 1992].
  *+10(p)(1)       --   AEP System Incentive Compensation Deferral Plan dated
                        January 1, 2001.
</Table>

                                       E-13
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
  *+10(p)(2)       --   First Amendment to AEP System Incentive Compensation
                        Deferral Plan dated December 6, 2002.
  *+10(q)          --   AEP System Nuclear Performance Long Term Incentive
                        Compensation Plan dated August 1, 1998.
  *+10(r)          --   Nuclear Key Contributor Retention Plan dated May 1, 2000.
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the OPCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of OPCo [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21].
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

 PSO++
     3(a)          --   Restated Certificate of Incorporation of PSO [Annual Report
                        on Form U5S of Central and South West Corporation for the
                        fiscal year ended December 31, 1996, File No. 1-1443,
                        Exhibit B-3.1].
     3(b)          --   By-Laws of PSO (amended as of June 28, 2000) [Annual Report
                        on Form 10-K of PSO for the fiscal year ended December 31,
                        2000, File No. 0-343, Exhibit 3(b)].
     4(a)          --   Indenture, dated July 1, 1945, between and Liberty Bank and
                        Trust Company of Tulsa, National Association, as Trustee, as
                        amended and supplemented [Registration Statement No.
                        2-60712, Exhibit 5.03; Registration Statement No. 2-64432,
                        Exhibit 2.02; Registration Statement No. 2-65871, Exhibit
                        2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234,
                        Exhibit 3; Registration Statement No. 33-48650, Exhibit
                        4(b); Registration Statement No. 33-49143, Exhibit 4(c);
                        Registration Statement No. 33-49575, Exhibit 4(b); Annual
                        Report on Form 10-K of PSO for the fiscal year ended
                        December 31, 1993, File No. 0-343, Exhibit 4(b); Current
                        Report on Form 8-K of PSO dated March 4, 1996, No. 0-343,
                        Exhibit 4.01; Current Report on Form 8-K of PSO dated March
                        4, 1996, No. 0-343, Exhibit 4.02; Current Report on Form 8-K
                        of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].
     4(b)          --   PSO-obligated, mandatorily redeemable preferred securities
                        of subsidiary trust holding solely Junior Subordinated
                        Debentures of PSO:
                        (1) Indenture, dated as of May 1, 1997, between PSO and The
                            Bank of New York, as Trustee [Quarterly Report on Form 10-Q
                            of PSO dated March 31, 1997, File No. 0-343, Exhibits
                            4.6 and 4.7].
                        (2) Amended and Restated Trust Agreement of PSO Capital I,
                            dated as of May 1, 1997, among PSO, as Depositor, The Bank
                            of New York, as Property Trustee, The Bank of New York
                            (Delaware), as Delaware Trustee, and the Administrative
                            Trustee [Quarterly Report on Form 10-Q of PSO dated
                            March 31, 1997, File No. 0-343, Exhibit 4.8].
</Table>

                                       E-14
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
                        (3) Guarantee Agreement, dated as of May 1, 1997, delivered
                            by PSO for the benefit of the holders of PSO Capital I's
                            Preferred Securities [Quarterly Report on Form 10-Q of
                            PSO dated March 31, 1997, File No. 0-343, Exhibits 4.9].
                        (4) Agreement as to Expenses and Liabilities, dated as of
                            May 1, 1997, between PSO and PSO Capital I [Quarterly Report
                            on Form 10-Q of PSO dated March 31, 1997, File No.
                            0-343, Exhibits 4.10].
     4(c)          --   Indenture (for unsecured debt securities), dated as of
                        November 1, 2000, between PSO and The Bank of New York, as
                        Trustee [Registration Statement No. 333-100623, Exhibits
                        4(a) and 4(b)].
    *4(d)          --   Second Supplemental Indenture, dated as of November 26, 2002
                        establishing certain terms of the 6% Senior Notes, Series B,
                        due 2032.
   *10(a)          --   Copy of Restated and Amended Operating Agreement, dated as
                        of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
   *10(b)          --   Transmission Coordination Agreement, dated October 29, 1998,
                        among PSO, TCC, TNC, SWEPCo and AEPSC.
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the PSO 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of PSO [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21]
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

SWEPCO++
     3(a)          --   Restated Certificate of Incorporation, as amended through
                        May 6, 1997, including Certificate of Amendment of Restated
                        Certificate of Incorporation [Quarterly Report on Form 10-Q
                        of SWEPCo for the quarter ended March 31, 1997, File No.
                        1-3146, Exhibit 3.4].
     3(b)          --   By-Laws of SWEPCo (amended as of April 27, 2000) [Quarterly
                        Report on Form 10-Q of SWEPCo for the quarter ended March
                        31, 2000, File No. 1-3146, Exhibit 3.3].
     4(a)          --   Indenture, dated February 1, 1940, between SWEPCo and
                        Continental Bank, National Association and M. J. Kruger, as
                        Trustees, as amended and supplemented [Registration
                        Statement No. 2-60712, Exhibit 5.04; Registration Statement
                        No. 2-61943, Exhibit 2.02; Registration Statement No.
                        2-66033, Exhibit 2.02; Registration Statement No. 2-71126,
                        Exhibit 2.02; Registration Statement No. 2-77165, Exhibit
                        2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1 No. 70-7233,
                        Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No.
                        70-7934, Exhibit 10; Form U-1 No. 72-8041, Exhibit 10(b);
                        Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No. 70-8239,
                        Exhibit 10(a)].
     4(b)          --   SWEPCO-obligated, mandatorily redeemable preferred
                        securities of subsidiary trust holding solely Junior
                        Subordinated Debentures of SWEPCo:
                        (1) Indenture, dated as of May 1, 1997, between SWEPCo and
                            the Bank of New York, as Trustee [Quarterly Report on Form
                            10-Q of SWEPCo dated March 31, 1997, File No. 1-3146,
                            Exhibits 4.11 and 4.12].
                        (2) Amended and Restated Trust Agreement of SWEPCo Capital
                            I, dated as of May 1, 1997, among SWEPCo, as Depositor, the
                            Bank of New York, as Property Trustee, The Bank of New
                            York (Delaware), as Delaware Trustee, and the
                            Administrative Trustee [Quarterly Report on Form 10-Q of
                            SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit
                            4.13].
</Table>

                                       E-15
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
                        (3) Guarantee Agreement, dated as of May 1, 1997, delivered
                            by SWEPCo for the benefit of the holders of SWEPCo Capital
                            I's Preferred Securities [Quarterly Report on Form 10-Q
                            of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit
                            4.14].
                        (4) Agreement as to Expenses and Liabilities, dated as of
                            May 1, 1997 between SWEPCo and SWEPCo Capital I [Quarterly
                            Report on Form 10-Q of SWEPCo dated March 31, 1997, File
                            No. 1-3146, Exhibits 4.15].
     4(c)          --   Indenture (for unsecured debt securities), dated as of
                        February 4, 2000, between SWEPCo and The Bank of New York,
                        as Trustee [Registration Statement No. 333-87834, Exhibits
                        4(a) and 4(b); Form 8-K of SWEPCo filed on June 26, 2002,
                        File No. 1-3146, Exhibit 4(b)].
   *10(a)          --   Copy of Restated and Amended Operating Agreement, dated as
                        of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
   *10(b)          --   Transmission Coordination Agreement, dated October 29, 1998,
                        among PSO, TCC, TNC, SWEPCo and AEPSC.
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the SWEPCo 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of SWEPCo [Annual Report on Form 10-K
                        of AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21]
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

 TCC++
     3(a)          --   Restated Articles of Incorporation Without Amendment,
                        Articles of Correction to Restated Articles of Incorporation
                        Without Amendment, Articles of Amendment to Restated
                        Articles of Incorporation, Statements of Registered Office
                        and/or Agent, and Articles of Amendment to the Articles of
                        Incorporation [Quarterly Report on Form 10-Q of TCC for the
                        quarter ended March 31, 1997, File No. 0-346, Exhibit 3.1].
    *3(b)          --   Articles of Amendment to Restated Articles of Incorporation
                        of TCC dated December 18, 2002.
     3(c)          --   By-Laws of TCC (amended as of April 19, 2000) [Annual Report
                        on Form 10-K of TCC for the fiscal year ended December 31,
                        2000, File No. 0-346, Exhibit 3(b)].
     4(a)          --   Indenture of Mortgage or Deed of Trust, dated November 1,
                        1943, between TCC and The First National Bank of Chicago and
                        R. D. Manella, as Trustees, as amended and supplemented
                        [Registration Statement No. 2-60712, Exhibit 5.01;
                        Registration Statement No. 2-62271, Exhibit 2.02; Form U-1
                        No. 70-7003, Exhibit 17; Registration Statement No. 2-98944,
                        Exhibit 4 (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No.
                        70-7249, Exhibit 4; Form U-1 No. 70-7520, Exhibit 2; Form
                        U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit
                        10; Form U-1 No. 70-8053, Exhibit 10 (a); Form U-1 No.
                        70-8053, Exhibit 10 (b); Form U-1 No. 70-8053, Exhibit 10
                        (c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No.
                        70-8053, Exhibit 10 (e); Form U-1 No. 70-8053, Exhibit 10
                        (f)].
     4(b)          --   TCC-obligated, mandatorily redeemable preferred securities
                        of subsidiary trust holding solely Junior Subordinated
                        Debentures of TCC:
                        (1) Indenture, dated as of May 1, 1997, between TCC and the
                            Bank of New York, as Trustee [Quarterly Report on Form 10-Q
                            of TCC dated March 31, 1997, File No. 0-346, Exhibits
                            4.1 and 4.2].
</Table>

                                       E-16
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
                        (2) Amended and Restated Trust Agreement of TCC Capital I,
                            dated as of May 1, 1997, among TCC, as Depositor, the Bank
                            of New York, as Property Trustee, The Bank of New York
                            (Delaware), as Delaware Trustee, and the Administrative
                            Trustee [Quarterly Report on Form 10-Q of TCC dated
                            March 31, 1997, File No. 0-346, Exhibit 4.3].
                        (3) Guarantee Agreement, dated as of May 1, 1997, delivered
                            by TCC for the benefit of the holders of TCC Capital I's
                            Preferred Securities [Quarterly Report on Form 10-Q of
                            TCC dated March 31, 1997, File No. 0-346, Exhibit 4.4].
                        (4) Agreement as to Expenses and Liabilities dated as of May
                            1, 1997, between TCC and TCC Capital I [Quarterly Report on
                            Form 10-Q of TCC dated March 31, 1997, File No. 0-346,
                            Exhibit 4.5].
     4(c)          --   Indenture (for unsecured debt securities), dated as of
                        November 15, 1999, between TCC and The Bank of New York, as
                        Trustee, as amended and supplemented [Annual Report on Form
                        10-K of TCC for the fiscal year ended December 31, 2000,
                        File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].
   *10(a)          --   Copy of Restated and Amended Operating Agreement, dated as
                        of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
   *10(b)          --   Transmission Coordination Agreement, dated October 29, 1998,
                        among PSO, TCC, TNC, SWEPCo and AEPSC.
   *12             --   Statement re: Computation of Ratios.
   *13             --   Copy of those portions of the TCC 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
    21             --   List of subsidiaries of TCC [Annual Report on Form 10-K of
                        AEP for the fiscal year ended December 31, 2002, File No.
                        1-3525, Exhibit 21]
   *23             --   Consent of Deloitte & Touche LLP.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Financial Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.

 TNC++
     3(a)          --   Restated Articles of Incorporation, as amended, and Articles
                        of Amendment to the Articles of Incorporation [Annual Report
                        on Form 10-K of TNC for the fiscal year ended December 31,
                        1996, File No. 0-340, Exhibit 3.5].
    *3(b)          --   Articles of Amendment to Restated Articles of Incorporation
                        of TNC dated December 17, 2002.
     3(c)          --   By-Laws of TNC (amended as of May 1, 2000) [Quarterly Report
                        on Form 10-Q of TNC for the quarter ended March 31, 2000,
                        File No. 0-340, Exhibit 3.4].
     4(a)          --   Indenture, dated August 1, 1943, between TNC and Harris
                        Trust and Savings Bank and J. Bartolini, as Trustees, as
                        amended and supplemented [Registration Statement No.
                        2-60712, Exhibit 5.05; Registration Statement No. 2-63931,
                        Exhibit 2.02; Registration Statement No. 2-74408, Exhibit
                        4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No.
                        70-6925, Exhibit 13; Registration Statement No. 2-98843,
                        Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1 No.
                        70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form
                        U-1 No. 70-8057, Exhibit 10; Form U-1 No. 70-8265, Exhibit
                        10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No.
                        70-8057, Exhibit 10(c)].
   *10(a)          --   Copy of Restated and Amended Operating Agreement, dated as
                        of January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC.
   *10(b)          --   Transmission Coordination Agreement, dated October 29, 1998,
                        among PSO, TCC, TNC, SWEPCo and AEPSC.
   *12             --   Statement re: Computation of Ratios.
</Table>

                                       E-17
<PAGE>

<Table>
<Caption>
EXHIBIT NUMBER                                  DESCRIPTION
- ---------------                                 -----------
<C>               <C>   <S>
   *13             --   Copy of those portions of the TNC 2002 Annual Report (for
                        the fiscal year ended December 31, 2002) which are
                        incorporated by reference in this filing.
   *24             --   Power of Attorney.
   *99(a)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
   *99(b)          --   Certification of Chief Executive Officer Pursuant to Section
                        1350 of Chapter 63 of Title 18 of the United States Code.
</Table>

                             ----------------------

     ++ Certain instruments defining the rights of holders of long-term debt of
the registrants included in the financial statements of registrants filed
herewith have been omitted because the total amount of securities authorized
thereunder does not exceed 10% of the total assets of registrants. The
registrants hereby agree to furnish a copy of any such omitted instrument to the
SEC upon request.

                                       E-18
<PAGE>

                                     (LOGO)

                                  RECYCLE LOGO
                           PRINTED ON RECYCLED PAPER

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>4
<FILENAME>x4b.txt
<DESCRIPTION>(B) THIRD SUPP INDENTURE
<TEXT>

<PAGE>

                                                                   EXHIBIT 4(b)











                      AMERICAN ELECTRIC POWER COMPANY, INC.


                                       AND


                              THE BANK OF NEW YORK,
                                   as Trustee


                             -----------------------



                          THIRD SUPPLEMENTAL INDENTURE

                            Dated as of June 11, 2002


                                       TO


                                    INDENTURE


                             Dated as of May 1, 2001


                     5.75% Senior Notes Due August 16, 2007


                             -----------------------



<PAGE>



                               TABLE OF CONTENTS*


                                   ARTICLE ONE


                GENERAL TERMS AND CONDITIONS OF THE SENIOR NOTES

Section 1.1.   Definitions................................................1
Section 1.2.   Establishment, Designation and Principal Amount............3
Section 1.3.   Payment of Principal and Interest..........................4
Section 1.4.   Denominations..............................................6
Section 1.5.   Global Securities..........................................6
Section 1.6.   Remarketing................................................7
Section 1.7.   Optional Remarketing.......................................13
Section 1.8.   Sinking Fund...............................................14
Section 1.9.   Redemption and Repurchase..................................14
Section 1.10.  Covenants..................................................14
Section 1.11.  Defeasance.................................................14
Section 1.12.  Tax Event Redemption.......................................15
Section 1.13.  Tax Treatment..............................................16

                                   ARTICLE II


                            MISCELLANEOUS PROVISIONS

Section 2.1.   Recitals by Company........................................16
Section 2.2.   Ratification and Incorporation of Original Indenture.......16
Section 2.3.   Executed in Counterparts...................................16
Section 2.4.   Separability...............................................16
Section 2.5.   Governing Law..............................................17

Exhibit A      Form of Senior Note........................................A-1



- -------------------------
*    This Table of Contents does not constitute part of the Indenture or have
     any bearing upon the interpretation of any of its terms and provisions.





<PAGE>


     THIRD  SUPPLEMENTAL  INDENTURE,  dated  as of June  11,  2002  (the  "Third
Supplemental  Indenture"),  between  AMERICAN  ELECTRIC POWER  COMPANY,  INC., a
corporation  duly organized and existing under the laws of the State of New York
(hereinafter sometimes referred to as the "Company"),  and THE BANK OF NEW YORK,
a New York banking corporation, as trustee (hereinafter sometimes referred to as
the "Trustee"),  under the Indenture dated as of May 1, 2001 between the Company
and  the  Trustee  (the  "Original  Indenture").   The  Original  Indenture,  as
previously  supplemented from time to time, including by this Third Supplemental
Indenture, is hereafter referred to as the "Indenture."

                                   WITNESSETH:

     WHEREAS,  the Company has executed and delivered the Original  Indenture to
the Trustee to provide for the issuance of unsecured  promissory  notes or other
evidences of indebtedness (the "Securities") in an unlimited aggregate principal
amount,  to be issued from time to time in one or more series as provided in the
Original Indenture; and

     WHEREAS,  pursuant  to the terms of the  Original  Indenture,  the  Company
desires to provide for the establishment of a new series of its Securities (said
series  being  hereinafter  referred  to as the  "Senior  Notes"),  the form and
substance of such Senior Notes and the terms,  provisions and conditions thereof
to  be  set  forth  as  provided  in  the  Original  Indenture  and  this  Third
Supplemental Indenture; and

     WHEREAS,  the Company desires and has requested the Trustee to join with it
in the  execution  and delivery of this Third  Supplemental  Indenture,  and all
requirements  necessary  to  make  this  Third  Supplemental  Indenture  a valid
instrument,  in accordance  with its terms,  and to make the Senior Notes,  when
executed by the Company and  authenticated  and  delivered by the  Trustee,  the
valid  obligations of the Company,  have been  performed and fulfilled,  and the
execution and delivery hereof have been in all respects duly authorized;

     NOW  THEREFORE,  in  consideration  of the purchase and  acceptance  of the
Senior Notes by the holders  thereof,  and for the purpose of setting forth,  as
provided in the Original  Indenture,  the form and substance of the Senior Notes
and the terms,  provisions and  conditions  thereof,  the Company  covenants and
agrees with the Trustee as follows:

                                  ARTICLE ONE

                GENERAL TERMS AND CONDITIONS OF THE SENIOR NOTES

SECTION 1.1.  Definitions.
- --------------------------

     Except  as  otherwise  expressly  provided  in or  pursuant  to this  Third
Supplemental Indenture or unless the context otherwise requires:

          (1) a term defined in the Original Indenture has the same meaning when
     used in this Third Supplemental Indenture;

          (2) a term defined anywhere in this Third  Supplemental  Indenture has
     the same meaning throughout;

          (3) the singular includes the plural and vice versa;

          (4) headings are for  convenience  of reference only and do not affect
     interpretation;

          (5) capitalized  terms used herein for which no definition is provided
     herein shall have the meanings  set forth in the  Original  Indenture,  the
     Forward  Purchase  Contract  Agreement,  the  Remarketing  Agreement or the
     Pledge Agreement, as the case may be and as the context may require; and

          (6) the  following  terms  have  the  meanings  given  to them in this
     Section 1.1(6):

               "Business Day" means any day other than a Saturday, Sunday or any
               other day on which banking  institutions  and trust companies the
               State of New  York or at a place of  payment  are  authorized  or
               required by law, regulation or executive order to be closed.

               "Company" has the meaning set forth in the preamble.

               "Contingent  Payment  Regulations"  has the  meaning set forth in
               Section 1.13.

               "Forward Purchase Contract Agent" means The Bank of New York.

               "Forward Purchase Contract Agreement" means the agreement,  dated
               as of June 11, 2002, between the Company and the Forward Purchase
               Contract Agent.

               "Global Securities" has the meaning set forth in Section 1.5.

               "Interest Payment Date" has the meaning set forth in Section 1.3.

               "Pledge  Agreement" means the Pledge Agreement,  dated as of June
               11,  2002,  between  the  Company  and The Bank of New  York,  as
               Forward  Purchase  Contract Agent,  Collateral  Agent,  Custodial
               Agent and Securities Intermediary.

               "Regular  Record  Date"  means,  with  respect  to each  Interest
               Payment Date, the close of business on the Business Day preceding
               such  Interest  Payment  Date;  provided,  that with  respect  to
               Separate Notes that are not in book-entry  only form, the Regular
               Record Date shall be the close of  business on the 15th  Business
               Day preceding such Interest Payment Date.

               "Remarketing" means any remarketing  conducted pursuant to and in
               accordance with the Remarketing Agreement.

               "Remarketing Agreement" means the Remarketing Agreement, dated as
               of June 11, 2002, by and among the Company, the Remarketing Agent
               and the Forward Purchase Contract Agent.

               "Remarketing Value" means

               (i)  the  value  at  the  Remarketing   Date  or  any  Subsequent
                    Remarketing  Date,  as the case may be, of  either  (a) U.S.
                    Treasury  securities  that  will  pay,  on or  prior  to the
                    Payment Date falling on the Stock  Purchase  Date, an amount
                    of cash  equal to the  aggregate  interest  payment  that is
                    scheduled  to be payable on that  Payment  Date,  on (x) the
                    Notes   which  are   included   in  Equity   Units  and  are
                    participating  in the remarketing and (y) the Separate Notes
                    which are to be remarketed pursuant to Section 4.5(d) of the
                    Pledge  Agreement,   assuming  for  that  purpose  that  the
                    interest  rate on the Notes is equal to the Coupon Rate,  if
                    the  Remarketing  occurs  prior to the fourth  Business  Day
                    preceding the Stock  Purchase Date, or (b) an amount of cash
                    equal to the aggregate interest payment that is scheduled to
                    be payable on that Payment  Date, on (x) the Notes which are
                    included  in  Equity  Units  and  are  participating  in the
                    remarketing  and  (y) the  Separate  Notes  which  are to be
                    remarketed   pursuant  to  Section   4.5(d)  of  the  Pledge
                    Agreement  and  Section  1.6  of  this  Third   Supplemental
                    Indenture,  assuming for that purpose that the interest rate
                    on the Notes is equal to the Coupon Rate, if the Remarketing
                    occurs on or after the fourth  Business  Day  preceding  the
                    Stock Purchase Date; and

               (ii) the  value  at  the  Remarketing   Date  or  any  Subsequent
                    Remarketing  Date,  as the case may be, of  either  (a) U.S.
                    Treasury  securities that will pay, on or prior to the Stock
                    Purchase  Date, an amount of cash equal to the Stated Amount
                    of (x) such Notes which are included in Equity Units and are
                    participating  in the remarketing and (y) the Separate Notes
                    which are to be remarketed pursuant to Section 4.5(d) of the
                    Pledge  Agreement,  if the  Remarketing  occurs prior to the
                    fourth  Business Day preceding the Stock  Purchase  Date, or
                    (b) an amount of cash equal to the Stated Amount of (x) such
                    Notes   which  are   included   in  Equity   Units  and  are
                    participating  in the remarketing and (y) the Separate Notes
                    which are to be remarketed pursuant to Section 4.5(d) of the
                    Pledge Agreement and Section 1.6 of this Third  Supplemental
                    Indenture,  if the Remarketing occurs on or after the fourth
                    Business Day preceding the Stock Purchase Date

               provided  that for  purposes  of clauses  (1) and (2) above,  the
               Remarketing Value shall be calculated on the assumptions that (x)
               the U.S.  Treasury  securities are highly liquid and mature on or
               within 35 days prior to the Stock Purchase Date, as determined in
               good  faith by the  Remarketing  Agent in a  manner  intended  to
               minimize the cash value of the U.S. Treasury securities,  and (y)
               the U.S.  Treasury  securities  are valued  based on the ask-side
               price of the U.S. Treasury securities at a time between 9:00 a.m.
               and 11:00 a.m., New York City time,  selected by the  Remarketing
               Agent,  on the  Remarketing  Date or any  Subsequent  Remarketing
               Date, as the case may be, as determined on a third-day settlement
               basis by reasonable and customary means selected in good faith by
               the Remarketing Agent, plus accrued interest to that date.

               "Reset  Rate" means the  interest  rate per annum with respect to
               the Senior  Notes that is  determined  by the  Remarketing  Agent
               pursuant to the Remarketing Agreement as follows:

               (i)  in  connection  with a successful  Remarketing,  the rate of
                    interest  that,  in the  opinion of the  Remarketing  Agent,
                    will, when applied to the Outstanding  Senior Notes,  enable
                    the then current  aggregate market value of the Senior Notes
                    to have a value equal to  approximately,  but not less than,
                    100.25% of the Remarketing  Value as of the Remarketing Date
                    or as of any  Subsequent  Remarketing  Date, as the case may
                    be; or

               (ii) upon the  occurrence  of a Failed  Remarketing,  the rate of
                    interest  applicable to the Senior Notes initially until (A)
                    the Senior Notes are successfully remarketed pursuant to the
                    Forward  Purchase  Contract  Agreement  and the  Remarketing
                    Agreement or (B) if the Last Failed  Remarketing  shall have
                    occurred,  a  market  rate  of  interest  as  determined  in
                    accordance with Section 1.6 of this Supplemental Indenture.

               "Senior Notes" has the meaning set forth in the recitals.

               "Stated Maturity" means August 16, 2007.

               "Telerate" means the Dow Jones Telerate Service.

               "Tax Event  Redemption Date" has the meaning set forth in Section
               1.11.

SECTION 1.2.  Establishment, Designation and Principal Amount.
- --------------------------------------------------------------

     (a) There shall be and is hereby  authorized a series of  Securities  under
the Original Indenture  designated the "5.75% Senior Notes Due August 16, 2007,"
in the initial aggregate principal amount of $300,000,000, which amount shall be
as set forth in the Company  Order for the  authentication  and  delivery of the
Senior Notes pursuant to Section 2.04 of the Original Indenture.  Such aggregate
principal  amount of the 5.75% Senior Notes Due August 16, 2007 may be increased
from time to time in accordance with Section 2.01 of the Original Indenture.

     (b) The  Senior  Notes  shall  mature  and the  principal  shall be due and
payable  together  with all  accrued and unpaid  interest  thereon on August 16,
2007.

     (c) The Senior  Notes that are part of the Equity  Units shall be issued in
definitive fully registered form (the "Registered Securities"), without coupons,
in  substantially  the form set out in Exhibit A hereto.  The  entire  principal
amount  of the  Senior  Notes  shall  initially  be  evidenced  by  one or  more
certificates  issued to The Bank of New York, as the Forward  Purchase  Contract
Agent under the Forward Purchase Contract Agreement (as defined below).

     (d) The Senior Notes that, in accordance with the Forward Purchase Contract
Agreement,  are no longer part of Equity Units shall be represented initially by
Global Securities (as defined below).  Each such Registered  Security and Global
Security  shall  represent such aggregate  principal  amount of the  Outstanding
Senior Notes as shall be from time to time  endorsed  thereon,  which  principal
amounts may be increased or decreased, as applicable,  to reflect Transfers from
Pledged  Notes to Separate  Notes and Transfers  from Separate  Notes to Pledged
Notes.  Any such increase or decrease in the aggregate  principal  amount of (i)
Registered  Securities  shall be made by the  Collateral  Agent and (ii)  Global
Securities  representing Senior Notes shall be made by the Trustee, as custodian
of the Global  Securities,  in each case upon the instructions of the Collateral
Agent given pursuant to Article IV of the Pledge Agreement.


SECTION 1.3. Payment of Principal and Interest.
- -----------------------------------------------

     (a) The unpaid  principal  amount of the Senior Notes shall  initially bear
interest at the rate of 5.75% per annum,  payable on each  February  16, May 16,
August 16 and November 16 (each,  with respect to the Senior Notes, an "Interest
Payment  Date"),  from the original  date of issuance,  to, but  excluding,  the
earlier of (i) the settlement date of a successful Remarketing under the Forward
Purchase Contract Agreement or (ii) the Stock Purchase Date, and, thereafter, at
the Reset Rate to, but excluding, the Stated Maturity of the Senior Notes.

     (b) Interest shall be payable quarterly in arrears on each Interest Payment
Date to the Person in whose name the Senior Notes are  registered on the Regular
Record Date for such Interest  Payment Date;  provided that interest  payable on
the Stated  Maturity of principal as provided herein shall be paid to the person
to whom  principal is payable.  Any such  interest not  punctually  paid or duly
provided for with respect to any Interest  Payment Date falling  after the Stock
Purchase Date shall forthwith  cease to be payable to the registered  holders on
such regular record date, and may be paid to the person or persons in whose name
the Senior  Notes are  registered  at the close of business on a special  record
date to be fixed by the  Trustee  for the  payment of such  defaulted  interest,
notice whereof shall be given to the registered  holders of the Senior Notes not
less than ten (10) days prior to such special record date, or may be paid at any
time in any other lawful manner not  inconsistent  with the  requirements of any
securities  exchange,  if any, on which the Senior Notes may be listed, and upon
such notice as may be required by such  exchange,  all as more fully provided in
Section 2.03 of the Original Indenture.

     (c) The amount of interest  payable for any period will be computed (1) for
any quarterly  period,  on the basis of a 360-day year of twelve 30-day  months,
(2) for any  period  shorter  than a full  quarterly  period,  on the basis of a
30-day  month  and (3) for  periods  of less  than a month,  on the basis of the
actual number of days elapsed per 30-day month.  If any date on which  principal
or interest  is payable is not a Business  Day,  then  payment of  principal  or
interest payable on such date will be made on the next succeeding day which is a
Business Day (and  without any interest or other  payment in respect of any such
delay),  except that,  if such Business Day is in the next  succeeding  calendar
year, such payment shall be made on the immediately  preceding  Business Day, in
each case with the same force and effect as if made on such date.

     (d) Payment of the  principal  of and interest on the Senior Notes shall be
made at an Office or Agency of the  Company or at the Office of the Agent in The
City of New York in such coin or currency of the United  States of America as at
the time of payment is legal  tender for  payment of public and  private  debts,
with any such  payment  that is due on the Stated  Maturity of any Senior  Notes
being made upon  surrender  of such Senior  Notes to the Office or Agency of the
Company  or at the  Office  of the Agent in The City of New  York.  Payments  of
interest will be made, subject to such surrender where applicable, at the option
of the  Company,  (i) by check  mailed to the  address  of the  person  entitled
thereto as such address  shall  appear in the Security  Register or (ii) by wire
transfer  at such  place and to such  account  at a banking  institution  in the
United  States as may be  designated  in writing to the Trustee at least sixteen
(16) days prior to the date for payment by the Person entitled hereto.


SECTION 1.4. Denominations.
- ---------------------------

     The  Senior  Notes  shall be issued in  denominations  of $50 and  integral
multiples of $50.


SECTION 1.5..Global Securities.
- -------------------------------

     (a) The Senior Notes that, in accordance with the Forward Purchase Contract
Agreement,  are no longer part of the Equity  Units will be issued  initially in
the form of one or more global securities (the "Global  Securities")  registered
in the  name of DTC or its  nominee.  Except  under  the  limited  circumstances
described below or in Section 1.3 above, Senior Notes represented by such Global
Securities will not be exchangeable  for, and will not otherwise be issuable as,
Senior Notes in definitive form. The Global  Securities  described above may not
be  transferred  except by DTC to a nominee of DTC or by a nominee of DTC to DTC
or another nominee of DTC or to a successor Depository or its nominee.

     (b) Owners of  beneficial  interests in such a Global  Security will not be
considered  the  Holders  thereof for any purpose  under the  Indenture,  and no
Global  Security  representing a Senior Note shall be  exchangeable,  except for
another Global Security of like  denomination  and tenor to be registered in the
name of DTC or its nominee or to a successor Depository or its nominee or except
as  described  below.  The rights of owners of  beneficial  interests  in such a
Global Security shall be exercised only through DTC.

     (c) A Global Security shall be exchangeable  for Senior Notes registered in
the names of persons  other than DTC or its nominee only if (i) DTC notifies the
Company  that it is  unwilling  or unable to continue as a  Depository  for such
Global  Security and no successor  Depository  shall have been  appointed by the
Company within 90 days of receipt by the Company of such notification,  or if at
any time DTC  ceases to be a clearing  agency  registered  under the  Securities
Exchange Act of 1934 at a time when DTC is required to be so  registered  to act
as such Depository and no successor  Depository shall have been appointed by the
Company  within 90 days after it becomes  aware of such  cessation,  or (ii) the
Company in its sole discretion  determines that it no longer has any senior debt
securities  represented  by global  securities  or that it will  permit a Global
Security  to be  exchangeable  or an Event of Default  under the  Indenture  has
occurred and is continuing. Any Global Security that is exchangeable pursuant to
the preceding sentence shall be exchangeable for Senior Notes registered in such
names as DTC shall direct.


SECTION 1.6. Remarketing.
- -------------------------

     (a) The Pledged  Notes  comprising  part of Equity  Units and the  Separate
Notes of  holders of  Separate  Notes that have  elected to  participate  in the
Remarketing  shall be remarketed  by the  Remarketing  Agent on the  Remarketing
Date. A Holder of Equity Units may elect not to participate in a Remarketing and
retain the Senior Notes  underlying  such Equity Units by notifying  the Forward
Purchase  Contract Agent of such election and  delivering  the Opt-out  Treasury
Consideration to the Forward  Purchase  Contract Agent not later than 10:00 a.m.
on the fourth Business Day prior to the Remarketing  Date, as applicable (or, in
the case of a Failed  Remarketing,  not later  than  10:00  a.m.  on the  fourth
Business Day  immediately  prior to the  subsequent  Remarketing  Period).  Upon
receipt thereof by the Forward  Purchase  Contract Agent,  the Forward  Purchase
Contract  Agent  shall  deliver  such  Opt-out  Treasury  Consideration  to  the
Collateral  Agent,  which will, for the benefit of the Company,  thereupon apply
such Opt-out Treasury  Consideration to secure such Holder's  obligations  under
the Forward Purchase Contracts.  On the first Business Day immediately preceding
the Remarketing  Date (or, in the case of a Failed  Remarketing,  the subsequent
Remarketing Period),  the Collateral Agent,  pursuant to the terms of the Pledge
Agreement,  will  deliver the Pledged  Notes to the  Forward  Purchase  Contract
Agent.  Within three Business Days following any  Remarketing  Period (A) if the
Remarketing was successful, the Forward Purchase Contract Agent shall distribute
such Notes to the new Holders thereof and (B) if there was a Failed Remarketing,
the Forward  Purchase  Contract  Agent will deliver such Notes to the Collateral
Agent,  which will, for the benefit of the Company,  thereupon  apply such Notes
that are a component of Equity Units to secure such Holders'  obligations  under
the  Forward  Purchase  Contracts,  return any  Opt-out  Treasury  Consideration
delivered by such  Holders to such Holders and return the Separate  Notes to the
holders  thereof.  A  Holder  that  does not so  deliver  the  Opt-out  Treasury
Consideration  or has not settled the related  Purchase  Contract through a Cash
Settlement  or an  Early  Settlement  pursuant  to  Sections  5.4 and 5.9 of the
Forward  Purchase  Contract  Agreement  shall  be  deemed  to  have  elected  to
participate in the Remarketing.

     (b) On the seventh  Business Day prior to the Remarketing Date or the first
day of any  subsequent  Remarketing  Period,  the Company  shall give Holders of
Equity  Units and  Holders of Separate  Notes  notice of the  Remarketing  in an
Authorized   Newspaper,   including  the  specific  U.S.  Treasury  security  or
securities  (including  the CUSIP  number  and/or  the  principal  terms of such
Treasury  security or  securities)  that must be  delivered by Holders of Equity
Units that  elect not to  participate  in the  Remarketing  pursuant  to Section
5.4(g) of the Forward Purchase Contract Agreement, no later than 10:00 a.m. (New
York City time) on the seventh Business Day preceding the Remarketing  Date. Not
later than seven nor more than 15 calendar days prior to any Remarketing Period,
the Company  shall  request DTC (or any  successor  Clearing  Agency) to notify,
directly or indirectly,  each Beneficial  Owner or Clearing  Agency  Participant
holding Equity Units or Stripped Units and each  Beneficial  Owner of a Separate
Note  of  the  Remarketing  and of the  procedures  that  must  be  followed  in
connection with the Remarketing.

     (c) The Forward  Purchase  Contract Agent shall notify,  by 10:00 a.m., New
York City time, on the third Business Date preceding the Remarketing Date or the
first day of any subsequent  Remarketing Period, as applicable,  the Remarketing
Agent and the Collateral Agent of the aggregate number of Senior Notes of Equity
Units Holders to be remarketed.  On the third Business Day immediately preceding
the Remarketing Date or the first day of any subsequent  Remarketing  Period, as
applicable,  no later than by 10:00 a.m.  New York City  time,  pursuant  to the
terms of the Pledge  Agreement,  the Custodial Agent will notify the Remarketing
Agent of the aggregate  number of Separate Notes to be remarketed.  On the third
Business Day immediately  preceding the Remarketing Date or the first day of any
subsequent  Remarketing  Period,  as applicable,  the  Collateral  Agent and the
Custodial Agent, pursuant to the terms of the Pledge Agreement, will deliver for
Remarketing to the Remarketing Agent all Notes to be remarketed. Upon receipt of
such notice from the Forward Purchase Contract Agent and the Custodial Agent and
such Notes from the Collateral  Agent and the Custodial  Agent,  the Remarketing
Agent will,  on the  Remarketing  Date,  use its  commercially  reasonable  best
efforts to establish a Reset Rate  pursuant to clause (i) of the  definition  of
Reset Rate and remarket such Senior Notes pursuant to the Remarketing procedures
in the Remarketing Agreement.

     (d) The  right of each  Holder  of Senior  Notes to have its  Senior  Notes
tendered  for  purchase  will be limited to the extent that (i) the  Remarketing
Agent conducts a Remarketing pursuant to the terms of the Remarketing Agreement,
(ii) the  Remarketing  Agent is able to find a purchaser or  purchasers  for the
tendered  Senior  Notes and (iii)  such  purchaser  or  purchasers  deliver  the
purchase price therefor to the Remarketing Agent.

     (e) Upon receipt of the notice  provided  above in  paragraph  (c) from the
Forward Purchase  Contract Agent and the Custodial Agent and such Notes from the
Collateral  Agent and the Custodial  Agent,  the Remarketing  Agent will, on the
Remarketing Date, use its commercially  reasonable best efforts to (i) establish
a rate of interest that, in the opinion of the  Remarketing  Agent,  will,  when
applied to the outstanding Notes, enable the then current aggregate market value
of the Notes to have a value equal to approximately,  but not less than, 100.25%
of the  Remarketing  Value as of the  Remarketing  Date or as of any  Subsequent
Remarketing Date, as the case may be (the "Reset Rate") and (ii) sell such Notes
on such date at a price equal to  approximately,  but not less than,  100.25% of
the Remarketing Value.

     (f) If, in spite of using its  commercially  reasonable  best efforts,  the
Remarketing  Agent  cannot  establish  the  Reset  Rate and  remarket  the Notes
included  in the  remarketing  at a price equal to  approximately,  but not less
than, 100.25% of the Remarketing Value, the Remarketing Agent will again attempt
to establish the Reset Rate and remarket the Notes  included in the  remarketing
at a price equal to approximately, but not less than, 100.25% of the Remarketing
Value on each of the two immediately following Business Days. If the Remarketing
Agent cannot  remarket the Notes included in the remarketing at a price equal to
approximately,  but not less than,  100.25% of the  Remarketing  Value on any of
those days,  it will attempt to establish  the Reset Rate and remarket the Notes
included  in the  remarketing  at a price equal to  approximately,  but not less
than,  100.25%  of the  Remarketing  Value on each of the  three  Business  Days
immediately  preceding June 16, 2005. If the  Remarketing  Agent cannot remarket
the Notes included in the remarketing at a price equal to approximately, but not
less  than,  100.25%  of the  Remarketing  Value on any of those  days,  it will
attempt to  establish  the Reset Rate and  remarket  the Notes  included  in the
remarketing at a price equal to approximately, but not less than, 100.25% of the
Remarketing Value on each of the three Business Days immediately  preceding July
16, 2005. If the Remarketing  Agent cannot establish the Reset Rate and remarket
the Notes included in the remarketing at a price equal to approximately, but not
less than,  100.25% of the  Remarketing  Value either on any of the two Business
Days immediately  following the Remarketing Date or on any of the three Business
Days  immediately  preceding  June 16, 2005 or on any of the three Business Days
immediately  preceding  July 16, 2005,  the  remarketing  in each period will be
deemed to have failed (each, a "Failed  Remarketing").  If the Remarketing Agent
cannot  establish  the  Reset  Rate  and  remarket  the  Notes  included  in the
remarketing at a price equal to approximately, but not less than, 100.25% of the
Remarketing  Value on any of the three Business Days immediately  preceding July
16, 2005, the Remarketing Agent will further attempt to establish the Reset Rate
and  remarket  the  Notes  included  in the  remarketing  at a  price  equal  to
approximately,  but not less than,  100.25% of the Remarketing  Value on each of
the three Business Days  immediately  preceding August 12, 2005. If, in spite of
using its commercially  reasonable best efforts,  the Remarketing Agent fails to
remarket   the  Notes   underlying   the  Equity  Units  at  a  price  equal  to
approximately, but not less than, 100.25% of the Remarketing Value in accordance
with the terms of the Pledge  Agreement by 4:00 p.m., New York City time, on the
third Business Day immediately preceding the Stock Purchase Date, a "Last Failed
Remarketing" will be deemed to have occurred.

     (g) If a successful  Remarketing  shall have  occurred  prior to the fourth
Business Day preceding the Stock Purchase Date, the  Remarketing  Agent will, in
accordance  with the Forward  Purchase  Contract  Agreement and the  Remarketing
Agreement:

          (i)  deduct and retain for itself the Remarketing Fee;

          (ii) use the proceeds from such successful Remarketing to purchase the
               Agent-purchased Treasury Consideration with the CUSIP numbers, if
               any, selected by the Remarketing Agent,  described in clauses (1)
               and (2) of the  definition  of  Remarketing  Value related to the
               Senior Notes of Holders of Equity Units that were remarketed;

          (iii)if any Separate  Notes were  remarketed,  remit to the Collateral
               Agent for payment to the Holders of such  Separate  Notes sold in
               the  Remarketing  the  remaining  proceeds  from such  successful
               Remarketing attributable to the Separate Notes; and

          (iv) if there remain any proceeds  from such  successful  Remarketing,
               after the  application  of such  proceeds as set forth in clauses
               (i) through  (iii) of this  sentence,  then remit such  remaining
               proceeds to the Forward  Purchase  Contract  Agent for payment to
               the Holders of the Equity  Units that were  remarketed,  on a pro
               rata basis, in accordance with the Remarketing Agreement.

     (h) In the case of a successful  Remarketing  occurring prior to the fourth
Business  Day  preceding  the  Stock  Purchase  Date,  on or prior to the  third
Business Day following the Remarketing Date or any Subsequent  Remarketing Date,
the Remarketing Agent shall deliver such Agent-purchased  Treasury Consideration
to the Forward  Purchase  Contract  Agent,  which shall  thereupon  deliver such
Agent-purchased  Treasury  Consideration to the Collateral Agent. The Collateral
Agent, for the benefit of the Company, will thereupon apply such Agent-purchased
Treasury Consideration,  in accordance with the Pledge Agreement, to secure such
Holders' obligations under the Forward Purchase Contracts.

     (i) If a successful  Remarketing shall have occurred on or after the fourth
Business Day preceding the Stock Purchase Date, the  Remarketing  Agent will, in
accordance  with the Forward  Purchase  Contract  Agreement and the  Remarketing
Agreement:

          (i)  deduct and retain for itself the Remarketing Fee;

          (ii) pay the proceeds from such successful  Remarketing to the Forward
               Purchase  Contract  Agent,  which shall  thereupon  deliver  such
               proceeds to the  Collateral  Agent which,  for the benefit of the
               Company,  will thereupon apply such proceeds,  in accordance with
               the  Pledge  Agreement  in  direct  settlement  of  the  Holders'
               obligations under the Forward Purchase Contracts;

          (iii)if any Separate  Notes were  remarketed,  remit to the Collateral
               Agent for payment to the Holders of such  Separate  Notes sold in
               the  Remarketing  the  remaining  proceeds  from such  successful
               Remarketing attributable to the Separate Notes; and

          (iv) if there remain any proceeds  from such  successful  Remarketing,
               after the  application  of such  proceeds as set forth in clauses
               (i) through  (iii) of this  sentence,  then remit such  remaining
               proceeds to the Forward  Purchase  Contract  Agent for payment to
               the Holders of the Equity  Units that were  remarketed,  on a pro
               rata basis, in accordance with the Remarketing Agreement.

     (j) If a successful  Remarketing  occurs,  by approximately  4:30 p.m. (New
York City time) on the Remarketing  Date, the Remarketing Agent shall advise, by
telephone (promptly confirmed in writing in the case of clause (i)):

          (i)  the Company,  the Forward Purchase Contract Agent, the Collateral
               Agent,  the Securities  Intermediary,  DTC and the Trustee of the
               Reset Rate determined in the Remarketing;

          (ii) each purchaser (or the Depository  Participant thereof) of Senior
               Notes in the  Remarketing  of the  Reset  Rate and the  number of
               Senior Notes such purchaser is to purchase; and

          (iii)each   purchaser   to  give   instructions   to  its   Depository
               Participant  to pay the purchase  price on the date of settlement
               for such  Remarketing  in same day funds against  delivery of the
               remarketed Senior Notes purchased through the facilities of DTC.

     (k) Any  distribution to Holders of excess funds and interest  described in
this  Section 1.6 shall be payable at the Office of the Agent in The City of New
York  maintained  for that purpose or, at the option of the Holder or the holder
of Separate Notes,  as applicable,  by check mailed to the address of the Person
entitled  thereto at such address as it appears on the  relevant  Register or by
wire  transfer to an account  specified  by the Holder or the holder of Separate
Notes, as applicable.

     (l) If a Failed Remarketing  occurs, the Remarketing Agent and the Company,
as applicable, shall take the following actions:

          (i)  the Remarketing Agent shall notify by telephone the Company,  the
               Forward  Purchase  Contract Agent,  the Collateral  Agent and the
               Trustee,  that a Failed  Remarketing has occurred,  whereupon the
               Company shall notify the Clearing  Agency,  by telephone,  that a
               Failed Remarketing has occurred;

          (ii) with respect to any Remarketing Period during which no successful
               Remarketing  occurred,  the Company shall publish notice by means
               of Bloomberg and Reuters  newswires,  such notice to be published
               no later than the fourth  Business Day  following the end of such
               Remarketing Period;

          (iii)the   Remarketing   Agent  shall  determine  the  Reset  Rate  in
               accordance with clause (ii) of the Reset Rate definition; and

          (iv) the  Remarketing  Agent shall remit,  within three  Business Days
               following  the end of a  Remarketing  Period which  constituted a
               Failed Remarketing,  the Pledged Notes that were to be remarketed
               to the  Collateral  Agent and the Separate  Notes that were to be
               remarketed to the Custodial Agent.

     (m) If upon a Last Failed  Remarketing,  the Collateral  Agent delivers any
Senior  Notes to the Company in full  satisfaction  of the  Holder's  obligation
under the  related  Forward  Purchase  Contracts,  any  accumulated  and  unpaid
interest  on such  Notes will  become  payable  by the  Company  to the  Forward
Purchase  Contract  Agent for payment to the Holder of the Equity Units to which
such Notes relate. Such payment will be made by the Company on or prior to 11:00
a.m.,  New York City time,  on the Stock  Purchase  Date in lawful  money of the
United States by certified or cashier's  check or wire  transfer in  immediately
available  funds payable to or upon the order of the Forward  Purchase  Contract
Agent. Upon the occurrence of a Last Failed Remarketing, the Company will retain
and dispose of the Pledged Notes of all Holders in  satisfaction of the Holders'
obligations  under the related  Forward  Purchase  Contracts.  The Company  will
publish  notice by means of Bloomberg and Reuters  newswires of any  Remarketing
Period  during  which no  successful  Remarketing  occurred,  such  notice to be
published  not later  than the fourth  Business  Day  following  the end of such
Remarketing  Period.  The  Company  will  cause  a  notice  of the  Last  Failed
Remarketing to be published on the fourth Business Day following the date of the
Last Failed Remarketing in an Authorized Newspaper.

     (n) In the event of a Last Failed Remarketing,  the Remarketing Agent shall
determine  the Reset  Rate that  shall  apply to the  Senior  Notes  held by the
Holders of Equity Units that elected not to participate in the  remarketing  and
Holders of Separate Notes according to the following method, provided that in no
event shall the Reset Rate exceed the maximum rate permitted by state usury laws
and other applicable laws.  After the Last Failed  Remarketing,  the Remarketing
Agent  will  take  the  average  of the  interest  rates  quoted  to it by three
nationally  recognized  investment  banks  selected  by the  Company,  which are
underwriters or dealers in debt securities  similar to the Senior Notes, that in
their judgment  reflects an accurate  market rate of interest  applicable to the
Senior Notes at that time.  Following  receipt of these quotes,  the Remarketing
Agent will have the  right,  in its sole  judgment,  to either  recalculate  the
average  based  on only two of the  quoted  interest  rates if one of the  three
quotes,  in the  Remarketing  Agent's sole  discretion,  did not reflect  market
conditions or,  alternatively,  determine a consensus among the investment banks
rather than a strict  mathematical  average by taking into  account all relevant
qualitative and quantitative  factors.  These factors may include, but shall not
limited to,  maturity of the Senior Notes,  the credit rating and credit risk of
the Company and companies of similar  industries,  the then yield to maturity of
the Senior Notes and the state of the markets for primary and secondary sales of
similar debt securities.

     (o) In accordance with DTC's normal  procedures,  on the date of settlement
of such Remarketing or the Stock Purchase Date, as applicable,  the transactions
described above with respect to each Senior Notes  remarketed in the Remarketing
shall be executed  through DTC, and the  accounts of the  respective  Depository
Participants  shall be debited and  credited  and such  remarketed  Senior Notes
delivered  by book  entry as  necessary  to effect  purchases  and sales of such
remarketed  Senior Notes.  DTC shall make payment in accordance  with its normal
procedures.

     (p) If any Holder of Senior Notes selling  Senior Notes in the  Remarketing
fails  to  deliver  such  Senior  Notes,  the  direct  or  indirect   Depository
Participant  of such  selling  Holder  and of any other  Person  who was to have
purchased  Senior Notes in the  Remarketing may deliver to any such other Person
an aggregate  principal  amount of Senior Notes that is less than the  aggregate
principal  amount of Senior  Notes that  otherwise  was to be  purchased by such
Person.  In such event, the aggregate  principal amount of Senior Notes to be so
delivered shall be determined by such direct or indirect Depository Participant,
and  delivery of such lesser  aggregate  principal  amount of Senior Notes shall
constitute good delivery.

     (q) The  Remarketing  Agent is not  obligated  to purchase any Senior Notes
that otherwise would remain unsold in the  Remarketing.  Neither the Company nor
the  Remarketing  Agent shall be obligated in any case to provide  funds to make
payment upon tender of the Senior Notes for Remarketing.

     (r) Under the Remarketing Agreement, the Company, in its capacity as issuer
of the Senior  Notes,  shall be liable for, and shall pay, any and all costs and
expenses incurred in connection with the Remarketing, other than the Remarketing
Fee.

     (s) The settlement  procedures set forth herein,  including  provisions for
payment by purchasers of the remarketed  Senior Notes in the Remarketing,  shall
be subject to  modification  to the extent  required by DTC or if the book-entry
system is no longer available for the remarketed Senior Notes at the time of the
Remarketing,  to facilitate the  Remarketing  of the remarketed  Senior Notes in
certificated  form,  and shall  provide for the  authentication  and delivery of
Senior  Notes in a principal  amount equal to the  unremarketed  portion of such
Senior  Notes.  In addition,  the  Remarketing  Agent may modify the  settlement
procedures set forth herein in order to facilitate the settlement process.


SECTION 1.7. Optional Remarketing.
- ----------------------------------

     (a) On or prior to the fourth Business Day immediately preceding either the
Remarketing Date or if applicable,  the first day of any subsequent  Remarketing
Period, but no earlier than the Interest Payment Date immediately  preceding the
last Interest  Payment Date before the Stock Purchase Date,  holders of Separate
Notes may elect to have their Separate Notes  remarketed by  Transferring  their
Separate Notes and delivering a notice of such  election,  substantially  in the
form of Exhibit C to the Pledge Agreement, to the Collateral Agent. On the third
Business Day immediately  prior to the Remarketing  Date or the first day of any
subsequent Remarketing Period, by 10:00 a.m., New York City time, the Collateral
Agent shall notify the Remarketing Agent of the number of such Separate Notes to
be remarketed.  The Collateral Agent will hold such Separate Notes in an account
separate from the  Collateral  Account.  A holder of Separate  Notes electing to
have its Separate  Notes  remarketed  will also have the right to withdraw  such
election by written notice to the Collateral Agent, substantially in the form of
Exhibit  D to the  Pledge  Agreement,  on or prior to the  fourth  Business  Day
immediately  preceding  the  applicable  Remarketing  Date or the first day of a
subsequent  Remarketing  Period,  upon which  notice the  Collateral  Agent will
return such Separate Notes to such holder.

     (b) On the third Business Day immediately preceding the Remarketing Date or
the first day of any subsequent  Remarketing Period, the Collateral Agent at the
written direction of the Remarketing Agent will deliver to the Remarketing Agent
for Remarketing all Separate Notes delivered to the Collateral Agent pursuant to
Section 4.5(d) of the Pledge  Agreement and not withdrawn  pursuant to the terms
thereof  prior to such date. If the holder of the Separate  Notes  delivers only
such notice but not the Separate Notes subject to such notice, then none of such
holder's Separate Notes shall be included in the Remarketing. Once the holder of
Separate  Notes elects to participate  in the  Remarketing,  such Separate Notes
will be remarketed in the Remarketing, unless such notice is properly withdrawn.
In accordance with Section 4.5(d) of the Pledge  Agreement,  upon the occurrence
of a Failed  Remarketing,  the  Remarketing  Agent  will  promptly  return  such
Separate  Notes to the  Collateral  Agent for redelivery to such holders of such
Separate Notes.


SECTION 1.8. Sinking Fund.
- --------------------------

     The Senior Notes shall not be entitled to any sinking fund.


SECTION 1.9. Redemption and Repurchase.
- ---------------------------------------

     Except  as  provided  in  Section  1.12,  the  Senior  Notes  shall  not be
redeemable prior to their Stated Maturity.


SECTION 1.10. Covenants.
- ------------------------

     (a) For so long as any Senior Notes of this series remain outstanding,  the
Company will not create or incur or allow any of its  subsidiaries  to create or
incur any pledge or security  interest  on any of the capital  stock of a Public
Utility  Subsidiary  held  by  the  Company  or one  of  its  subsidiaries  or a
Significant Subsidiary.

     For purposes of this covenant:

     (i)  Public Utility  Subsidiary  means, at any particular time, a direct or
          indirect  subsidiary of the Company that, as a substantial part of its
          business,  distributes  or  transmits  electric  energy  to  retail or
          wholesale customers at rates or tariffs that are regulated by either a
          state or Federal  regulatory  authority.

     (ii) Significant  Subsidiary  means,  at any  particular  time,  any direct
          subsidiary  of  the  Company  whose   consolidated   gross  assets  or
          consolidated  gross revenues  (having  regard to the Company's  direct
          beneficial  interest in the shares,  or the like, of that  subsidiary)
          represent at least 25% of the Company's  consolidated  gross assets or
          consolidated  gross  revenues  appearing  in the most  recent  audited
          financial statements of the Company as of the date of determination.

     (b) The  provisions  of  Article  Ten of the  Original  Indenture  shall be
applicable to the Senior Notes.


SECTION 1.11. Defeasance.
- -------------------------

     The provisions of Section 11.01 of the Original  Indenture  shall not apply
to the Senior Notes.


SECTION 1.12. Tax Event Redemption.
- -----------------------------------

     (a) If a Tax Event shall occur, the Company may, at its option,  redeem the
Senior  Notes in whole (but not in part) at any time at a price per Senior  Note
equal to the Redemption Price. Installments of interest on the Senior Notes that
are due and  payable  on or prior  to the date of  redemption  (the  "Tax  Event
Redemption  Date") will be payable to the Holders of the Senior Notes registered
as such on the Record Date next  preceding such Tax Event  Redemption  Date. If,
following  the  settlement of the Forward  Purchase  Contracts and following the
occurrence of a Tax Event, the Company, at its option, redeems the Senior Notes,
the  proceeds  of the  redemption  will be payable in cash to the Holders of the
Senior Notes.

     (b) If the  Company  exercises  its  option  to  redeem  the  Senior  Notes
following  the  occurrence of a Tax Event prior to the  Remarketing  Date, or if
there has not been a successful  Remarketing  prior to the Stock  Purchase Date,
the Company  shall in the notice to the Trustee  pursuant to Section 3.02 of the
Original  Indenture  specify the Redemption Price. Upon the specification of the
Redemption Price by the Company,  the Company shall appoint the Collateral Agent
to acquire  the  Treasury  Portfolio  in  consultation  with the  Company and in
accordance with the Forward Purchase  Contract  Agreement.  The Collateral Agent
shall then apply,  out of the  aggregate  Redemption  Price for the Senior Notes
that are components of Equity Units, an amount equal to the aggregate Redemption
Amount for the Senior Notes that are  components  of Equity Units to purchase on
behalf of the Holders of Equity Units the Treasury  Portfolio and promptly remit
the remaining portion, if any, of such aggregate Redemption Price to the Forward
Purchase  Contract  Agent for payment to the Holders of such Equity  Units.  The
Treasury  Portfolio  will be  substituted  for the  Pledged  Notes,  and will be
pledged  to the  Collateral  Agent in  accordance  with the terms of the  Pledge
Agreement to secure the  obligation of each Holder of an Equity Unit to purchase
the Common Stock under the Forward Purchase Contract constituting a part of such
Equity Units. Payment of the Redemption Price to Holders of Separate Notes shall
be made in cash on the Tax Event Redemption Date.

     (c) If a Tax Event  Redemption  occurs  after the  earlier of a  successful
Remarketing or the Stock Purchase Date,  payment of the Redemption Price to each
Holder of Senior  Notes shall be made by the Trustee  (subject to its receipt of
funds),  no  later  than  12:00  noon,  New York  City  time,  on the Tax  Event
Redemption  Date,  by check or wire  transfer  in  immediately  available  funds
(provided the necessary wire  instructions  have been provided to the Trustee at
least 15 days prior to the Tax Event  Redemption Date) at such place and to such
account as may be designated by each such Holder of Senior Notes,  including the
Collateral Agent. If the Trustee holds immediately available funds sufficient to
pay the Redemption Price of the Senior Notes, then, on such Tax Event Redemption
Date, such Senior Notes will cease to be Outstanding.

     (d) The Trustee  shall have no duty or liability to determine or verify the
Redemption  Price.  Notice of any redemption will be mailed at least 30 days but
not more than 60 days before the Tax Event  Redemption  Date to each  registered
Holder of the Senior Notes to be repaid at its  registered  address.  Unless the
Company defaults in payment of the Redemption  Price, on and after the Tax Event
Redemption  Date interest shall cease to accrue on the Senior Notes,  whether or
not such Senior Notes have been received by the Company, and all other rights of
the Holders in respect of the Senior Notes shall terminate and lapse (other than
the right to receive the Redemption Price upon delivery of such Senior Notes but
without interest on such Redemption Price).

SECTION 1.13. Tax Treatment.
- ----------------------------

     The Company agrees, and by acceptance of a beneficial ownership interest in
the Senior Notes,  each beneficial holder of Senior Notes will be deemed to have
agreed (1) to treat the  acquisition of an Equity Unit as the acquisition of the
Senior Note and the Forward Purchase  Contract  constituting the Equity Unit and
to allocate  the  purchase  price of the Equity Unit between the Senior Note and
the  Forward  Purchase  Contract as $50 and $0,  respectively,  (2) to treat the
Senior Notes as indebtedness  that is subject to Treas.  Reg. Sec. 1.1275-4 (the
"Contingent Payment  Regulations") for United States federal income tax purposes
and (3) to be bound by the Company's determination of the "comparable yield" and
"projected  payment  schedule,"  within the  meaning of the  Contingent  Payment
Regulations,  with respect to the Senior Notes for United States  federal income
tax purposes.  A Holder of Senior Notes may obtain the amount of original  issue
discount, issue date, yield to maturity,  comparable yield and projected payment
schedule by submitting a written  request for it to the Company at the following
address:  American  Electric Power,  Investor  Relations,  One Riverside  Plaza,
Columbus, Ohio 43215.

                                  ARTICLE TWO

                            MISCELLANEOUS PROVISIONS

SECTION 2.1. Recitals by Company.
- ---------------------------------

     The recitals in this Third  Supplemental  Indenture are made by the Company
only and not by the Trustee, and all of the provisions contained in the Original
Indenture in respect of the rights, privileges, immunities, powers and duties of
the Trustee shall be applicable in respect of the Senior Notes and of this Third
Supplemental  Indenture  as fully and with like effect as if set forth herein in
full.


SECTION 2.2. Ratification and Incorporation of Original Indenture.
- ------------------------------------------------------------------

     As supplemented  hereby, the Original Indenture is in all respects ratified
and confirmed,  and the Original Indenture and this Third Supplemental Indenture
shall be read, taken and construed as one and the same instrument.


SECTION 2.3. .Executed in Counterparts.
- ---------------------------------------

     This Third Supplemental  Indenture may be executed in several counterparts,
each of which shall be deemed to be an  original,  and such  counterparts  shall
together constitute but one and the same instrument.


SECTION 2.4.      Separability.
- -------------------------------

     In case any provisions contained in this Third Supplemental Indenture or in
any  Senior  Note shall be  invalid,  illegal or  unenforceable,  the  validity,
legality and enforceability of the remaining  provisions shall not in any way be
affected or impaired thereby.

SECTION 2.5. Governing Law.
- ---------------------------

     THIS THIRD SUPPLEMENTAL INDENTURE AND EACH SENIOR NOTE SHALL BE GOVERNED BY
AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK APPLICABLE TO
AGREEMENTS MADE OR INSTRUMENTS ENTERED INTO AND, IN EACH CASE, PERFORMED IN SAID
STATE.



<PAGE>


     IN WITNESS WHEREOF,  the parties hereto have caused this Third Supplemental
Indenture  to be duly  executed,  and  their  respective  corporate  seals to be
hereunto affixed, all as of the day and year first above written.


                             AMERICAN ELECTRIC POWER COMPANY,   INC.


                             By:   /s/ A. A. Pena
                                Name:  A. A. Pena
                                Title: Treasurer



                             THE BANK OF NEW YORK, as Trustee


                             By:      /s/ Terence Rawlins
                                Name:     Terence Rawlins
                                Title:    Vice President


<PAGE>


                                    EXHIBIT A

                               FORM OF SENIOR NOTE

                                 [Face of Note]

[UNLESS  AND  UNTIL IT IS  EXCHANGED  IN  WHOLE  OR IN PART  FOR THE  INDIVIDUAL
SECURITIES  REPRESENTED  HEREBY,  THIS GLOBAL  SECURITY  MAY NOT BE  TRANSFERRED
EXCEPT AS A WHOLE BY THE  DEPOSITORY  TRUST COMPANY OR ANY SUCCESSOR  DEPOSITARY
APPOINTED AS SUCH PURSUANT TO THE INDENTURE (THE  "DEPOSITARY")  TO A NOMINEE OF
THE  DEPOSITARY OR BY A NOMINEE OF THE  DEPOSITARY TO THE  DEPOSITARY OR ANOTHER
NOMINEE OF THE  DEPOSITARY  OR BY THE  DEPOSITARY  OR ANY SUCH NOMINEE TO SUCH A
SUCCESSOR  DEPOSITARY  OR A NOMINEE OF SUCH  SUCCESSOR  DEPOSITARY.  UNLESS THIS
GLOBAL SECURITY IS PRESENTED BY AN AUTHORIZED  REPRESENTATIVE  OF THE DEPOSITARY
TO THE COMPANY OR ITS AGENT FOR  REGISTRATION OR TRANSFER,  EXCHANGE OR PAYMENT,
AND ANY  SECURITY  ISSUED IS  REGISTERED  IN THE NAME OF THE  DEPOSITARY  OR ITS
NOMINEE OR SUCH OTHER NAME AS IS REQUESTED BY AN  AUTHORIZED  REPRESENTATIVE  OF
THE  DEPOSITARY  AND ANY PAYMENT IS MADE TO THE  DEPOSITARY OR ITS NOMINEE,  ANY
TRANSFER,  PLEDGE OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON
IS WRONGFUL SINCE THE REGISTERED OWNER HEREOF HAS AN INTEREST HEREIN.]*

CUSIP No.
ISIN No.
No. ___                                                        $_______________

                      AMERICAN ELECTRIC POWER COMPANY, INC.

                     5.75% Senior Notes Due August 16, 2007

     American  Electric  Power Company,  Inc., a corporation  duly organized and
existing  under the laws of New York (the  "Company,"  which term  includes  any
successor  corporation under the Indenture  hereinafter  referred to), for value
received,  hereby  promises to pay to [Cede & Co.]* or registered  assigns,  the
principal sum of _______________________  United States Dollars [, or such other
principal amount as shall be set forth in the Schedule of Increases or Decreases
attached  hereto,]** at the Company's Office or Agency or Office of the Agent in
The City of New York  for said  purpose,  on  August  16,  2007 in such  coin or
currency  of the United  States of  America  as at the time of payment  shall be
legal  tender for the payment of public and private  debts,  and to pay interest
thereon  from June 11, 2002 or from the next most recent date to which  interest
has been paid or duly  provided  for,  quarterly in arrears on each February 16,
May 16,  August 16 and  November 16 of each year (each such date,  an  "Interest
Payment  Date"),  commencing  on August 16, 2002, at the rate of 5.75% per annum
to, but  excluding,  the  earlier  of (i) the  settlement  date of a  successful
Remarketing  under the Forward  Purchase  Contract  Agreement  or (ii) the Stock
Purchase Date, and, thereafter,  at the Reset Rate to, but excluding, the Stated
Maturity.

- -----------------------------
*  Insert in Global Securities.
** Insert in Global Securities and Pledged Notes.

     The amount of interest so payable for any period  shall be computed (i) for
any full quarterly period on the basis of a 360-day year of twelve 30-day months
and (ii) for any period shorter than a full quarterly  period, on the basis of a
30-day month and,  for periods of less than a month,  on the basis of the actual
number of days elapsed per 30-day month. In the event that any Interest  Payment
Date is not a Business Day, then payment of the interest or principal payable on
such date will be made on the next succeeding day which is a Business Day and no
interest  shall accrue in respect of the amounts which payment is so delayed for
the period from and after such  interest  payment  date or other  payment  date,
except that, if such Business Day is in the next succeeding  calendar year, such
payment shall be made on the  immediately  preceding  Business Day, in each case
with the same force and effect as if made on such date.

     Payments of the principal of and interest on the Senior Notes shall be made
at said  Office or Agency of the  Company  or at the  Office of the Agent in The
City of New York to which  interest  on the  Senior  Notes has been paid or duly
provided for, until payment of said principal sum has been made or duly provided
for;  provided  that,  unless this Senior Note is a Senior Note issued in global
form  ("Global  Security"),  interest may be paid, at the option of the Company,
(i) by check  mailed to the  address  of the  Person  entitled  thereto  as such
address  shall appear in the Security  Register or (ii) by wire transfer at such
place and to such account at a banking  institution  in the United States as may
be  designated in writing to the Trustee at least sixteen (16) days prior to the
date for payment by the Person entitled  thereto.  The interest so payable,  and
punctually paid or duly provided for, on any Interest  Payment Date, as provided
in the Indenture,  as hereinafter defined,  shall be paid to the Person in whose
name  this  Note  (or  one or  more  Predecessor  Securities)  shall  have  been
registered  at the close of business on the Regular  Record Date with respect to
such  Interest  Payment  Date,  provided  that  interest  payable  on the Stated
Maturity or any redemption date shall be paid to the Person to whom principal is
paid.  Any such  interest  not so  punctually  paid or duly  provided  for shall
forthwith  cease to be  payable to the Holder on such  Regular  Record  Date and
shall be paid as provided in said Indenture.

     Reference is hereby made to the further  provisions of this Senior Note set
forth  herein,  which  further  provisions  shall for all purposes have the same
effect as if set forth at this place.

     Unless the  certificate of  authentication  hereon has been executed by the
Trustee  referred to herein by manual  signature,  this Senior Note shall not be
entitled to any benefit under the  Indenture or be valid or  obligatory  for any
purpose.



<PAGE>


                  IN WITNESS WHEREOF, the Company has caused this instrument to
be duly executed.


Dated: ___________________


                                  AMERICAN ELECTRIC POWER COMPANY, INC.


                                  By: _________________________________
                                      Name:
                                      Title:




                     TRUSTEE'S CERTIFICATE OF AUTHENTICATION

     This is one of the Securities of the series  designated in accordance with,
and referred to in, the within-mentioned Indenture.


Dated: ___________________

                                   THE BANK OF NEW YORK, as Trustee


                                   By: __________________________
                                       Authorized Signatory


<PAGE>


                                [Reverse of Note]


                      American Electric Power Company, Inc.

                     5.75% Senior Notes Due August 16, 2007

     This Senior Note is one of a duly  authorized  issue of  securities  of the
Company (the "Securities"),  issued and to be issued in one or more series under
an Indenture, dated as of May 1, 2001 (the "Original Indenture"),  as previously
supplemented and as to be supplemented by a third supplemental indenture,  dated
as of June  11,  2002  (the  "Third  Supplemental  Indenture"  and the  Original
Indenture,  as so supplemented,  the  "Indenture"),  between the Company and The
Bank of New York, a New York  banking  corporation,  as trustee (the  "Trustee,"
which term includes any successor trustee under the Indenture), and reference is
hereby  made  to  the  Indenture  for a  statement  of  the  respective  rights,
limitations  of rights,  duties and  immunities  thereunder of the Company,  the
Trustee and the Holders and of the terms upon which the Securities  are, and are
to be,  authenticated  and  delivered.  This  Senior  Note  is  one of a  series
designated as 5.75% Senior Notes Due August 16, 2007 of the Company (hereinafter
called the  "Senior  Notes"),  issued  under the  Original  Indenture,  which is
limited in aggregate principal amount to $300,000,000.

     Neither the  Original  Indenture  nor the Senior  Notes limit or  otherwise
restrict the amount of  indebtedness  which may be incurred or other  securities
which may be issued by the Company.  The Senior Notes issued under the Indenture
are direct,  unsecured  obligations of the Company and will mature on August 16,
2007. The Senior Notes rank on parity with all other  unsecured,  unsubordinated
indebtedness of the Company.

     The Senior Notes will bear  interest as set forth on the face hereof and in
the Third Supplemental  Indenture.  The Reset Rate will be the interest rate per
annum that is determined by the  Remarketing  Agent pursuant to the  Remarketing
Agreement as follows: (i) in connection with a successful Remarketing,  the rate
of interest that will,  when applied to the Outstanding  Notes,  enable the then
current  aggregate  market  value  of  the  Notes  to  have  a  value  equal  to
approximately,  but not less than,  100.25% of the  Remarketing  Value as of the
Remarketing Date or as of any Subsequent  Remarketing  Date, as the case may be,
or (ii)  upon the  occurrence  of a  Failed  Remarketing  the  rate of  interest
applicable  to the  Senior  Notes  initially  until  (A) the  Senior  Notes  are
successfully  remarketed pursuant to the Forward Purchase Contract Agreement and
the  Remarketing  Agreement  or (B) if the Last  Failed  Remarketing  shall have
occurred, in accordance with the method as described below.

     Notwithstanding anything herein to the contrary, the Reset Rate shall in no
event exceed the maximum rate, if any, permitted by applicable law.

     In the event of a Last  Failed  Remarketing,  the  Remarketing  Agent shall
determine  the Reset  Rate that  shall  apply to the  Senior  Notes  held by the
Holders of Equity Units that elected not to participate in the  remarketing  and
Holders of Separate  Notes  according to the  following  method.  After the Last
Failed Remarketing,  the Remarketing Agent will take the average of the interest
rates quoted to it by three nationally  recognized  investment banks selected by
the Company, which are underwriters or dealers in debt securities similar to the
Senior  Notes,  that in their  judgment  reflects  an  accurate  market  rate of
interest applicable to the Senior Notes at that time. Following receipt of these
quotes,  the  Remarketing  Agent will have the right,  in its sole judgment,  to
either recalculate the average based on only two of the quoted interest rates if
one of the three quotes,  in the Remarketing  Agent's sole  discretion,  did not
reflect market  conditions or,  alternatively,  determine a consensus  among the
investment  banks  rather  than a strict  mathematical  average  by taking  into
account all relevant  qualitative and  quantitative  factors.  These factors may
include,  but shall not limited to,  maturity  of the Senior  Notes,  the credit
rating and credit risk of the Company and companies of similar  industries,  the
then yield to  maturity  of the Senior  Notes and the state of the  markets  for
primary and secondary sales of similar debt securities.

     The Senior Notes are not redeemable  prior to maturity except pursuant to a
Tax Event in accordance with the Third  Supplemental  Indenture.  If a Tax Event
shall occur,  the Company  may, at its option,  redeem the Senior Notes in whole
(but not in part) at any time at a price per Senior Note equal to the Redemption
Price.  Installments of interest on the Senior Notes that are due and payable on
or prior to the date of redemption  will be payable to the Holders of the Senior
Notes  registered  as such at the  close of  business  on the  Record  Date next
preceding such Tax Event  Redemption  Date. If,  following the settlement of the
Forward  Purchase  Contracts and following  the  occurrence of a Tax Event,  the
Company, at its option, redeems the Senior Notes, the proceeds of the redemption
will be payable in cash to the Holders of the Senior Notes.

     The Company agrees, and by acceptance of a beneficial ownership interest in
the Senior Notes,  each beneficial holder of Senior Notes will be deemed to have
agreed (1) for United States  federal,  state and local income and franchise tax
purposes to treat the  acquisition  of an Equity Unit as the  acquisition of the
Senior Note and the Forward Purchase Contract  constituting the Equity Unit, (2)
to treat the Senior Notes as  indebtedness  that is subject to Treas.  Reg. Sec.
1.1275-4 (the "Contingent Payment Regulations") for United States federal income
tax  purposes  and  (3)  to be  bound  by  the  Company's  determination  of the
"comparable  yield" and "projected  payment schedule," within the meaning of the
Contingent  Payment  Regulations,  with  respect to the Senior  Notes for United
States  federal  income tax  purposes.  A Holder of Senior  Notes may obtain the
amount of original issue  discount,  issue date,  yield to maturity,  comparable
yield and projected  payment  schedule by submitting a written request for it to
the  Company  at  the  following  address:  American  Electric  Power,  Investor
Relations, One Riverside Plaza, Columbus, Ohio 43215.

     The Senior Notes are not entitled to any sinking fund.

     The Senior  Notes  that are a  component  of Equity  Units or that so elect
under Section 1.7 of the  Supplemental  Indenture will be subject to Remarketing
and, in the case of a Failed  Remarketing,  the Collateral Agent for the benefit
of the  Company  reserves  all of its rights as a secured  party of the  Pledged
Notes with respect thereto and, subject to applicable law and Section 5.4 of the
Forward Purchase Contract Agreement, may, among other things, permit the Company
to cause the Senior Notes to be sold or to retain and cancel such Senior  Notes,
in either  case,  in full  satisfaction  of the Holders'  obligations  under the
Forward Purchase Contracts.

     If an Event of Default  with respect to the Senior Notes shall occur and be
continuing, the principal of the Senior Notes may be declared due and payable in
the manner and with the effect provided in the Indenture.  The Senior  Indenture
provides that in certain circumstances such declaration and its consequences may
be waived by the  Holders of a majority  in  aggregate  principal  amount of the
Senior Notes then Outstanding. However, any such consent or waiver by the Holder
shall not affect any subsequent default or impair any right consequent thereon.

     The Indenture contains  provisions  permitting the Company and the Trustee,
with the  consent  of the  Holders  of not less  than a  majority  in  aggregate
principal  amount of the Securities of all series affected by such  supplemental
indenture or indentures at the time outstanding  voting as one class, as defined
in the Indenture,  to execute supplemental  indentures for the purpose of adding
any provisions to or changing in any manner or eliminating any of the provisions
of the Indenture or of any supplemental  indenture or of modifying in any manner
the rights of the Holders of the  Securities;  provided,  however,  that no such
supplemental  indenture shall (i) extend the fixed maturity of any Securities of
any series, or reduce the principal amount thereof, or reduce the rate or extend
the time of payment of interest thereon,  or reduce any premium payable upon the
redemption thereof, or reduce the amount of the principal of a Discount Security
that would be due and payable upon a declaration of acceleration of the maturity
thereof  pursuant  to the  Indenture,  without the consent of the holder of each
Senior Note then outstanding and affected;  (ii) reduce the aforesaid percentage
of Senior  Notes,  the  holders  of which are  required  to  consent to any such
supplemental indenture, or reduce the percentage of Senior Notes, the holders of
which are  required  to waive any  default  and its  consequences,  without  the
consent of the holder of each Senior Note then outstanding and affected thereby;
or (iii) modify any  provision of Section  6.01(c) of the  Indenture  (except to
increase the  percentage of principal  amount of securities  required to rescind
and annul any  declaration  of amounts due and payable under the Senior  Notes),
without  the  consent of the holder of each  Senior  Note then  outstanding  and
affected thereby. The Indenture also contains provisions  permitting the Holders
of a majority in aggregate principal amount of the Senior Notes of any series at
the time outstanding  affected  thereby,  on behalf of the Holders of the Senior
Notes of such series, to waive any past default in the performance of any of the
covenants contained in the Indenture,  or established  pursuant to the Indenture
with  respect  to such  series,  and its  consequences,  except a default in the
payment of the principal of or premium,  if any, or interest on any of the Notes
of such series. Any such consent or waiver by the registered Holder of this Note
(unless  revoked as provided in the  Indenture)  shall be conclusive and binding
upon such Holder and upon all future  Holders and owners of this Note and of any
Note issued in exchange  herefor or in place hereof  (whether by registration of
transfer  or  otherwise),  irrespective  of whether or not any  notation of such
consent or waiver is made upon this Note.

Restrictive Covenants
- ---------------------

     Limitation upon Liens of Certain Subsidiaries

     For so long as any Senior  Notes of this  series  remain  outstanding,  the
Company will not create or incur or allow any of its  subsidiaries  to create or
incur any pledge or security  interest  on any of the capital  stock of a Public
Utility  Subsidiary  held  by  the  Company  or one  of  its  subsidiaries  or a
Significant Subsidiary.

     For purposes of this covenant:

     (i)  Public Utility  Subsidiary  means, at any particular time, a direct or
          indirect  subsidiary of the Company that, as a substantial part of its
          business,  distributes  or  transmits  electric  energy  to  retail or
          wholesale customers at rates or tariffs that are regulated by either a
          state or Federal regulatory authority.

     (ii) Significant  Subsidiary  means,  at any  particular  time,  any direct
          subsidiary  of ours whose  consolidated  gross assets or  consolidated
          gross  revenues  (having  regard to the  Company's  direct  beneficial
          interest in the shares, or the like, of that subsidiary)  represent at
          least 25% of the Company's  consolidated  gross assets or consolidated
          gross  revenues   appearing  in  the  most  recent  audited  financial
          statements of the Company as of the date of determination.

         Limitation upon Mergers, Consolidations and Sale of Assets

     The  provisions of Article Ten of the Indenture  shall be applicable to the
Senior Notes of this series.

     The  Indenture  contains  provisions  for  defeasance  of  (a)  the  entire
indebtedness evidenced by this Senior Note and (b) certain restrictive covenants
upon  compliance  by the Company  with  certain  conditions  set forth  therein;
provided,  however,  Section 11.01 of the Original  Indenture shall not apply to
the Senior Notes.

     No reference  herein to the  Indenture and no provision of this Senior Note
or of the Indenture  shall alter or impair the obligation of the Company,  which
are absolute and  unconditional,  to pay the principal of (and premium,  if any)
and interest, if any, on this Senior Note at the times, places and rates, and in
the coin or currency, herein prescribed.

     The  Senior  Notes of this  series are  issuable  only in  registered  form
without coupons in minimum  denominations of $50 or any integral multiple of $50
over such minimum denomination. At the Office or Agency of the Company or at the
Office of the Agent in The City of New York  referred  to on the face hereof and
as provided in the  Indenture  and  subject to certain  limitations  therein set
forth, the Senior Notes are  exchangeable for a like aggregate  principal amount
of Senior Notes and of like tenor of a difference  authorized  denomination,  as
requested by the Holder surrendering the same.

     As provided in the Indenture and subject to certain limitations therein set
forth,  this Senior Note is transferable by the registered  holder hereof on the
Security  Register  of the  Company,  upon  surrender  of this  Senior  Note for
registration  of  transfer  at the  office or agency  of the  Company  as may be
designated by the Company  accompanied by a written instrument or instruments of
transfer in form satisfactory to the Company or the Trustee duly executed by the
registered Holder hereof or his or her attorney duly authorized in writing,  and
thereupon one or more new Senior Notes of authorized  denominations  and for the
same  aggregate  principal  amount and series  will be issued to the  designated
transferee or transferees. No service charge will be made for any such transfer,
but the  Company  may require  payment of a sum  sufficient  to cover any tax or
other governmental charge payable in relation thereto.

     Prior to due presentment of this Senior Note for  registration of transfer,
the  Company,  the Trustee and any agent of the Company or the Trustee may treat
the Person in whose name this Senior Note is  registered as the owner hereof for
all  purposes,  whether or not this  Senior  Note be  overdue  and  neither  the
Company,  the  Trustee  nor any such agent  shall be  affected  by notice to the
contrary.

     No  recourse  shall  be had  for the  payment  of the  principal  of or the
interest on this Senior  Note,  or for any claim based  hereon,  or otherwise in
respect  hereof,  or based on or in respect of the  Indenture,  or any indenture
supplement thereto, against any incorporator,  stockholder, officer or director,
past,  present or future,  as such,  of the  Company  or of any  predecessor  or
successor corporation, whether by virtue of any constitution, statute or rule of
law, or by the  enforcement of any assessment or penalty or otherwise,  all such
liability being, by the acceptance  hereof and as part of the  consideration for
the issue hereof, expressly waived and released.

     THIS  SENIOR  NOTE SHALL BE DEEMED TO BE A CONTRACT  MADE UNDER THE LAWS OF
THE STATE OF NEW YORK,  AND FOR ALL PURPOSES  SHALL BE  CONSTRUED IN  ACCORDANCE
WITH THE LAWS OF SAID STATE.

     All terms  used in this  Senior  Note (and not  otherwise  defined  in this
Senior Note) that are defined in the Indenture,  the Forward  Purchase  Contract
Agreement,  the Remarketing  Agreement or the Pledge Agreement,  as the case may
be,  shall have the  meanings  assigned  to them in the  Indenture,  the Forward
Purchase Contract Agreement,  the Remarketing Agreement or the Pledge Agreement,
as the case may be and as the context may require.

<PAGE>


     FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto

- -----------------------------------------------------------------------------.
     (please insert Social Security or other identifying number of assignee)

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

PLEASE  PRINT  OR  TYPEWRITE  NAME AND  ADDRESS,  INCLUDING  POSTAL  ZIP CODE OF
ASSIGNEE

the  within  Senior  Note  and  all  rights   thereunder,   hereby   irrevocably
constituting and appointing

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

- -----------------------------------------------------------------------------.

agent to transfer said Senior Note on the books of the Company,  with full power
of substitution in the premises.

Dated:_______________ __, ______


                                          ----------------------------


NOTICE:  The  signature  to this  assignment  must  correspond  with the name as
written  upon the face of the  within  instrument  in every  particular  without
alteration or enlargement, or any change whatever.


<PAGE>
<TABLE>
<CAPTION>


            [TO BE ATTACHED TO GLOBAL CERTIFICATES AND PLEDGED NOTES]

                       SCHEDULE OF INCREASES OR DECREASES

     The following increases or decreases in this [Global Certificate]  [Pledged
Note] have been made:

- -----------------------------------------------------------------------------------------------------------
<S>             <C>                   <C>                     <C>                    <C>
                                                               Principal amount of
                 Amount of decrease    Amount of increase in       Senior Notes
                 in principal amount    principal amount of      evidenced by the
                   of Senior Notes          Senior Notes       [Global Certificate]       Signature of
                  evidenced by the        evidenced by the        [Pledged Note]      authorized signatory
                [Global Certificate]    [Global Certificate]      following such          of Trustee or
Date               [Pledged Note]          [Pledged Note]      decrease or increase     Collateral Agent
- --------------- ---------------------- ----------------------- ---------------------- ----------------------

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</TABLE>






</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>5
<FILENAME>x4c.txt
<DESCRIPTION>(C) FORWARD PURCHASE CONTRACT
<TEXT>

<PAGE>

                                                                    EXHIBIT 4(c)














                      AMERICAN ELECTRIC POWER COMPANY, INC.


                                       AND


                              THE BANK OF NEW YORK


                       AS FORWARD PURCHASE CONTRACT AGENT


                       FORWARD PURCHASE CONTRACT AGREEMENT


                            Dated as of June 11, 2002







<PAGE>


                                Table of Contents

                                                                         .  Page

ARTICLE I. DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION........... 1
  Section 1.1   Definitions.................................................. 1
  Section 1.2   Compliance Certificates and Opinions.........................13
  Section 1.3   Form of Documents Delivered to Agent.........................14
  Section 1.4   Acts of Holders; Record Dates................................14
  Section 1.5   Notices......................................................16
  Section 1.6   Notice to Holders; Waiver....................................16
  Section 1.7   Effect of Headings and Table of Contents.....................17
  Section 1.8   Successors and Assigns.......................................17
  Section 1.9   Separability Clause..........................................17
  Section 1.10  Benefits of Agreement........................................17
  Section 1.11  Governing Law................................................17
  Section 1.12  Legal Holidays...............................................17
  Section 1.13  Counterparts.................................................18
  Section 1.14  Inspection of Agreement......................................18

ARTICLE II. CERTIFICATE FORMS................................................18
  Section 2.1   Forms of Certificates Generally..............................18
  Section 2.2   Form of Agent's Certificate of Authentication................19

ARTICLE III. THE EQUITY UNITS................................................20
  Section 3.1   Title and Terms; Denominations...............................20
  Section 3.2   Rights and Obligations Evidenced by the Certificates.........20
  Section 3.3   Execution, Authentication, Delivery and Dating...............21
  Section 3.4   Temporary Certificates.......................................22
  Section 3.5   Registration; Registration of Transfer and Exchange..........22
  Section 3.6   Book-Entry Interests.........................................24
  Section 3.7   Notices To Holders...........................................24
  Section 3.8   Appointment of Successor Clearing Agency.....................24
  Section 3.9   Definitive Certificates......................................24
  Section 3.10  Mutilated, Destroyed, Lost and Stolen Certificates...........25
  Section 3.11  Persons Deemed Owners........................................26
  Section 3.12  Cancellation.................................................27
  Section 3.13  Establishment of Stripped Units..............................27
  Section 3.14  Reestablishment of Equity Units..............................28
  Section 3.15  Transfer of Collateral Upon Occurrence of Termination Event..30
  Section 3.16  No Consent to Assumption.....................................30

ARTICLE IV. THE NOTES........................................................30
  Section 4.1   Payment of Interest; Rights to Interest Payments
                        Preserved; Notice....................................30
  Section 4.2   Notice and Voting............................................31
  Section 4.3   Tax Event Redemption.........................................32

ARTICLE V. THE FORWARD PURCHASE CONTRACTS; THE REMARKETING...................32
  Section 5.1   Purchase of Shares of Common Stock...........................32
  Section 5.2   Contract Adjustment Payments...................................
  Section 5.3   Deferral of Contract Adjustment Payments.....................35
  Section 5.4   Payment of Purchase Price; Remarketing.......................37
  Section 5.5   Issuance of Shares of Common Stock...........................42
  Section 5.6   Adjustment of Settlement Rate................................42
  Section 5.7   Notice of Adjustments and Certain Other Events...............49
  Section 5.8   Termination Event; Notice....................................50
  Section 5.9   Early Settlement.............................................50
  Section 5.10  Early Settlement Upon Merger.................................52
  Section 5.11  Charges and Taxes............................................53
  Section 5.12  No Fractional Shares.........................................54
  Section 5.13  Tax Treatment................................................54

ARTICLE VI. REMEDIES.........................................................54
  Section 6.1   Unconditional Right of Holders to Purchase Common Stock......54
  Section 6.2   Restoration of Rights and Remedies...........................55
  Section 6.3   Rights and Remedies Cumulative...............................55
  Section 6.4   Delay or Omission Not Waiver.................................55
  Section 6.5   Undertaking For Costs........................................55
  Section 6.6   Waiver of Stay or Extension Laws.............................56

ARTICLE VII. THE AGENT.......................................................56
  Section 7.1   Certain Duties, Rights and Immunities........................56
  Section 7.2   Notice of Default............................................58
  Section 7.3   Certain Rights of Agent......................................58
  Section 7.4   Not Responsible For Recitals, Etc............................59
  Section 7.5   May Hold Equity Units and Stripped Units and Other Dealings..60
  Section 7.6   Money Held In Custody........................................60
  Section 7.7   Compensation and Reimbursement...............................60
  Section 7.8   Corporate Agent Required; Eligibility........................61
  Section 7.9   Resignation and Removal; Appointment of Successor............61
  Section 7.10  Acceptance of Appointment By Successor.......................62
  Section 7.11  Merger, Conversion, Consolidation or Succession to Business..63
  Section 7.12  Preservation of Information; Communications to Holders.......63
  Section 7.13  Failure to Act...............................................63
  Section 7.14  No Obligations of Agent......................................64
  Section 7.15  Tax Compliance...............................................64

ARTICLE VIII. SUPPLEMENTAL AGREEMENTS........................................65
  Section 8.1   Supplemental Agreements Without Consent of Holders...........65
  Section 8.2   Supplemental Agreements With Consent of Holders..............65
  Section 8.3   Execution of Supplemental Agreements.........................67
  Section 8.4   Effect of Supplemental Agreements............................67
  Section 8.5   Reference to Supplemental Agreements.........................67

ARTICLE IX. CONSOLIDATION, MERGER, SALE OR CONVEYANCE........................67
  Section 9.1   Company May Consolidate, Etc., Only on Certain Terms.........67
  Section 9.2   Successor Substituted........................................68

ARTICLE X. COVENANTS.........................................................68
  Section 10.1  Performance Under Forward Purchase Contracts.................68
  Section 10.2  Maintenance of Office or Agency..............................68
  Section 10.3  Company to Reserve Common Stock..............................69
  Section 10.4  Covenants as to Common Stock.................................69
  Section 10.5  Statements of Officer of the Company as to Default...........69
  Section 10.6  ERISA........................................................70


EXHIBITS

Exhibit A...Form of Equity Units Certificate
Exhibit B...Form of Stripped Units Certificate
Exhibit C...Instruction from Forward Purchase Contract Agent to Collateral Agent
Exhibit D...Instruction to Forward Purchase Contract Agent
Exhibit E...Notice to Settle by Cash




<PAGE>

     FORWARD PURCHASE  CONTRACT  AGREEMENT,  dated as of June 11, 2002,  between
American  Electric Power Company,  Inc., a New York corporation (the "Company"),
and The Bank of New York,  a New York  banking  corporation,  acting as  Forward
Purchase  Contract Agent for the Holders of Equity Units and Stripped Units from
time to time (the "Agent").

                                    RECITALS

     The  Company  has  duly  authorized  the  execution  and  delivery  of this
Agreement and the Certificates evidencing the Equity Units and Stripped Units.

     All things  necessary  to make the  Forward  Purchase  Contracts,  when the
Certificates are executed by the Company and  authenticated,  executed on behalf
of the Holders and delivered by the Agent,  as provided in this  Agreement,  the
valid  obligations  of the Company,  and to  constitute  this  Agreement a valid
agreement of the Company, in accordance with its terms, have been done.

     For and in  consideration  of the  premises  and the purchase of the Equity
Units by the  Holders  thereof,  the  Company  and the Agent  mutually  agree as
follows:

                                   ARTICLE .
                        DEFINITIONS AND OTHER PROVISIONS
                             OF GENERAL APPLICATION

Section 1.1 Definitions.
- ------------------------

     For all purposes of this Agreement,  except as otherwise expressly provided
or unless the context otherwise requires:

          (a) the terms  defined in this Article  have the meanings  assigned to
     them in this  Article and include the plural as well as the  singular,  and
     nouns and pronouns of the masculine  gender include the feminine and neuter
     genders;

          (b) all  accounting  terms  not  otherwise  defined  herein  have  the
     meanings assigned to them in accordance with generally accepted  accounting
     principles in the United States;

          (c) the words  "herein,"  "hereof" and  "hereunder" and other words of
     similar import refer to this Agreement as a whole and not to any particular
     Article, Section or other subdivision; and

          (d) the  following  terms  have  the  meanings  given  to them in this
     Section 1.1(d):

          "Act" when used with respect to any Holder,  has the meaning specified
          in Section 1.4.

          "Affiliate"  has the same  meaning  as given to that  term in Rule 405
          under the Securities Act or any successor rule thereunder.

          "Agent"  means the Person named as the "Agent" in the first  paragraph
          of this  instrument  until a  successor  Agent  shall have become such
          pursuant  to  the  applicable   provisions  of  this  Agreement,   and
          thereafter "Agent" shall mean such Person.

          "Agent-purchased  Treasury Consideration" has the meaning specified in
          Section 5.4(d).

          "Agreement" means this instrument as originally  executed or as it may
          from time to time be supplemented or amended by one or more agreements
          supplemental hereto entered into pursuant to the applicable provisions
          hereof.

          "Applicable Market Value" has the meaning specified in Section 5.1(c).

          "Applicable  Ownership Interest" means, with respect to an Equity Unit
          and the U.S. Treasury  Securities in the Treasury  Portfolio,  (A) for
          the principal amount of a Note, a 1/20, or 5.0%,  undivided beneficial
          ownership  interest  in a $1,000  principal  or  interest  amount of a
          principal or interest strip in a U.S.  Treasury  security  included in
          such  Treasury  Portfolio  which  matures  on or  prior  to the  Stock
          Purchase Date and (B) for the scheduled  interest  Payment Date on the
          Notes  that  occurs  on the  Stock  Purchase  Date,  in the  case of a
          successful remarketing, or for each scheduled interest Payment Date on
          the Notes that occurs  after the Tax Event  Redemption  Date and on or
          before the Stock Purchase Date, in the case of a Tax Event Redemption,
          a  0.071875%  undivided  beneficial  ownership  interest  in a  $1,000
          principal  or interest  amount of a principal  or interest  strip in a
          U.S. Treasury security included in the Treasury Portfolio that matures
          on or prior to that interest Payment Date or Dates.

          "Applicants" has the meaning specified in Section 7.12(b).

          "Bankruptcy  Code" means Title 11 of the United  States  Code,  or any
          other law of the  United  States  that from  time to time  provides  a
          uniform system of bankruptcy laws.

          "Beneficial  Owner" means,  with respect to a Book-Entry  Interest,  a
          Person who is the  beneficial  owner of such  Book-Entry  Interest  as
          reflected  on the  books of the  Clearing  Agency or on the books of a
          Person maintaining an account with such Clearing Agency (directly as a
          Clearing  Agency  Participant or as an indirect  participant,  in each
          case in accordance with the rules of such Clearing Agency).

          "Board  of  Directors"  means  either  the Board of  Directors  of the
          Company or any other  committee of such Board duly  authorized  to act
          generally or in any particular respect for such Board hereunder.

          "Board  Resolution" means (i) a copy of a resolution  certified by the
          Secretary or an  Assistant  Secretary of the Company to have been duly
          adopted by the Board of  Directors  and to be in full force and effect
          on the  date of  such  certification  or  (ii) a copy  of a  unanimous
          written consent of the Board of Directors.

          "Book-Entry   Interest"  means  a  beneficial  interest  in  a  Global
          Certificate,  ownership and transfers of which shall be maintained and
          made through book entries by a Clearing Agency as described in Section
          3.6.

          "Business  Day"  means any day other  than a  Saturday,  Sunday or any
          other day on which  banking  institutions  and trust  companies in the
          State of New York or at a place of payment are  authorized or required
          by law, regulation or executive order to be closed.

          "Capital  Stock"  means  any  and all  shares,  interests,  rights  to
          purchase, warrants, options, participations or other equivalents of or
          interests  in  (however  designated,  whether  voting  or  non-voting)
          corporate stock or similar interests in other types of entities.

          "Cash Merger" has the meaning specified in Section 5.10(a).

          "Cash Settlement" has the meaning specified in Section 5.4(a).

          "Certificate"  means an Equity Units  Certificate  or a Stripped Units
          Certificate.

          "Clearing  Agency"  means an  organization  registered  as a "Clearing
          Agency"  pursuant to Section 17A of the Exchange Act that is acting as
          a  Depository  for the Equity  Units and  Stripped  Units and in whose
          name,  or in the  name of a  nominee  of that  organization,  shall be
          registered a Global  Certificate  and which shall  undertake to effect
          book-entry  transfers  and  pledges of the Equity  Units and  Stripped
          Units.

          "Clearing  Agency  Participant"  means a broker,  dealer,  bank, other
          financial  institution  or other Person for whom from time to time the
          Clearing Agency effects book-entry transfers and pledges of securities
          deposited with the Clearing Agency.

          "Closing Price" has the meaning specified in Section 5.1(c).

          "Code" means Internal Revenue Code of 1986, as amended,  and the rules
          and regulations promulgated thereunder.

          "Collateral" has the meaning specified in Section 2.1(a) of the Pledge
          Agreement.

          "Collateral  Agent" means The Bank of New York,  as  Collateral  Agent
          under the Pledge  Agreement until a successor  Collateral  Agent shall
          have become such pursuant to the  applicable  provisions of the Pledge
          Agreement, and thereafter "Collateral Agent" shall mean the Person who
          is then the Collateral Agent thereunder.

          "Collateral   Substitution"  has  the  meaning  specified  in  Section
          3.13(a).

          "Common Stock" means the common stock,  par value $6.50 per share,  of
          the Company.

          "Company"  means  the  Person  named  as the  "Company"  in the  first
          paragraph of this instrument  until a successor shall have become such
          pursuant  to  the  applicable   provisions  of  this  Agreement,   and
          thereafter "Company" shall mean such successor.

          "Constituent Person" has the meaning specified in Section 5.6(b).

          "Contract  Adjustment Payments" means, in the case of Equity Units and
          Stripped  Units,  the amount payable by the Company in respect of each
          Forward Purchase Contract  constituting a part of such Equity Units or
          Stripped Units,  equal to 3.50% per year of the Stated Amount, in each
          case  computed  (1) for any full  quarterly  period  on the basis of a
          360-day year of twelve 30-day  months,  and (2) for any period shorter
          than a full quarterly  period,  on the basis of a 30-day month and (3)
          for periods of less than a month, on the basis of the actual number of
          days elapsed per 30-day month, plus any Deferred  Contract  Adjustment
          Payments accrued pursuant to Section 5.3.

          "Corporate  Trust Office"  means the office of the Agent at which,  at
          any particular time, its corporate trust business shall be principally
          administered,  which  office at the date hereof is located at The Bank
          of New York, 101 Barclay Street, New York, New York 10286.

          "Coupon Rate" means the  percentage  rate per annum at which each Note
          will bear interest initially.

          "Current Market Price" has the meaning specified in Section 5.6(a)(8).

          "Custodial Agent" means The Bank of New York, as Custodial Agent under
          the Pledge  Agreement  until a  successor  Custodial  Agent shall have
          become  such  pursuant  to the  applicable  provisions  of the  Pledge
          Agreement,  and thereafter "Custodial Agent" shall mean the Person who
          is then the Custodial Agent thereunder.

          "Deferred Contract  Adjustment  Payments" has the meaning specified in
          Section 5.3.

          "Depository"  means,  initially,  DTC, until another  Clearing  Agency
          becomes its  successor,  and thereafter  "Depository"  shall mean such
          successor.

          "DTC" means The Depository Trust Company, the initial Clearing Agency.

          "Early Settlement" has the meaning specified in Section 5.9(a).

          "Early Settlement Amount" has the meaning specified in Section 5.9(a).

          "Early Settlement Date" has the meaning specified in Section 5.9(a).

          "Early Settlement Rate" has the meaning specified in Section 5.9(b).

          "Equity Units" means the collective rights and obligations of a Holder
          of an Equity Units Certificate in respect of a Note or the appropriate
          Treasury   Consideration  or  Applicable  Ownership  Interest  in  the
          Treasury  Portfolio,  as the case may be,  subject in each case to the
          Pledge thereof, and the related Forward Purchase Contract.

          "Equity Units Certificate"  means a certificate  evidencing the rights
          and  obligations  of a Holder in respect of the number of Equity Units
          specified on such certificate,  substantially in the form of Exhibit A
          hereto.

          "Equity  Units  Register"  and  "Equity  Units   Registrar"  have  the
          respective meanings specified in Section 3.5(a).

          "ERISA" means the Employee  Retirement Income Security Act of 1974, as
          amended.

          "Exchange  Act"  means  the  Securities  Exchange  Act of 1934 and any
          statute successor thereto,  in each case as amended from time to time,
          and the rules and regulations promulgated thereunder.

          "Expiration Date" has the meaning specified in Section 1.4(f).

          "Expiration Time" has the meaning specified in Section 5.6(a)(6).

          "Failed Remarketing" has the meaning specified in Section 5.4(e).

          "Fair  Market  Value"  with  respect to  securities  distributed  in a
          Spin-Off  means  (a) in the  case of any  Spin-Off  that  is  effected
          simultaneously with an Initial Public Offering of such securities, the
          Initial Public Offering price of those securities, and (b) in the case
          of any  other  Spin-Off,  the  average  of the  Sale  Prices  of those
          securities  over the first 10 Trading Days after the effective date of
          such Spin-Off.

          "Forward  Purchase  Contract,"  when used with  respect  to any Equity
          Units or Stripped  Units,  means the  contract  forming a part of such
          Equity Unit or Stripped  Unit and  obligating  the Company to sell and
          the Holder of such  Equity Unit or  Stripped  Unit to purchase  Common
          Stock on the terms and subject to the  conditions set forth in Article
          Five.

          "Forward Purchase Contract  Settlement Fund" has the meaning specified
          in Section 5.5.

          "Global Certificate" means a Certificate that evidences all or part of
          the Units and is  registered  in the name of a Depository or a nominee
          thereof.

          "Holder"  means the  Person in whose  name the Units  evidenced  by an
          Equity Units Certificate or a Stripped Units Certificate is registered
          in the Equity Units  Register or the Stripped Units  Register,  as the
          case may be.

          "Indenture" means the Indenture,  dated as of May 1, 2001, between the
          Company and the Trustee as supplemented  by any officers'  certificate
          or supplemental indenture.

          "Initial  Public  Offering,"  with respect to any Spin-Off,  means the
          first  time  securities  of the same  class or type as the  securities
          being  distributed in the Spin-Off are bone fide offered to the public
          for cash.

          "Issuer  Order" or "Issuer  Request"  means a written order or request
          signed in the name of the Company by the Chief Executive Officer,  the
          Chief  Financial  Officer,  the  President,  any  Vice-President,  the
          Treasurer,  any  Assistant  Treasurer,  the Secretary or any Assistant
          Secretary  (or other  officer  performing  similar  functions)  of the
          Company and delivered to the Agent.

          "Last  Failed  Remarketing"  has  the  meaning  specified  in  Section
          5.4(e)(i).

          "Merger Early Settlement" has the meaning specified in Section 5.10.

          "Merger Early Settlement  Amount" has the meaning specified in Section
          5.10.

          "Merger Early  Settlement  Date" has the meaning  specified in Section
          5.10.

          "Non-electing Share" has the meaning specified in Section 5.6(b).

          "Notes"  means the series of senior  debt  securities  of the  Company
          designated  the 5.75% Senior  Notes Due August 16, 2007,  to be issued
          under the Indenture.

          "NYSE" has the meaning specified in Section 5.1(c).

          "Office  of the Agent in The City of New York"  means an office  where
          Certificates may be presented or surrendered for acquisition of shares
          of Common  Stock,  transfer or exchange,  Notes may be  presented  for
          payment or surrendered for transfer or exchange, and where notices and
          demands to or upon the Company in respect of Units may be served, such
          office being located  initially at 101 Barclay  Street,  New York, New
          York 10286.

          "Officer's  Certificate"  means  a  certificate  signed  by the  Chief
          Executive  Officer,  the Chief Financial Officer,  the President,  any
          Vice-President,  the Treasurer, any Assistant Treasurer, the Secretary
          or any  Assistant  Secretary  (or  other  officer  performing  similar
          functions) of the Company and delivered to the Agent.

          "Opinion  of  Counsel"  means an opinion  in  writing  signed by legal
          counsel,  who may be an  employee  of or counsel to the  Company or an
          Affiliate of the Company.

          "Opt-out Treasury  Consideration" has the meaning specified in Section
          5.4(g).

          "Outstanding Units" means, as of the date of determination, all Equity
          Units  or  Stripped  Units  evidenced  by   Certificates   theretofore
          authenticated, executed and delivered under this Agreement, except:

          (i)  If a Termination  Event has occurred,  (A) Stripped Units and (B)
               Equity  Units  for  which  the  related  Note or the  appropriate
               Treasury  Consideration or Applicable  Ownership  Interest in the
               Treasury  Portfolio,  as the  case may be,  has been  theretofore
               deposited  with the Agent in trust for the Holders of such Equity
               Units;

          (ii) Equity  Units  and  Stripped  Units   evidenced  by  Certificates
               theretofore  cancelled by the Agent or delivered to the Agent for
               cancellation  or deemed  cancelled  pursuant to the provisions of
               this Agreement; and

          (iii)Equity Units and Stripped  Units  evidenced  by  Certificates  in
               exchange  for or in lieu of which  other  Certificates  have been
               authenticated,  executed  on behalf of the Holder  and  delivered
               pursuant to this  Agreement,  other than any such  Certificate in
               respect of which  there  shall have been  presented  to the Agent
               proof  satisfactory to it that such Certificate is held by a bona
               fide  purchaser in whose hands the Equity Units or Stripped Units
               evidenced  by  such  Certificate  are  valid  obligations  of the
               Company;

          provided,  that in  determining  whether the Holders of the  requisite
          number of the Equity  Units or Stripped  Units have given any request,
          demand, authorization, direction, notice, consent or waiver hereunder,
          Equity Units or Stripped  Units owned by the Company or any  Affiliate
          of the Company shall be disregarded  and deemed not to be outstanding,
          except that,  in  determining  whether the Agent shall be protected in
          relying  upon  any such  request,  demand,  authorization,  direction,
          notice, consent or waiver, only Equity Units or Stripped Units which a
          Responsible  Officer of the Agent  actually knows to be so owned shall
          be so disregarded.  Equity Units or Stripped Units so owned which have
          been pledged in good faith may be regarded as Outstanding Units if the
          pledgee  establishes  to the  satisfaction  of the Agent the pledgee's
          right so to act with  respect to such Equity  Units or Stripped  Units
          and  that the  pledgee  is not the  Company  or any  Affiliate  of the
          Company.

          "Payment  Date" means each February 16, May 16, August 16 and November
          16, commencing August 16, 2002.

          "Person" means any individual, corporation, limited liability company,
          partnership,  joint venture, association,  joint-stock company, trust,
          unincorporated  organization  or government or any agency or political
          subdivision thereof.

          "Plan"  means an employee  benefit  plan that is subject to Title I of
          ERISA, a plan, individual retirement account or other arrangement that
          is  subject  to  Section  4975 of the Code or any  similar  law or any
          entity whose underlying assets are considered to include "plan assets"
          of any such plan, account or arrangement.

          "Pledge" means the pledge under the Pledge Agreement of the Notes, the
          Treasury  Securities  or the  appropriate  Treasury  Consideration  or
          Applicable Ownership Interest in the Treasury Portfolio,  in each case
          constituting a part of the Equity Units or Stripped  Units,  property,
          cash,  securities,  financial assets and security  entitlements of the
          Collateral Account (as defined in Section 1.1 of the Pledge Agreement)
          and any proceeds of any of the foregoing.

          "Pledge  Agreement" means the Pledge  Agreement,  dated as of the date
          hereof, by and among the Company,  the Collateral Agent, the Custodial
          Agent,  the Securities  Intermediary  and the Agent, on its own behalf
          and as  attorney-in-fact  for  the  Holders  from  time to time of the
          Equity Units and Stripped Units.

          "Pledged Applicable  Ownership Interest in the Treasury Portfolio" has
          the meaning specified in Section 2.1(c) of the Pledge Agreement.

          "Pledged  Notes" has the meaning  specified  in Section  2.1(c) of the
          Pledge Agreement.

          "Pledged Treasury  Consideration" has the meaning specified in Section
          2.1(c) of the Pledge Agreement.

          "Pledged  Treasury  Securities"  has the meaning  specified in Section
          2.1(c) of the Pledge Agreement.

          "Predecessor Certificate" means a Predecessor Equity Units Certificate
          or a Predecessor Stripped Units Certificate.

          "Predecessor  Equity Units Certificate" of any particular Equity Units
          Certificate means every previous Equity Units  Certificate  evidencing
          all or a portion of the rights and  obligations of the Company and the
          Holder under the Equity Units evidenced thereby; and, for the purposes
          of this definition,  any Equity Units  Certificate  authenticated  and
          delivered  under  Section  3.10  in  exchange  for  or  in  lieu  of a
          mutilated, destroyed, lost or stolen Equity Units Certificate shall be
          deemed to evidence the same rights and  obligations of the Company and
          the Holder as the  mutilated,  destroyed,  lost or stolen Equity Units
          Certificate.

          "Predecessor  Stripped Units  Certificate" of any particular  Stripped
          Units  Certificate  means every previous  Stripped  Units  Certificate
          evidencing  all or a portion  of the  rights  and  obligations  of the
          Company and the Holder under the  Stripped  Units  evidenced  thereby;
          and,  for  the  purposes  of  this  definition,   any  Stripped  Units
          Certificate authenticated and delivered under Section 3.10 in exchange
          for or in lieu of a  mutilated,  destroyed,  lost or  stolen  Stripped
          Units  Certificate  shall be deemed to  evidence  the same  rights and
          obligations of the Company and the Holder as the mutilated, destroyed,
          lost or stolen Stripped Units Certificate.

          "Purchase Price" has the meaning specified in Section 5.1(a).

          "Purchased Shares" has the meaning specified in Section 5.6(a)(6).

          "Quotation  Agent" means J.P. Morgan  Securities Inc. or its successor
          or any other  primary U.S.  government  securities  dealer in New York
          City selected by the Company.

          "Record Date" for the distribution  payable on any Payment Date means,
          as to any Global  Certificate,  the Business Day next  preceding  such
          Payment Date, and as to any other Certificate,  the 15th day preceding
          such Payment Date.

          "Redemption  Amount" means,  (A) in the case of a Tax Event Redemption
          occurring  prior to the  earlier of a  successful  remarketing  of the
          Notes or the Stock Purchase Date, for each Note the product of (i) the
          Stated Amount of such Note and (ii) a fraction whose  numerator is the
          applicable  Treasury Portfolio Purchase Price and whose denominator is
          the aggregate  principal amount of Notes  outstanding on the Tax Event
          Redemption  Date,  and  (B)  in the  case  of a Tax  Event  Redemption
          occurring  after the earlier of a successful  remarketing of the Notes
          or the Stock  Purchase  Date,  for each Note the Stated  Amount of the
          Note.

          "Redemption  Price" means the  redemption  price per Note equal to the
          Redemption Amount.

          "Register"  means the Equity Units  Register  and the  Stripped  Units
          Register, as applicable.

          "Registrar"  means the Equity Units  Registrar and the Stripped  Units
          Registrar, as applicable.

          "Remarketing  Agent" means  Salomon Smith Barney Inc. or its successor
          under the Remarketing Agreement.

          "Remarketing Agreement" means the Remarketing Agreement dated June 11,
          2002 by and among the Company, the Remarketing Agent and the Agent.

          "Remarketing  Date" means the third  Business  Day  preceding  May 16,
          2005.

          "Remarketing Fee" has the meaning specified in Section 5.4(d).

          "Remarketing  Period" means the three Business Day period either:  (i)
          beginning on the Remarketing Date and ending after the two immediately
          following  Business Days;  (ii)  immediately  preceding June 16, 2005;
          (iii)  immediately  preceding  July  16,  2005;  or  (iv)  immediately
          preceding August 12, 2005.

          "Remarketing Value" means

          (1)  the value at the Remarketing  Date or any Subsequent  Remarketing
               Date, as the case may be, of either (a) U.S. Treasury  securities
               that will pay,  on or prior to the  Payment  Date  falling on the
               Stock  Purchase  Date,  an amount of cash equal to the  aggregate
               interest  payment that is scheduled to be payable on that Payment
               Date, on (x) the Notes which are included in Equity Units and are
               participating in the remarketing and (y) the Separate Notes which
               are to be  remarketed  pursuant  to Section  4.5(d) of the Pledge
               Agreement and Section 1.6 of the Supplemental Indenture, assuming
               for that purpose that the interest  rate on the Notes is equal to
               the Coupon Rate,  if the  remarketing  occurs prior to the fourth
               Business Day preceding the Stock  Purchase Date, or (b) an amount
               of cash equal to the aggregate interest payment that is scheduled
               to be payable on that  Payment  Date,  on (x) the Notes which are
               included in Equity Units and are participating in the remarketing
               and (y) the Separate Notes which are to be remarketed pursuant to
               Section 4.5(d) of the Pledge Agreement, assuming for that purpose
               that the interest  rate on the Notes is equal to the Coupon Rate,
               if the  remarketing  occurs on or after the fourth  Business  Day
               preceding the Stock Purchase Date; and

          (2)  the value at the Remarketing  Date or any Subsequent  Remarketing
               Date, as the case may be, of either (a) U.S. Treasury  securities
               that will pay, on or prior to the Stock  Purchase Date, an amount
               of cash  equal to the Stated  Amount of (x) such Notes  which are
               included in Equity Units and are participating in the remarketing
               and (y) the Separate Notes which are to be remarketed pursuant to
               Section  4.5(d) of the Pledge  Agreement  and  Section 1.6 of the
               Supplemental  Indenture,  if the remarketing  occurs prior to the
               fourth  Business Day preceding the Stock Purchase Date, or (b) an
               amount of cash equal to the Stated Amount of (x) such Notes which
               are  included  in  Equity  Units  and  are  participating  in the
               remarketing and (y) the Separate Notes which are to be remarketed
               pursuant  to  Section  4.5(d)  of the  Pledge  Agreement,  if the
               remarketing  occurs on or after the fourth Business Day preceding
               the Stock Purchase Date

          provided  that  for  purposes  of  clauses  (1)  and  (2)  above,  the
          Remarketing  Value shall be calculated on the assumptions that (x) the
          U.S. Treasury  securities are highly liquid and mature on or within 35
          days prior to the Stock  Purchase Date, as determined in good faith by
          the Remarketing  Agent in a manner intended to minimize the cash value
          of the U.S. Treasury securities,  and (y) the U.S. Treasury securities
          are valued based on the ask-side price of the U.S. Treasury securities
          at a time  between  9:00 a.m.  and  11:00  a.m.,  New York City  time,
          selected by the  Remarketing  Agent,  on the  Remarketing  Date or any
          Subsequent  Remarketing  Date,  as the case may be, as determined on a
          third-day  settlement basis by reasonable and customary means selected
          in good faith by the Remarketing  Agent, plus accrued interest to that
          date.

          "Reorganization Event" has the meaning specified in Section 5.6(b).

          "Reset Rate" has the meaning specified in Section 5.4(c).

          "Responsible  Officer" means, when used with respect to the Agent, any
          officer  within the  corporate  trust  department of the Agent (or any
          successor of the Agent),  including any Vice-President,  any assistant
          Vice-President,  any assistant secretary, any assistant treasurer, any
          trust  officer,  any senior trust  officer or any other officer of the
          Agent who customarily performs functions similar to those performed by
          the Persons who at the time shall be such officers,  respectively,  or
          to whom  any  corporate  trust  matter  is  referred  because  of such
          Person's  knowledge of and familiarity with the particular subject and
          who, in each of the above cases, shall have direct  responsibility for
          the administration of this Agreement.

          "Sale Price" of the Common Stock or any  securities  distributed  in a
          Spin-Off,  as the case may be, on any  Trading  Day means the  closing
          sale price per share (or if no closing  sale  price is  reported,  the
          average  of the bid and  asked  prices  or, if more than one in either
          case,  the average of the average bid and the average asked prices) on
          such  Trading  Day as  reported  in  composite  transactions  for  the
          principal U.S.  securities  exchange on which the Common Stock or such
          securities  are traded or, if the Common Stock or such  securities are
          not listed on a U.S.  national or  regional  securities  exchange,  as
          reported by NASDAQ.

          "Securities  Act" means the  Securities  Act of 1933,  and any statute
          successor thereto,  in each case as amended from time to time, and the
          rules and regulations promulgated thereunder.

          "Securities  Intermediary" means The Bank of New York, in its capacity
          as securities  intermediary under the Pledge Agreement,  together with
          its successors in such capacity.

          "Separate  Notes" has the  meaning  specified  in  Section  1.1 of the
          Pledge Agreement.

          "Settlement  Date"  means any Early  Settlement  Date or Merger  Early
          Settlement Date or the Stock Purchase Date.

          "Settlement Rate" has the meaning specified in Section 5.1(a).

          "Spin-Off" means a dividend or other distribution of shares of Capital
          Stock of any class or  series,  or  similar  equity  interests,  of or
          relating to a subsidiary or other business unit of the Company.

          "Stated  Amount" means,  with respect to any one Note,  Equity Unit or
          Stripped Unit, $50.

          "Stock Purchase Date" means August 16, 2005.

          "Stripped  Units" means the  collective  rights and  obligations  of a
          holder of a Stripped Units  Certificate in respect of a 1/20 undivided
          beneficial  interest in a Treasury  Security,  subject in each case to
          the Pledge thereof, and the related Forward Purchase Contract.

          "Stripped Units Certificate" means a certificate evidencing the rights
          and obligations of a Holder in respect of the number of Stripped Units
          specified on such certificate,  substantially in the form of Exhibit B
          hereto.

          "Stripped  Units  Register" and "Stripped  Units  Registrar"  have the
          respective meanings specified in Section 3.5(a).

          "Subsequent  Remarketing  Date" means,  provided there has been one or
          more Failed Remarketings,  the date on which the Remarketing Agent has
          consummated  a remarketing  in accordance  with Section 5.4 hereof and
          Section 1.6 of the Indenture,  such date to be no later than the third
          Business Day immediately preceding the Stock Purchase Date.

          "Supplemental  Indenture"  means a supplemental  indenture dated as of
          June 11,  2002,  between the Company and the Trustee to the  indenture
          dated as of May 1, 2001, between the Company and the Trustee.

          "Tax  Event"  means  the  receipt  by the  Company  of an  opinion  of
          nationally  recognized  independent  tax counsel  experienced  in such
          matters,  which may be Simpson Thacher & Bartlett,  to the effect that
          there is more than an insubstantial  risk that interest payable by the
          Company on the Notes would not be deductible,  in whole or in part, by
          the Company for United States federal income tax purposes, as a result
          of (a) any amendment to, or change  (including any announced  proposed
          change)  in, the laws (or any  regulations  thereunder)  of the United
          States or any political  subdivision  or taxing  authority  thereof or
          therein  affecting  taxation,  (b) any  amendment  to or  change in an
          official  interpretation or application of such laws or regulations by
          any  legislative  body,  court,   governmental  agency  or  regulatory
          authority or (c) any interpretation or pronouncement that provides for
          a position with respect to such laws or regulations  that differs from
          the generally  accepted  position on June 11, 2002,  which  amendment,
          change or proposed  change is  effective  or which  interpretation  or
          pronouncement is announced on or after June 11, 2002.

          "Tax  Event  Redemption"  means,  if a  Tax  Event  shall  occur,  the
          redemption  of the Notes,  at the option of the Company,  in whole but
          not in part,  on not less than 30 days' nor more than 60 days' written
          notice.

          "Tax  Event  Redemption  Date"  means the date upon  which a Tax Event
          Redemption is to occur.

          "Termination  Date"  means the date,  if any,  on which a  Termination
          Event occurs.

          "Termination  Event"  means  the  occurrence  of any of the  following
          events, at any time on or prior to the Stock Purchase Date:

          (i)  the entry by a court having competent jurisdiction of:

               (a)  a decree or order for relief in respect of the Company in an
                    involuntary  proceeding  under  any  applicable  bankruptcy,
                    insolvency,  reorganization or other similar law or a decree
                    or order adjudging the Company to be insolvent, or approving
                    a petition seeking reorganization,  arrangement,  adjustment
                    or composition of the Company and such decree or order shall
                    remain unstayed and in effect for a period of 60 consecutive
                    days; or

               (b)  a final and  non-appealable  order  appointing  a custodian,
                    receiver,  liquidator,  assignee,  trustee or other  similar
                    official  of the Company or of any  substantial  part of the
                    property  of  the  Company   ordering   the  winding  up  or
                    liquidation of the affairs of the Company; or

          (ii) the  commencement by the Company of a voluntary  proceeding under
               any applicable  bankruptcy,  insolvency,  reorganization or other
               similar  law  or  of  a  voluntary   proceeding   seeking  to  be
               adjudicated  insolvent or the consent by the Company to the entry
               of a decree or order  for  relief  in an  involuntary  proceeding
               under any applicable  bankruptcy,  insolvency,  reorganization or
               other  similar  law or to  the  commencement  of  any  insolvency
               proceedings  against  it,  or the  filling  by the  Company  of a
               petition  or answer or  consent  seeking  organization  or relief
               under any  applicable  law,  or the consent by the Company to the
               filing  of  such  petition  or to the  appointment  of or  taking
               possession  by  a  custodian,  receiver,  liquidator,   assignee,
               trustee or similar official of the or any substantial part of the
               property  of the  Company  or the  making  by the  Company  of an
               assignment  for  the  benefit  of  creditors,  or the  taking  of
               corporate action by the Company or any in furtherance of any such
               action.

          "Threshold  Appreciation  Price" has the meaning  specified in Section
          5.1(a)(i).

          "TIA" means the Trust Indenture Act of 1939, and any statute successor
          thereto,  in each case as amended from time to time, and the rules and
          regulations promulgated thereunder.

          "Trading Day" has the meaning specified in Section 5.1(c).

          "Transaction Documents" has the meaning specified in Section 7.1(a).

          "Treasury    Consideration"   means   the   Agent-purchased   Treasury
          Consideration or the Opt-out Treasury Consideration.

          "Treasury Portfolio" means: (i) if a Tax Event Redemption occurs prior
          to a successful remarketing of the Notes or the Stock Purchase Date, a
          portfolio  of  zero-coupon  U.S.  Treasury  Securities  consisting  of
          principal or interest strips of U.S.  Treasury  Securities that mature
          on or prior to the Stock Purchase Date in an aggregate amount equal to
          the  aggregate  principal  amount of the Notes  included in the Equity
          Units on the Tax Event  Redemption  Date  and,  with  respect  to each
          scheduled interest Payment Date on the Notes that occurs after the Tax
          Event  Redemption  Date and on or  before  the  Stock  Purchase  Date,
          interest or principal strips of U.S.  Treasury  Securities that mature
          on or prior to such Payment  Date in an aggregate  amount equal to the
          aggregate  interest  payment  that  would  be  due  on  the  aggregate
          principal  amount of the Notes  included  in the Equity  Units on such
          Payment Date if the  interest  rate of the Notes were not reset on the
          applicable   Remarketing   Date,  and  (ii)  solely  for  purposes  of
          determining the Treasury Portfolio Purchase Price in the case of a Tax
          Event  Redemption Date occurring prior to a successful  remarketing of
          the  Notes,  a  portfolio  of  zero-coupon  U.S.  Treasury  Securities
          consisting of principal or interest strips of U.S. Treasury Securities
          that  mature on or prior to the Stock  Purchase  Date in an  aggregate
          amount  equal  to  the  aggregate   principal   amount  of  the  Notes
          outstanding on the Tax Event  Redemption Date and with respect to each
          scheduled  interest Payment Date on the Notes  outstanding that occurs
          after  the Tax  Event  Redemption  Date  and on or  before  the  Stock
          Purchase  Date,   interest  or  principal  strips  of  U.S.   Treasury
          Securities that mature on or prior to such interest Payment Date in an
          aggregate amount equal to the aggregate interest payment that would be
          due on the aggregate  principal amount of the Notes outstanding on the
          Tax Event Redemption Date.

          "Treasury  Portfolio  Purchase Price" means the lowest aggregate price
          quoted by a primary U.S. government securities dealer in New York City
          to the Quotation Agent on the third Business Day immediately preceding
          the Tax  Event  Redemption  Date  for  the  purchase  of the  Treasury
          Portfolio for settlement on the Tax Event Redemption Date.

          "Treasury  Security" means a zero-coupon U.S. Treasury security (CUSIP
          Number 912803AG8)  maturing on August 15, 2005 that will pay $1,000 on
          such maturity date.

          "Trustee" means The Bank of New York, a New York banking  corporation,
          as trustee under the Indenture, or any successor thereto.

          "Underwriting  Agreement" means the Underwriting Agreement relating to
          the  Equity  Units  dated June 5, 2002  between  the  Company  and the
          underwriters named therein.

          "Vice-President"  means any vice-president,  whether or not designated
          by a number  or a word or  words  added  before  or  after  the  title
          "vice-president."


Section 1.2 Compliance Certificates and Opinions.
- -------------------------------------------------

     Except  as  otherwise  expressly  provided  by  this  Agreement,  upon  any
application  or request by the Company to the Agent to take any action under any
provision of this Agreement, the Company shall furnish to the Agent an Officer's
Certificate stating that all conditions precedent,  if any, provided for in this
Agreement  relating  to the  proposed  action  have been  complied  with and, if
requested by the Agent,  an Opinion of Counsel  stating  that, in the opinion of
such counsel,  all such conditions  precedent,  if any, have been complied with,
except  that in the case of any such  application  or  request  as to which  the
furnishing of such documents is  specifically  required by any provision of this
Agreement  relating to such  particular  application  or request,  no additional
certificate or opinion need be furnished.

     Every certificate or opinion with respect to compliance with a condition or
covenant  provided for in this Agreement  (other than the Officer's  Certificate
provided for in Section 10.5) shall include:

          (a) a  statement  that the  individual  signing  such  certificate  or
     opinion has read such  covenant or  condition  and the  definitions  herein
     relating thereto;

          (b) a brief statement as to the nature and scope of the examination or
     investigation  upon which the  statements  or  opinions  contained  in such
     certificate or opinion are based;

          (c) a statement that, in the opinion of such individual, he or she has
     made such  examination  or  investigation  as is  necessary  to enable such
     individual  to  express  an  informed  opinion  as to  whether  or not such
     covenant or condition has been complied with; and

          (d) a statement as to whether, in the opinion of such individual, such
     condition or covenant has been complied with.


Section 1.3 Form of Documents Delivered to Agent.
- -------------------------------------------------

          (a) In any case where several matters are required to be certified by,
     or covered by an opinion of, any specified Person, it is not necessary that
     all such  matters be  certified  by, or covered by the opinion of, only one
     such Person,  or that they be so certified or covered by only one document,
     but one such  Person may  certify or give an opinion  with  respect to some
     matters  and one or more other such  Persons as to other  matters,  and any
     such  Person may  certify  or give an opinion as to such  matters in one or
     several documents.

          (b) Any  certificate  or opinion of an officer of the  Company  may be
     based,  insofar as it  relates  to legal  matters,  upon a  certificate  or
     opinion of, or representations  by, counsel,  unless such officer knows, or
     in the exercise of reasonable  care should know,  that the  certificate  or
     opinion  or  representations  with  respect to the  matters  upon which his
     certificate  or opinion is based are  erroneous.  Any such  certificate  or
     Opinion of Counsel may be based,  insofar as it relates to factual matters,
     upon a  certificate  or opinion  of, or  representations  by, an officer or
     officers of the Company stating that the  information  with respect to such
     factual  matters is in the  possession  of the Company  unless such counsel
     knows,  or in the  exercise  of  reasonable  care  should  know,  that  the
     certificate or opinion or representations  with respect to such matters are
     erroneous.

     Where  any  Person  is  required  to  make,  give  or  execute  two or more
applications,  requests, consents,  certificates,  statements, opinions or other
instruments  under this Agreement,  they may, but need not, be consolidated  and
form one instrument.


Section 1.4 Acts of Holders; Record Dates.
- ------------------------------------------

          (a) Any request, demand,  authorization,  direction,  notice, consent,
     waiver or other action  provided by this  Agreement to be given or taken by
     Holders may be  embodied in and  evidenced  by one or more  instruments  of
     substantially similar tenor signed by such Holders in person or by an agent
     of such Holders duly appointed in writing;  and, except as herein otherwise
     expressly provided, such action shall become effective when such instrument
     or instruments are delivered to the Agent and, where it is hereby expressly
     required,  to the Company.  Such instrument or instruments  (and the action
     embodied therein and evidenced thereby) are herein sometimes referred to as
     the "Act" of the Holders signing such  instrument or instruments.  Proof of
     execution of any such instrument or of a writing  appointing any such agent
     shall be  sufficient  for any  purpose of this  Agreement  and  (subject to
     Section 7.1)  conclusive in favor of the Agent and the Company,  if made in
     the manner provided in this Section.

          (b) The fact  and  date of the  execution  by any  Person  of any such
     instrument  or writing  may be proved in any manner  which the Agent  deems
     sufficient.

          (c) The ownership of Equity Units or Stripped Units shall be proved by
     the Equity Units Register or the Stripped Units  Register,  as the case may
     be.

          (d) Any request, demand,  authorization,  direction,  notice, consent,
     waiver  or other Act of the  Holder of any  Certificate  shall  bind  every
     future Holder of the same  Certificate and the Holder of every  Certificate
     issued upon the registration of transfer thereof or in exchange therefor or
     in lieu thereof in respect of anything done, omitted or suffered to be done
     by the Agent or the Company in reliance thereon, whether or not notation of
     such action is made upon such Certificate.

          (e) The  Company  may set any day as a record  date for the purpose of
     determining the Holders of Outstanding Units entitled to give, make or take
     any request, demand,  authorization,  direction, notice, consent, waiver or
     other action  provided or permitted by this Agreement to be given,  made or
     taken by Holders of Equity Units and Stripped  Units. If any record date is
     set pursuant to this  paragraph,  the Holders of the  Outstanding  Units on
     such  record  date,  and no other  Holders,  shall be  entitled to take the
     relevant  action with respect to the Equity Units or the Stripped Units, as
     the case may be,  whether or not such  Holders  remain  Holders  after such
     record date;  provided  that no such action  shall be  effective  hereunder
     unless taken on or prior to the  applicable  Expiration  Date by Holders of
     the requisite number of Outstanding  Units on such record date.  Nothing in
     this paragraph shall be construed to prevent the Company from setting a new
     record date for any action for which a record date has previously  been set
     pursuant to this paragraph  (whereupon the record date previously set shall
     automatically  and with no action  by any  Person  be  cancelled  and of no
     effect),  and  nothing  in this  paragraph  shall be  construed  to  render
     ineffective  any  action  taken  by  Holders  of the  requisite  number  of
     Outstanding  Units on the date such  action is  taken.  Promptly  after any
     record date is set  pursuant to this  paragraph,  the  Company,  at its own
     expense,  shall cause  notice of such record date,  the proposed  action by
     Holders  and the  applicable  Expiration  Date to be given to the  Agent in
     writing and to each Holder of Equity Units and Stripped Units in the manner
     set forth in Section 1.6.

          (f) With respect to any record date set pursuant to this Section,  the
     Company may  designate any date as the  "Expiration  Date" and from time to
     time may change the Expiration  Date to any earlier or later day;  provided
     that no such change  shall be effective  unless  notice of the proposed new
     Expiration  Date is given to the Agent in  writing,  and to each  Holder of
     Equity Units and Stripped  Units in the manner set forth in Section 1.6, on
     or prior to the existing  Expiration  Date.  If an  Expiration  Date is not
     designated  with respect to any record date set  pursuant to this  Section,
     the  Company  shall be deemed to have  initially  designated  the 180th day
     after such record date as the Expiration Date with respect thereto, subject
     to its right to change the Expiration  Date as provided in this  paragraph.
     Notwithstanding  the foregoing,  no Expiration Date shall be later than the
     180th day after the applicable record date.

Section 1.5 Notices.
- --------------------

     Any request, demand,  authorization,  direction, notice, consent, waiver or
Act of Holders or other  document  provided or permitted by this Agreement to be
made upon, given or furnished to, or filed with:

          (a) the Agent by any Holder or by the Company shall be sufficient  for
     every purpose  hereunder  (unless  otherwise herein expressly  provided) if
     made,  given,  furnished  or filed in  writing  and  personally  delivered,
     mailed,  first-class postage prepaid,  telecopied or delivered by overnight
     air courier  guaranteeing  next day  delivery,  to the Agent at 101 Barclay
     Street,  New  York,  New  York  10286,  telecopy  number:  (212)  328-8243,
     Attention: Corporate Trust Department, or at any other address furnished in
     writing by the Agent to the Holders and the Company; or

          (b) the Company by the Agent or by any Holder shall be sufficient  for
     every purpose  hereunder  (unless  otherwise herein expressly  provided) if
     made,  given,  furnished  or filed in  writing  and  personally  delivered,
     mailed,  first-class postage prepaid,  telecopied or delivered by overnight
     air  courier  guaranteeing  next day  delivery,  to the Company at American
     Electric  Power Company,  Inc., 1 Riverside  Plaza,  Columbus,  Ohio 43215,
     telecopy number:  (614) 223-1687,  Attention:  General  Counsel,  or at any
     other  address  furnished  in writing  to the Agent and the  Holders by the
     Company; or

          (c) the Collateral Agent by the Agent, the Company or any Holder shall
     be  sufficient  for  every  purpose   hereunder  (unless  otherwise  herein
     expressly  provided)  if made,  given,  furnished  or filed in writing  and
     personally delivered,  mailed,  first-class postage prepaid,  telecopied or
     delivered  by  overnight  air  courier   guaranteeing  next  day  delivery,
     addressed to the Collateral Agent at 101 Barclay Street, New York, New York
     10286,  telecopy  number:  (212)  328-8243,   Attention:   Corporate  Trust
     Department,  or at any other address furnished in writing by the Collateral
     Agent to the Agent, the Company and the Holders; or

          (d) the Trustee by the Company shall be  sufficient  for every purpose
     hereunder  (unless  otherwise  herein expressly  provided) if made,  given,
     furnished or filed in writing and personally delivered, mailed, first-class
     postage   prepaid,   telecopied  or  delivered  by  overnight  air  courier
     guaranteeing next day delivery, addressed to the Trustee at The Bank of New
     York, 101 Barclay Street, New York, New York 10286,  telecopy number: (212)
     328-8243,  Attention:  Corporate Trust Department,  or at any other address
     furnished in writing by the Trustee to the Company.


Section 1.6 Notice to Holders; Waiver.
- --------------------------------------

          (a) Where this Agreement  provides for notice to Holders of any event,
     such notice shall be sufficiently  given (unless otherwise herein expressly
     provided) if in writing and mailed,  first-class  postage prepaid,  to each
     Holder  affected  by  such  event,  at its  address  as it  appears  in the
     applicable  Register,  not later than the latest date, and not earlier than
     the earliest date,  prescribed  for the giving of such notice.  In any case
     where notice to Holders is given by mail,  neither the failure to mail such
     notice  nor any  defect in any  notice so mailed to any  particular  Holder
     shall affect the  sufficiency of such notice with respect to other Holders.
     Where this Agreement provides for notice in any manner,  such notice may be
     waived in writing by the Person  entitled to receive  such  notice,  either
     before or after the event,  and such waiver shall be the equivalent of such
     notice.  Waivers  of notice by Holders  shall be filed with the Agent,  but
     such  filing  shall not be a  condition  precedent  to the  validity of any
     action taken in reliance upon such waiver.

          (b) In case by reason of the  suspension of regular mail service or by
     reason of any other cause it shall be  impracticable to give such notice by
     mail,  then such  notification  as shall be made with the  approval  of the
     Agent  shall  constitute  a  sufficient   notification  for  every  purpose
     hereunder.


Section 1.7 Effect of Headings and Table of Contents.
- -----------------------------------------------------

          The Article and Section  headings herein and the Table of Contents are
     for convenience only and shall not affect the construction hereof.


Section 1.8 Successors and Assigns.
- -----------------------------------

          All  covenants and  agreements in this  Agreement by the Company shall
     bind its successors and assigns, whether so expressed or not.


Section 1.9 Separability Clause.
- --------------------------------

          In case any  provision  in this  Agreement  or in the Equity  Units or
     Stripped Units shall be invalid,  illegal or  unenforceable,  the validity,
     legality and enforceability of the remaining  provisions hereof and thereof
     shall not in any way be affected or impaired thereby.


Section 1.10 Benefits of Agreement.
- -----------------------------------

     Nothing in this Agreement or in the Equity Units or Stripped Units, express
or implied,  shall give to any Person,  other than the parties  hereto and their
successors  hereunder  and, to the extent  provided  hereby,  the  Holders,  any
benefits or any legal or equitable right,  remedy or claim under this Agreement.
The Holders from time to time shall be beneficiaries of this Agreement and shall
be bound by all of the terms and  conditions  hereof and of the Equity Units and
Stripped Units evidenced by their  Certificates by their  acceptance of delivery
of such Certificates.


Section 1.11 Governing Law.
- ---------------------------

     This Agreement and the Equity Units and Stripped Units shall be governed by
and  construed  in  accordance  with the laws of the State of New York,  without
regard to its principles of conflicts of laws.


Section 1.12 Legal Holidays.
- ----------------------------

          (a) In any case where any  Payment  Date shall not be a Business  Day,
     then  (notwithstanding  any other provision of this Agreement or the Equity
     Units  Certificates)  payments on the Notes shall not be made on such date,
     but such payments  shall be made on the next  succeeding  Business Day with
     the same force and effect as if made on such Payment Date, provided that no
     interest  shall accrue or be payable by the Company for the period from and
     after any such Payment Date,  except that if such next succeeding  Business
     Day is in the next succeeding  calendar year, such payment shall be made on
     the Business Day immediately preceding the Payment Date with the same force
     and effect as if made on such Payment Date.

          (b) If any date on which Contract  Adjustment  Payments are to be made
     on the Forward  Purchase  Contracts is not a Business  Day, then payment of
     the Contract  Adjustment  Payments payable on that date will be made on the
     next  succeeding day which is a Business Day, and no interest or additional
     payment will be paid in respect of the delay. However, if that Business Day
     is in the next  succeeding  calendar  year, the payment will be made on the
     Business Day immediately preceding the Payment Date with the same force and
     effect as if made on that Payment Date.

          (c) In any case where the Stock  Purchase Date shall not be a Business
     Day, then  (notwithstanding  any other  provision of this  Agreement or the
     Certificates),  the Forward  Purchase  Contracts  shall not be performed on
     such date,  but the Forward  Purchase  Contracts  shall be performed on the
     immediately  following  Business  Day with the same  force and effect as if
     performed on the Stock Purchase Date.


Section 1.13 Counterparts.
- --------------------------

     This Agreement may be executed in any number of counterparts by the parties
hereto,  each of  which,  when so  executed  and  delivered,  shall be deemed an
original,  but all such counterparts shall together  constitute one and the same
instrument.

Section 1.14 Inspection of Agreement.
- -------------------------------------

     A copy of this Agreement shall be available at all reasonable  times during
normal  business  hours at the  Corporate  Trust  Office for  inspection  by any
Holder.

                                  ARTICLE II.
                                CERTIFICATE FORMS

Section 2.1 Forms of Certificates Generally.
- --------------------------------------------

          (a) The  Equity  Units  Certificates  (including  the form of  Forward
     Purchase Contract forming part of the Equity Units evidenced thereby) shall
     be in  substantially  the form set forth in  Exhibit  A  hereto,  with such
     letters,  numbers or other marks of  identification or designation and such
     legends or endorsements printed thereon, as may be required by the rules of
     any securities  exchange or quotation  system on which the Equity Units are
     listed  or  quoted  for  trading  or any  Depository  therefor,  or as may,
     consistently  herewith,  be  determined  by the  officers  of  the  Company
     executing such Equity Units  Certificates,  as evidenced by their execution
     of the Equity Units Certificates.

          (b) The definitive Equity Units  Certificates  shall be printed or may
     be produced in any other  manner,  all as determined by the officers of the
     Company  executing  such Equity  Units  Certificates,  consistent  with the
     provisions of this Agreement, as evidenced by their execution thereof.

          (c) The Stripped  Units  Certificates  (including  the form of Forward
     Purchase  Contracts  forming part of the Stripped Units evidenced  thereby)
     shall be in substantially the form set forth in Exhibit B hereto, with such
     letters,  numbers or other marks of  identification or designation and such
     legends or endorsements  printed thereon as may be required by the rules of
     any securities exchange or quotation system on which the Stripped Units may
     be listed or quoted for  trading  or any  Depository  therefor,  or as may,
     consistently  herewith,  be  determined  by the  officers  of  the  Company
     executing such Stripped Units Certificates, as evidenced by their execution
     of the Stripped Units Certificates.

          (d) The definitive Stripped Units Certificates shall be printed or may
     be produced in any other  manner,  all as determined by the officers of the
     Company  executing such Stripped Units  Certificates,  consistent  with the
     provisions of this Agreement, as evidenced by their execution thereof.

          (e) Every Global Certificate authenticated,  executed on behalf of the
     Holders and delivered  hereunder shall bear a legend in  substantially  the
     following form:

     "THIS CERTIFICATE IS A GLOBAL CERTIFICATE WITHIN THE MEANING OF THE FORWARD
PURCHASE  CONTRACT  AGREEMENT (AS HEREINAFTER  DEFINED) AND IS REGISTERED IN THE
NAME OF THE CLEARING AGENCY OR A NOMINEE  THEREOF.  THIS  CERTIFICATE MAY NOT BE
EXCHANGED IN WHOLE OR IN PART FOR A CERTIFICATE  REGISTERED,  AND NO TRANSFER OF
THIS  CERTIFICATE  IN  WHOLE OR IN PART  MAY BE  REGISTERED,  IN THE NAME OF ANY
PERSON  OTHER  THAN SUCH  CLEARING  AGENCY OR A NOMINEE  THEREOF,  EXCEPT IN THE
LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD PURCHASE CONTRACT AGREEMENT."

     Unless this Certificate is presented by an authorized representative of The
Depository Trust Company (55 Water Street, New York, New York) to the Company or
its agent for registration of transfer, exchange or payment, and any Certificate
issued is  registered in the name of Cede & Co., or such other name as requested
by an authorized representative of The Depository Trust Company, and any payment
hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE
OR OTHERWISE BY A PERSON IS WRONGFUL since the registered  owner hereof,  Cede &
Co., has an interest herein."

Section 2.2 Form of Agent's Certificate of Authentication.
- ----------------------------------------------------------

          (a) The  form of the  Agent's  certificate  of  authentication  of the
     Equity  Units shall be in  substantially  the form set forth on the form of
     the Equity Units Certificates.

          (b) The  form of the  Agent's  certificate  of  authentication  of the
     Stripped Units shall be in substantially  the form set forth on the form of
     the Stripped Units Certificates.


                                  ARTICLE III.
                                THE EQUITY UNITS


Section 3.1 Title and Terms; Denominations.
- -------------------------------------------

          (a) The aggregate  number of Equity Units and Stripped  Units, if any,
     evidenced by Certificates authenticated,  executed on behalf of the Holders
     and  delivered  hereunder  is  limited  to  6,000,000   (6,900,000  if  the
     Underwriters'  (as defined in the  Underwriting  Agreement)  over-allotment
     option pursuant to the Underwriting Agreement is exercised in full), except
     for Certificates authenticated, executed and delivered upon registration of
     transfer of, in exchange for, or in lieu of other Certificates  pursuant to
     Section 3.4, 3.5, 3.10, 3.13, 3.14, 5.9, 5.10 or 8.5.

          (b) The  Certificates  shall be issuable only in  registered  form and
     only in  denominations  of a single  Equity Unit and any integral  multiple
     thereof.


Section 3.2 Rights and Obligations Evidenced by the Certificates.
- -----------------------------------------------------------------

          (a) Each Equity Units  Certificate shall evidence the number of Equity
     Units  specified   therein,   with  each  such  Equity  Units   Certificate
     representing  the ownership by the Holder thereof of a beneficial  interest
     in a Note or the appropriate Treasury Consideration or Applicable Ownership
     Interest  in the  Treasury  Portfolio,  as the case may be,  subject to the
     Pledge of such Note or such Treasury  Consideration or Applicable Ownership
     Interest  in the  Treasury  Portfolio,  as the case may be, by such  Holder
     pursuant to the Pledge  Agreement,  and the rights and  obligations  of the
     Holder  thereof and the Company under one Forward  Purchase  Contract.  The
     Agent as attorney-in-fact  for, and on behalf of, the Holder of each Equity
     Unit  shall  pledge,  pursuant  to the  Pledge  Agreement,  the Note or the
     appropriate Treasury  Consideration or Applicable Ownership Interest in the
     Treasury  Portfolio,  as the case  may be,  forming  a part of such  Equity
     Units, to the Collateral Agent and grant to the Collateral Agent a security
     interest in the right,  title,  and interest of such Holder in such Note or
     such  Treasury  Consideration  or  Applicable  Ownership  Interest  in  the
     Treasury Portfolio,  as the case may be, for the benefit of the Company, to
     secure the obligation of the Holder under each Forward Purchase Contract to
     purchase the Common  Stock of the Company.  Prior to the purchase of shares
     of Common Stock under each Forward Purchase Contract, such Forward Purchase
     Contracts shall not entitle the Holders of Equity Units Certificates to any
     of the  rights of a holder of shares of Common  Stock,  including,  without
     limitation, the right to vote or receive any dividends or other payments or
     to consent or to receive notice as  stockholders in respect of the meetings
     of  stockholders or for the election of directors of the Company or for any
     other  matter,  or any  other  rights  whatsoever  as  stockholders  of the
     Company.

          (b) Each  Stripped  Units  Certificate  shall  evidence  the number of
     Stripped Units specified therein, with each such Stripped Units Certificate
     representing  the  ownership  by the  Holder  thereof  of a 1/20  undivided
     beneficial  interest in a Treasury Security,  subject to the Pledge of such
     interest in such  Treasury  Security by such Holder  pursuant to the Pledge
     Agreement,  and the rights and  obligations  of the Holder  thereof and the
     Company under one Forward Purchase Contract.  The Agent as attorney-in-fact
     for,  and on behalf  of,  the Holder of each  Stripped  Unit shall  pledge,
     pursuant to the Pledge Agreement, the Treasury Security,  forming a part of
     such Stripped  Unit, to the  Collateral  Agent and grant to the  Collateral
     Agent a security  interest in the right,  title and interest of such Holder
     in such  Treasury  Security for the benefit of the  Company,  to secure the
     obligation of the Holder under each Forward  Purchase  Contract to purchase
     shares of Common Stock pursuant to this  Agreement and the related  Forward
     Purchase  Contract.  Prior to the  purchase of shares of Common Stock under
     each Forward Purchase  Contract,  such Forward Purchase Contracts shall not
     entitle the Holders of Stripped Units  Certificates to any of the rights of
     a holder of shares of Common  Stock,  including,  without  limitation,  the
     right to vote or receive any  dividends or other  payments or to consent or
     to  receive  notice  as   stockholders   in  respect  of  the  meetings  of
     stockholders  or for the  election of  directors  of the Company or for any
     other  matter,  or any  other  rights  whatsoever  as  stockholders  of the
     Company.


Section 3.3 Execution, Authentication, Delivery and Dating.
- -----------------------------------------------------------

          (a)  Subject to the  provisions  of Sections  3.13 and 3.14,  upon the
     execution and delivery of this Agreement,  and at any time and from time to
     time  thereafter,  the  Company may  deliver  Certificates  executed by the
     Company to the Agent for authentication, execution on behalf of the Holders
     and  delivery,  together with its Issuer Order for  authentication  of such
     Certificates,  and the Agent in  accordance  with such  Issuer  Order shall
     authenticate,   execute  on  behalf  of  the  Holders   and  deliver   such
     Certificates.

          (b) The Certificates shall be executed on behalf of the Company by the
     Chief Executive Officer,  the Chief Financial Officer,  the President,  any
     Vice-President,  the Treasurer,  any Assistant Treasurer,  the Secretary or
     any Assistant  Secretary (or other officer performing similar functions) of
     the Company  and  delivered  to the Agent.  The  signature  of any of these
     officers on the Certificates may be manual or by facsimile.

          (c)  Certificates  bearing  the  manual  or  facsimile  signatures  of
     individuals  who were at any time the proper  officers of the Company shall
     bind the Company, notwithstanding that such individuals or any of them have
     ceased to hold such  offices  prior to the  authentication  and delivery of
     such  Certificates  or did  not  hold  such  offices  at the  date  of such
     Certificates.

          (d) No Forward Purchase  Contract  evidenced by a Certificate shall be
     valid until such  Certificate  has been executed on behalf of the Holder by
     the manual  signature  of an  authorized  signatory  of the Agent,  as such
     Holder's attorney-in-fact. Such signature by an authorized signatory of the
     Agent shall be conclusive  evidence that the Holder of such Certificate has
     entered into the Forward Purchase Contracts evidenced by such Certificate.

          (e) Each Certificate shall be dated the date of its authentication.

          (f) No  Certificate  shall  be  entitled  to any  benefit  under  this
     Agreement or be valid or obligatory for any purpose unless there appears on
     such Certificate a certificate of authentication  substantially in the form
     provided  for herein  executed by an  authorized  signatory of the Agent by
     manual  signature,  and  such  certificate  upon any  Certificate  shall be
     conclusive evidence, and the only evidence,  that such Certificate has been
     duly authenticated and delivered hereunder.


Section 3.4 Temporary Certificates.
- -----------------------------------

          (a) Pending the  preparation of definitive  Certificates,  the Company
     shall execute and deliver to the Agent,  and the Agent shall  authenticate,
     execute on behalf of the Holders,  and deliver,  in lieu of such definitive
     Certificates,  temporary  Certificates  which are in substantially the form
     set forth in Exhibit A or Exhibit B hereto,  as the case may be,  with such
     letters,  numbers or other marks of  identification or designation and such
     legends or endorsements printed, lithographed or engraved thereon as may be
     required by the rules of any securities  exchange on which the Equity Units
     or Stripped  Units, as the case may be, are listed,  or as may,  consistent
     herewith,  be  determined  by the  officers of the Company  executing  such
     Certificates, as evidenced by their execution of the Certificates.

          (b) If  temporary  Certificates  are issued,  the  Company  will cause
     definitive  Certificates to be prepared without  unreasonable  delay. After
     the  preparation  of definitive  Certificates,  the temporary  Certificates
     shall be  exchangeable  for definitive  Certificates  upon surrender of the
     temporary Certificates at the Corporate Trust Office, at the expense of the
     Company and without charge to the Holder.  Upon surrender for  cancellation
     of any one or more  temporary  Certificates,  the Company shall execute and
     deliver to the Agent, and the Agent shall  authenticate,  execute on behalf
     of the Holder,  and deliver in exchange  therefor,  one or more  definitive
     Certificates of like tenor and  denominations  and evidencing a like number
     of Equity  Units or Stripped  Units,  as the case may be, as the  temporary
     Certificate  or  Certificates  so  surrendered.  Until  so  exchanged,  the
     temporary Certificates shall in all respects evidence the same benefits and
     the same obligations with respect to the Equity Units or Stripped Units, as
     the case may be, evidenced thereby as definitive Certificates.


Section 3.5 Registration; Registration of Transfer and Exchange.
- ----------------------------------------------------------------

          (a) The Agent shall keep at the Corporate Trust Office a register (the
     "Equity Units Register") in which,  subject to such reasonable  regulations
     as it may prescribe, the Agent shall provide for the registration of Equity
     Units  Certificates  and of  transfers of Equity  Units  Certificates  (the
     Agent, in such capacity,  the "Equity Units Registrar") and a register (the
     "Equity Units Register") in which,  subject to such reasonable  regulations
     as it may prescribe,  the Agent shall provide for the  registration  of the
     Equity Units  Certificates and transfers of Equity Units  Certificates (the
     Agent, in such capacity, the "Equity Units Registrar").

          (b) Upon surrender for  registration of transfer of any Certificate at
     the Corporate  Trust  Office,  the Company shall execute and deliver to the
     Agent,  and  the  Agent  shall  authenticate,  execute  on  behalf  of  the
     designated  transferee  or  transferees,  and  deliver,  in the name of the
     designated transferee or transferees,  one or more new Certificates of like
     tenor and  denominations,  and  evidencing a like number of Equity Units or
     Stripped Units, as the case may be.

          (c) At the option of the Holder,  Certificates  may be  exchanged  for
     other  Certificates,  of like tenor and denominations and evidencing a like
     number  of  Equity  Units or  Stripped  Units,  as the  case  may be,  upon
     surrender  of the  Certificates  to be  exchanged  at the  Corporate  Trust
     Office.  Whenever any  Certificates  are so surrendered  for exchange,  the
     Company  shall  execute  and  deliver  to the  Agent,  and the Agent  shall
     authenticate, execute on behalf of the Holder, and deliver the Certificates
     which the Holder making the exchange is entitled to receive.

          (d) All  Certificates  issued  upon any  registration  of  transfer or
     exchange of a Certificate  shall  evidence the ownership of the same number
     of Equity Units or Stripped  Units,  as the case may be, and be entitled to
     the same benefits and subject to the same obligations, under this Agreement
     as the Equity Units or Stripped Units, as the case may be, evidenced by the
     Certificate surrendered upon such registration of transfer or exchange.

          (e) Every  Certificate  presented or surrendered  for  registration of
     transfer  or for  exchange  shall  (if so  required  by the  Agent) be duly
     endorsed,  or be  accompanied  by a written  instrument of transfer in form
     satisfactory  to the  Company  and the Agent duly  executed,  by the Holder
     thereof or its attorney duly authorized in writing.

          (f) No service charge shall be made for any  registration  of transfer
     or  exchange  of a  Certificate,  but the Company and the Agent may require
     payment  from the  Holder  of a sum  sufficient  to cover  any tax or other
     governmental charge that may be imposed in connection with any registration
     of transfer or exchange of Certificates,  other than any exchanges pursuant
     to Sections 3.4, 3.6, 3.9 and 8.5 not involving any transfer.

          (g) Notwithstanding the foregoing,  the Company shall not be obligated
     to execute and deliver to the Agent,  and the Agent shall not be  obligated
     to  authenticate,   execute  on  behalf  of  the  Holder  and  deliver  any
     Certificate  presented or surrendered  for  registration of transfer or for
     exchange on or after the Business Day immediately  preceding the earlier of
     the Stock Purchase Date or the  Termination  Date. In lieu of delivery of a
     new Certificate,  upon satisfaction of the applicable  conditions specified
     above in this Section and receipt of appropriate  registration  or transfer
     instructions from such Holder, the Agent shall,

               (i)  if the Stock Purchase Date has occurred,  deliver the shares
                    of Common Stock issuable in respect of the Forward  Purchase
                    Contracts  forming a part of the  Equity  Units or  Stripped
                    Units, as the case may be, evidenced by such Certificate,

               (ii) in the case of Equity Units,  if a  Termination  Event shall
                    have occurred prior to the Stock Purchase Date, transfer the
                    Notes  or  the   appropriate   Treasury   Consideration   or
                    Applicable Ownership Interest in the Treasury Portfolio,  as
                    applicable, relating to such Equity Units, or

               (iii)in the case of Stripped Units, if a Termination  Event shall
                    have occurred prior to the Stock Purchase Date, transfer the
                    Treasury Securities relating to such Stripped Units,

     in each case subject to the applicable  conditions  and in accordance  with
     the applicable provisions of Article V.

Section 3.6 Book-Entry Interests.
- ---------------------------------

     The Certificates, on original issuance will be issued in the form of one or
more fully registered Global Certificates,  to be delivered to the Depository or
its custodian by, or on behalf of, the Company.  Such Global  Certificate  shall
initially be  registered in the  applicable  Register in the name of Cede & Co.,
the nominee of the Depository, and no Beneficial Owner will receive a definitive
Certificate  representing  such  Beneficial  Owner's  interest  in  such  Global
Certificate,  except as provided in Section  3.9.  The Agent shall enter into an
agreement with the  Depository if so requested by the Company.  Unless and until
definitive,  fully registered Certificates have been issued to Beneficial Owners
pursuant to Section 3.9:

          (a) the  provisions  of this  Section  3.6 shall be in full  force and
     effect;

          (b) the Company shall be entitled to deal with the Clearing Agency for
     all purposes of this Agreement  (including  receiving  approvals,  votes or
     consents  hereunder)  as the Holder of the Equity Units and Stripped  Units
     and  the  sole  holder  of the  Global  Certificate(s)  and  shall  have no
     obligation to the Beneficial Owners;

          (c) to the extent that the  provisions  of this  Section 3.6  conflict
     with any other provisions of this Agreement, the provisions of this Section
     3.6 shall control; and

          (d) the  rights  of the  Beneficial  Owners  shall be  exercised  only
     through the Clearing  Agency and shall be limited to those  established  by
     law and agreements  between such Beneficial  Owners and the Clearing Agency
     and/or the Clearing  Agency  Participants.  The  Clearing  Agency will make
     book-entry transfers among Clearing Agency Participants.

Section 3.7 Notices To Holders.
- -------------------------------

          Whenever a notice or other communication to the Holders is required to
     be given under this  Agreement,  the Company or the  Company's  agent shall
     give such notices and  communications  to the Holders and,  with respect to
     any Equity  Units or Stripped  Units  registered  in the name of a Clearing
     Agency or the nominee of a Clearing  Agency,  the Company or the  Company's
     agent  shall,  except  as set  forth  herein,  have no  obligations  to the
     Beneficial Owners.

Section 3.8 Appointment of Successor Clearing Agency.
- -----------------------------------------------------

     If any Clearing  Agency  elects to  discontinue  its services as securities
Depository  with respect to the Equity Units and Stripped  Units or ceases to be
eligible as a "clearing  agency" under the Exchange Act, the Company may, in its
sole discretion,  appoint a successor Clearing Agency with respect to the Equity
Units and Stripped Units.

Section 3.9 Definitive Certificates.
- ------------------------------------

     If

          (i)  a  Clearing   Agency  elects  to  discontinue   its  services  as
               securities  Depository  with  respect  to the  Equity  Units  and
               Stripped  Units or ceases to be eligible  as a "clearing  agency"
               under the  Exchange  Act and a successor  Clearing  Agency is not
               appointed  within 90 days after such  discontinuance  pursuant to
               Section 3.8,

          (ii) the Company elects to terminate the book-entry system through the
               Clearing  Agency with  respect to the Equity  Units and  Stripped
               Units, or

          (iii)there  shall have  occurred  and be  continuing  a default by the
               Company in respect of its  obligations  under one or more Forward
               Purchase Contracts, this Agreement, the Indenture, the Notes, the
               Equity  Units,  the  Pledge  Agreement  or  any  other  principal
               agreements  or  instruments   executed  in  connection  with  the
               offering of Equity Units

then upon  surrender  of the Global  Certificates  representing  the  Book-Entry
Interests  with respect to the Equity  Units and Stripped  Units by the Clearing
Agency,  accompanied  by  registration  instructions,  the  Company  shall cause
definitive  Certificates  to be delivered  to Clearing  Agency  Participants  in
accordance  with the  instructions of the Clearing  Agency.  The Company and the
Agent shall not be liable for any delay in delivery of such instructions and may
conclusively rely on and shall be protected in relying on such instructions.

Section 3.10 Mutilated, Destroyed, Lost and Stolen Certificates.
- ----------------------------------------------------------------

          (a) If any mutilated  Certificate  is  surrendered  to the Agent,  the
     Company  shall  execute  and  deliver  to the  Agent,  and the Agent  shall
     authenticate,  execute on behalf of the  Holder,  and  deliver in  exchange
     therefor, a new Certificate at the cost of the Holder,  evidencing the same
     number of Equity Units or Stripped Units, as the case may be, and bearing a
     Certificate number not contemporaneously outstanding.

          (b) If there  shall be  delivered  to the  Company  and the  Agent (i)
     evidence to their  satisfaction  of the  destruction,  loss or theft of any
     Certificate,  and (ii) such security or indemnity at the cost of the Holder
     as may be  required  by them to hold  each of them and any  agent of any of
     them  harmless,  then, in the absence of notice to the Company or the Agent
     that such  Certificate  has been  acquired  by a bona fide  purchaser,  the
     Company  shall  execute  and  deliver  to the  Agent,  and the Agent  shall
     authenticate,  execute on behalf of the Holder,  and deliver to the Holder,
     in  lieu  of  any  such  destroyed,  lost  or  stolen  Certificate,  a  new
     Certificate,  evidencing the same number of Equity Units or Stripped Units,
     as the case may be, and bearing a Certificate number not  contemporaneously
     outstanding.

          (c) Notwithstanding the foregoing,  the Company shall not be obligated
     to execute and deliver to the Agent,  and the Agent shall not be  obligated
     to  authenticate,  execute  on behalf of the  Holder,  and  deliver  to the
     Holder,  a Certificate on or after the Business Day  immediately  preceding
     the earlier of the Stock Purchase Date or the Termination  Date. In lieu of
     delivery  of  a  new  Certificate,  upon  satisfaction  of  the  applicable
     conditions  specified  above in this  Section  and  receipt of  appropriate
     registration or transfer instructions from such Holder, the Agent shall (i)
     if the Stock Purchase Date has occurred, deliver the shares of Common Stock
     issuable in respect of the Forward Purchase Contracts forming a part of the
     Equity Units or Stripped Units evidenced by such Certificate,  or (ii) if a
     Termination  Event shall have occurred  prior to the Stock  Purchase  Date,
     transfer the Notes,  the appropriate  Treasury  Consideration or Applicable
     Ownership Interest in the Treasury Portfolio,  or the Treasury  Securities,
     as the  case  may be,  evidenced  thereby,  in  each  case  subject  to the
     applicable  conditions and in accordance with the applicable  provisions of
     Article V.

          (d) Upon the issuance of any new Certificate  under this Section,  the
     Company  and the Agent  may  require  the  payment  by the  Holder of a sum
     sufficient  to  cover  any tax or  other  governmental  charge  that may be
     imposed in relation thereto and any other expenses  (including the fees and
     expenses of the Agent) connected therewith.

          (e) Every new  Certificate  issued pursuant to this Section in lieu of
     any  destroyed,  lost or stolen  Certificate  shall  constitute an original
     contractual  obligation  of the Company and of the Holder in respect of the
     Equity  Units or Stripped  Units,  as the case may be,  evidenced  thereby,
     whether or not the destroyed,  lost or stolen  Certificate  (and the Equity
     Units  and  Stripped  Units  evidenced   thereby)  shall  be  at  any  time
     enforceable  by anyone,  and shall be entitled to all the  benefits  and be
     subject   to  all  the   obligations   of  this   Agreement   equally   and
     proportionately with any and all other Certificates delivered hereunder.

          (f) The  provisions of this Section are  exclusive and shall  preclude
     (to the extent  lawful) all other rights and  remedies  with respect to the
     replacement   or  payment   of   mutilated,   destroyed,   lost  or  stolen
     Certificates.

Section 3.11 Persons Deemed Owners.
- -----------------------------------

          (a) Prior to due  presentment  of a Certificate  for  registration  of
     transfer,  the Company  and the Agent,  and any agent of the Company or the
     Agent, may treat the Person in whose name such Certificate is registered as
     the  owner of the  Equity  Units  or  Stripped  Units,  as the case may be,
     evidenced  thereby,  for the purpose of receiving  interest payments on the
     Notes,  receiving payment of Contract Adjustment  Payments,  performance of
     the  Forward  Purchase  Contracts  and for all  other  purposes  whatsoever
     (subject to Section  4.1(a) and 5.2(a)),  whether or not any such  payments
     shall be  overdue  and  notwithstanding  any  notice to the  contrary,  and
     neither  the  Company  nor the Agent,  nor any agent of the  Company or the
     Agent, shall be affected by notice to the contrary.

          (b)  Notwithstanding  the  foregoing,   with  respect  to  any  Global
     Certificate,  nothing  herein shall  prevent the Company,  the Agent or any
     agent of the  Company  or the  Agent  from  giving  effect  to any  written
     certification,  proxy  or other  authorization  furnished  by any  Clearing
     Agency  (or  its  nominee),  as a  Holder,  with  respect  to  such  Global
     Certificate  or  impair,  as  between  such  Clearing  Agency and owners of
     beneficial interests in such Global Certificate, the operation of customary
     practices  governing the exercise of rights of such Clearing Agency (or its
     nominee) as Holder of such Global  Certificate.  None of the  Company,  the
     Agent,   or  any  agent  of  the   Company  or  the  Agent  will  have  any
     responsibility  or liability  for any aspect of the records  relating to or
     payments  made on account of  beneficial  ownership  interests  in a Global
     Certificate or maintaining,  supervising or reviewing any records  relating
     to such beneficial ownership interests.

Section 3.12 Cancellation.
- --------------------------

          (a) All Certificates  surrendered (i) for delivery of shares of Common
     Stock on or after any Settlement Date; (ii) upon the transfer of Notes, the
     appropriate Treasury  Consideration or Applicable Ownership Interest in the
     Treasury Portfolio,  or Treasury Securities,  as the case may be, after the
     occurrence  of a Termination  Event;  or (iii) upon the  registration  of a
     transfer or exchange of Equity Units or Stripped Units, as the case may be,
     shall,  if surrendered to any Person other than the Agent,  be delivered to
     the Agent and, if not already cancelled, shall be promptly cancelled by it.
     The  Company  may at any time  deliver  to the Agent for  cancellation  any
     Certificates  previously  authenticated,  executed and delivered  hereunder
     which the  Company  may have  acquired  in any manner  whatsoever,  and all
     Certificates so delivered shall,  upon Issuer Order, be promptly  cancelled
     by the Agent. No Certificates shall be authenticated, executed on behalf of
     the Holder and  delivered  in lieu of or in exchange  for any  Certificates
     cancelled as provided in this  Section,  except as  expressly  permitted by
     this  Agreement.  All  cancelled  Certificates  held by the Agent  shall be
     disposed of by the Agent in accordance with its customary procedures.

          (b) If the Company or any  Affiliate of the Company  shall acquire any
     Certificate,  such acquisition  shall not operate as a cancellation of such
     Certificate  unless and until such Certificate is cancelled or delivered to
     the Agent for cancellation.

Section 3.13 Establishment of Stripped Units.
- ---------------------------------------------

          (a) Unless a  successful  remarketing  or a Tax Event  Redemption  has
     occurred,  a Holder may separate the Pledged Notes from the related Forward
     Purchase  Contracts  in respect of the Equity  Units held by such Holder by
     substituting  for such Pledged Notes Treasury  Securities that will pay, on
     the Stock Purchase Date, an amount equal to the aggregate  principal amount
     of such Notes (a "Collateral Substitution"), at any time from and after the
     date  of  this  Agreement  and  on or  prior  to  the  tenth  Business  Day
     immediately  preceding the Stock Purchase Date, by (i) depositing  with the
     Collateral Agent Treasury  Securities having an aggregate  principal amount
     equal  to the  aggregate  Stated  Amount  of such  Equity  Units,  and (ii)
     transferring the related Equity Units to the Agent  accompanied by a notice
     to the Agent,  substantially in the form of Exhibit D hereto,  stating that
     the Holder has transferred  the relevant  amount of Treasury  Securities to
     the Collateral  Agent and requesting that the Agent instruct the Collateral
     Agent to release the Pledged Notes underlying such Equity Units,  whereupon
     the Agent shall promptly give such  instruction  to the  Collateral  Agent,
     substantially  in  the  form  of  Exhibit  C  hereto.  Notwithstanding  the
     foregoing,  a Holder may not  separate  the Pledged  Notes from the related
     Forward  Purchase  Contracts  in respect  of the Equity  Units held by such
     Holder during the periods beginning on the fourth Business Day prior to any
     Remarketing  Period and ending on the third  Business  Day after the end of
     such Remarketing Period. Upon receipt of the Treasury Securities  described
     in clause (i) above and the instruction  described in clause (ii) above, in
     accordance  with the terms of the Pledge  Agreement,  the Collateral  Agent
     will release to the Agent, on behalf of the Holder, such Pledged Notes from
     the Pledge, free and clear of the Company's security interest therein,  and
     upon receipt thereof the Agent shall promptly:

               (i)  cancel the related Equity Units;

               (ii) transfer the Pledged Notes to the Holder; and

               (iii)authenticate,  execute on behalf of such  Holder and deliver
                    to such Holder a Stripped Units Certificate  executed by the
                    Company in accordance  with Section 3.3  evidencing the same
                    number of Forward  Purchase  Contracts as were  evidenced by
                    the cancelled Equity Units.

          (b) Holders who elect to separate  the Pledged  Notes from the related
     Forward Purchase  Contract and to substitute  Treasury  Securities for such
     Pledged Notes shall be responsible for any fees or expenses  payable to the
     Collateral  Agent for its  services as  Collateral  Agent in respect of the
     substitution, and the Company shall not be responsible for any such fees or
     expenses.

          (c) Holders may make Collateral  Substitutions if Treasury  Securities
     are being substituted for Pledged Notes,  only in integral  multiples of 20
     Equity Units.

          (d) In the event a Holder making a Collateral Substitution pursuant to
     this Section 3.13 fails to effect a book-entry transfer of the Equity Units
     or  fails to  deliver  an  Equity  Units  Certificate  to the  Agent  after
     depositing Treasury Securities with the Collateral Agent, the Pledged Notes
     constituting  a part of such Equity Units,  and any  distributions  on such
     Pledged  Notes  shall be held in the name of the  Agent or its  nominee  in
     trust for the  benefit  of such  Holder,  until  such  Equity  Units are so
     transferred or the Equity Units  Certificate  is so delivered,  as the case
     may be,  or,  with  respect to an Equity  Units  Certificate,  such  Holder
     provides  evidence  satisfactory  to the  Company  and the Agent  that such
     Equity Units Certificate has been destroyed,  lost or stolen, together with
     any indemnity that may be required by the Agent and the Company.

          (e)  Except as  described  in this  Section  3.13,  for so long as the
     Forward Purchase Contract underlying an Equity Unit remains in effect, such
     Equity Unit shall not be  separable  into its  constituent  parts,  and the
     rights and  obligations of the Holder of such Equity Unit in respect of the
     Note or the  appropriate  Treasury  Consideration  or Applicable  Ownership
     Interest  in the  Treasury  Portfolio,  as the case may be, and the Forward
     Purchase Contract  comprising such Equity Unit may be acquired,  and may be
     transferred and exchanged, only as an Equity Unit.

Section 3.14 Reestablishment of Equity Units.
- ---------------------------------------------

          (a) Unless a  successful  remarketing  or a Tax Event  Redemption  has
     occurred,  a Holder of Stripped Units may  reestablish  Equity Units at any
     time from and after the date of this Agreement and on or prior to the tenth
     Business  Day  immediately  preceding  the  Stock  Purchase  Date,  by  (i)
     depositing with the Collateral  Agent the Notes then comprising such number
     of Equity Units as is equal to such  Stripped  Units and (ii)  transferring
     such  Stripped  Units to the Agent  accompanied  by a notice to the  Agent,
     substantially in the form of Exhibit D hereto,  stating that the Holder has
     transferred  the  relevant  amount  of Notes to the  Collateral  Agent  and
     requesting  that the Agent  instruct  the  Collateral  Agent to release the
     Pledged Treasury Securities  underlying such Stripped Units,  whereupon the
     Agent  shall  promptly  give  such  instruction  to the  Collateral  Agent,
     substantially  in  the  form  of  Exhibit  C  hereto.  Notwithstanding  the
     foregoing,  a Holder may not  reestablish  Equity  Units during the periods
     beginning on the fourth  Business Day prior to any  Remarketing  Period and
     ending on the third Business Day after the end of such Remarketing  Period.
     Upon receipt of the Notes described in clause (i) above and the instruction
     described in clause (ii) above,  in accordance with the terms of the Pledge
     Agreement, the Collateral Agent will release to the Agent, on behalf of the
     Holder, such Pledged Treasury Securities from the Pledge, free and clear of
     the Company's security interest therein, and upon receipt thereof the Agent
     shall promptly:

               (i)  cancel the related Stripped Units;

               (ii) transfer the Pledged Treasury Securities to the Holder; and

               (iii)authenticate,  execute on behalf of such  Holder and deliver
                    an Equity  Units  Certificate  executed  by the  Company  in
                    accordance  with Section 3.3  evidencing  the same number of
                    Forward   Purchase   Contracts  as  were  evidenced  by  the
                    cancelled Stripped Units.

          (b) Holders of Stripped  Units may  reestablish  Equity  Units only in
     integral multiples of 20 Stripped Units for 20 Equity Units.

          (c)  Except  as  provided  in this  Section  3.14,  for so long as the
     Forward  Purchase  Contract  underlying a Stripped  Unit remains in effect,
     such Stripped Unit shall not be separable into its constituent  parts,  and
     the rights and  obligations  of the Holder of such Stripped Unit in respect
     of the Treasury  Security and Forward  Purchase  Contract  comprising  such
     Stripped Unit may be acquired,  and may be transferred and exchanged,  only
     as a Stripped Unit.

          (d) Holders of Stripped  Units who  reestablish  Equity Units shall be
     responsible  for any fees or expenses  payable to the Collateral  Agent for
     its services as Collateral  Agent in respect of the  substitution,  and the
     Company shall not be responsible for any such fees or expenses.

          (e) In the event a Holder who  reestablishes  Equity Units pursuant to
     this  Section  3.14 fails to effect a  book-entry  transfer of the Stripped
     Units or fails to deliver a Stripped  Units  Certificate to the Agent after
     depositing Pledged Notes with the Collateral Agent, the Treasury Securities
     constituting a part of such Stripped Units,  and any  distributions on such
     Treasury  Securities  shall be held in the name of the Agent or its nominee
     in trust for the benefit of such Holder,  until such Stripped  Units are so
     transferred or the Stripped Units Certificate is so delivered,  as the case
     may be, or,  with  respect to a Stripped  Units  Certificate,  such  Holder
     provides  evidence  satisfactory  to the  Company  and the Agent  that such
     Stripped Units  Certificate  has been destroyed,  lost or stolen,  together
     with any indemnity that may be required by the Agent and the Company.

Section 3.15 Transfer of Collateral Upon Occurrence of Termination Event.
- -------------------------------------------------------------------------

     Upon the occurrence of a Termination Event and the transfer to the Agent by
the Collateral  Agent of the Notes,  the appropriate  Treasury  Consideration or
Applicable  Ownership  Interest  in the  Treasury  Portfolio,  or  the  Treasury
Securities,  as the case may be,  underlying  the Equity  Units or the  Stripped
Units,  as the case may be, pursuant to the terms of the Pledge  Agreement,  the
Agent shall  request  transfer  instructions  with  respect to such Notes or the
appropriate  Treasury  Consideration  or  Applicable  Ownership  Interest in the
Treasury Portfolio, or Treasury Securities, as the case may be, from each Holder
by written  request  mailed to such  Holder at its  address as it appears in the
Equity Units Register or the Stripped Units  Register,  as the case may be. Upon
book-entry  transfer  of the Equity  Units or  Stripped  Units or delivery of an
Equity Units  Certificate or Stripped  Units  Certificate to the Agent with such
transfer  instructions,  the Agent shall  transfer  the Notes,  the  appropriate
Treasury   Consideration  or  Applicable  Ownership  Interest  in  the  Treasury
Portfolio,  or Treasury  Securities,  as the case may be, underlying such Equity
Units or  Stripped  Units,  as the case may be,  to such  Holder  by  book-entry
transfer, or other appropriate procedures, in accordance with such instructions.
In the event a Holder  would be entitled to receive  less than $1,000  principal
amount at maturity of any  Treasury  security,  the Agent shall  dispose of such
Treasury  security for cash and deliver such cash to the Holder.  In the event a
Holder of Equity  Units or  Stripped  Units  fails to effect  such  transfer  or
delivery,  the Notes,  the  appropriate  Treasury  Consideration  or  Applicable
Ownership Interest in the Treasury Portfolio or Treasury Securities, as the case
may be,  underlying such Equity Units or Stripped Units, as the case may be, and
any distributions thereon, shall be held in the name of the Agent or its nominee
in trust for the benefit of such Holder, until (i) such Equity Units or Stripped
Units  are  transferred  or the  Equity  Units  Certificate  or  Stripped  Units
Certificate is surrendered or such Holder  provides  satisfactory  evidence that
such Equity Units  Certificate or Stripped Units Certificate has been destroyed,
lost or stolen,  together with any  indemnity  that may be required by the Agent
and the Company;  and (ii) the  expiration  of the time period  specified in the
abandoned property laws of the relevant State.

Section 3.16 No Consent to Assumption.
- --------------------------------------

     Each  Holder  of Equity  Units or  Stripped  Units,  as the case may be, by
acceptance  thereof,  shall be deemed  expressly to have withheld any consent to
the  assumption  under Section 365 of the Bankruptcy  Code or otherwise,  of the
Forward Purchase Contract by the Company, any receiver,  liquidator or person or
entity performing similar functions or its trustee in the event that the Company
becomes the debtor under the  Bankruptcy  Code or subject to other similar state
or federal law providing for reorganization or liquidation.

                                   ARTICLE IV.
                                    THE NOTES

Section 4.1 Payment of Interest; Rights to Interest Payments Preserved; Notice.
- -------------------------------------------------------------------------------

          (a) A  payment  on any  Note,  Treasury  Consideration  or  Applicable
     Ownership Interest in the Treasury Portfolio,  as the case may be, which is
     paid on any  Payment  Date  other than a Payment  Date with  respect to the
     Stated  Amount  due  on  Treasury  Consideration  or  Applicable  Ownership
     Interest in the Treasury Portfolio shall, subject to receipt thereof by the
     Agent from the Collateral  Agent (if the Collateral Agent is the registered
     owner thereof) as provided by the terms of the Pledge Agreement, be paid to
     the  Person in whose  name the  Equity  Units  Certificate  (or one or more
     Predecessor   Equity  Units   Certificates)  of  which  such  Note  or  the
     appropriate Treasury  Consideration or Applicable Ownership Interest in the
     Treasury  Portfolio,  as the case may be,  is a part is  registered  at the
     close of business on the Record Date for such Payment Date.

          (b) Each Equity Units  Certificate  evidencing  Notes  delivered under
     this  Agreement upon  registration  of transfer of or in exchange for or in
     lieu of any other  Equity  Units  Certificate  shall  carry  the  rights to
     interest  accrued and unpaid  which were  carried by the Notes and Treasury
     Consideration or Applicable  Ownership Interest in the Treasury  Portfolio,
     as the case may be, underlying such other Equity Units Certificate.

          (c) In the case of any  Equity  Units  with  respect  to  which  Early
     Settlement of the underlying  Forward  Purchase  Contract is effected on an
     Early  Settlement Date,  Merger Early Settlement of the underlying  Forward
     Purchase  Contract is  effected on a Merger  Early  Settlement  Date,  Cash
     Settlement is effected on the seventh  Business Day  immediately  preceding
     the Stock Purchase Date, or a Collateral  Substitution is effected, in each
     case on a date  that is after any  Record  Date and on or prior to the next
     succeeding Payment Date,  payments on the Note or the appropriate  Treasury
     Consideration or Applicable  Ownership Interest in the Treasury  Portfolio,
     as the case may be,  underlying such Equity Units otherwise payable on such
     Payment  Date shall be payable on such Payment  Date  notwithstanding  such
     Early Settlement,  Merger Early  Settlement,  Cash Settlement or Collateral
     Substitution,  as the case may be,  and such  payments  shall,  subject  to
     receipt  thereof by the  Agent,  be payable to the Person in whose name the
     Equity  Units  Certificate  (or  one  or  more  Predecessor   Equity  Units
     Certificates)  was  registered at the close of business on the Record Date.
     Except  as  otherwise  expressly  provided  in  the  immediately  preceding
     sentence,  in the case of any  Equity  Units with  respect  to which  Early
     Settlement,  Merger Early  Settlement or Cash  Settlement of the underlying
     Forward  Purchase  Contract  is  effected,  or  with  respect  to  which  a
     Collateral Substitution has been effected, payments on the related Notes or
     payments on the appropriate Treasury  Consideration or Applicable Ownership
     Interest  in the  Treasury  Portfolio,  as the  case  may  be,  that  would
     otherwise be payable  after the  applicable  Settlement  Date or after such
     Collateral Substitution, as the case may be, shall not be payable hereunder
     to the Holder of such Equity Units; provided,  that to the extent that such
     Holder continues to hold the Separate Notes that formerly  comprised a part
     of such Holder's Equity Units, such Holder shall be entitled to receive the
     payments on such Separate Notes.

Section 4.2 Notice and Voting.
- ------------------------------

     Under the terms of the  Pledge  Agreement,  the Agent will be  entitled  to
exercise the voting and any other  consensual  rights  pertaining to the Pledged
Notes but only to the extent  instructed by the Holders as described below. Upon
receipt of notice of any meeting at which  holders of Notes are entitled to vote
or upon any  solicitation  of consents,  waivers or proxies of holders of Notes,
the Agent  shall,  as soon as  practicable  thereafter,  mail to the  Holders of
Equity Units a notice (a)  containing  such  information  as is contained in the
notice or  solicitation,  (b) stating that each Holder on the record date set by
the Agent therefor (which, to the extent possible, shall be the same date as the
record  date for  determining  the  holders of Notes  entitled to vote) shall be
entitled  to  instruct  the  Agent  as to  the  exercise  of the  voting  rights
pertaining  to the Pledged Notes  underlying  their Equity Units and (c) stating
the manner in which such  instructions may be given. Upon the written request of
the  Holders of Equity  Units on such  record  date,  the Agent  shall  endeavor
insofar as  practicable  to vote or cause to be voted,  in  accordance  with the
instructions set forth in such requests,  the maximum number of Pledged Notes as
to which any  particular  voting  instructions  are received.  In the absence of
specific instructions from the Holder of an Equity Unit, the Agent shall abstain
from voting the Pledged Note  underlying  such Equity Units.  The Company hereby
agrees, if applicable, to solicit Holders of Equity Units to timely instruct the
Agent in order to enable the Agent to vote such Pledged Notes.

Section 4.3 Tax Event Redemption.
- ---------------------------------

     Upon the  occurrence  of a Tax Event  Redemption  prior to the earlier of a
successful  remarketing of the Notes or the Stock Purchase Date, the Company may
elect to  instruct  in  writing  the  Collateral  Agent to apply,  and upon such
written  instruction,  the  Collateral  Agent shall apply,  out of the aggregate
Redemption  Price for the Notes that are  components of Equity Units,  an amount
equal to the aggregate  Redemption  Amount for the Notes that are  components of
Equity  Units to purchase on behalf of the Holders of Equity  Units the Treasury
Portfolio and promptly remit the remaining portion of such aggregate  Redemption
Price to the Agent for payment to the Holders of such Equity Units. The Treasury
Portfolio will be substituted for the Pledged Notes,  and will be pledged to the
Collateral  Agent in accordance with the terms of the Pledge Agreement to secure
the  obligation  of each Holder of an Equity  Units to purchase the Common Stock
under the Forward  Purchase  Contract  constituting a part of such Equity Units.
Following  the  occurrence of a Tax Event  Redemption  prior to the earlier of a
successful  remarketing  of the Notes or the Stock Purchase Date, the Holders of
Equity Units and the Collateral Agent shall have such security interests, rights
and obligations  with respect to the Treasury  Portfolio as the Holder of Equity
Units and the Collateral  Agent had in respect of the Notes, as the case may be,
subject to the Pledge  thereof as provided in Articles  II, III, IV, V and VI of
the Pledge  Agreement,  and any reference  herein or in the  Certificates to the
Note  shall be deemed  to be a  reference  to such  Treasury  Portfolio  and any
reference herein or in the Certificates to interest on the Notes shall be deemed
to be a reference to corresponding  distributions on the Treasury Portfolio. The
Company may cause to be made in any Equity Units  Certificates  thereafter to be
issued  such change in  phraseology  and form (but not in  substance)  as may be
appropriate to reflect the  substitution of the Treasury  Portfolio for Notes as
collateral.

     The Company shall cause notice of any Tax Event Redemption to be mailed, at
least 30 calendar  days but not more than 60 calendar days before such Tax Event
Redemption  Date, to each Holder of Equity Units  including Notes to be redeemed
at its registered address.

     Upon the  occurrence  of a Tax  Event  Redemption  after the  earlier  of a
successful  remarketing  of the Notes or the Stock Purchase Date, the Redemption
Price will be payable in cash to the holders of the Notes.


                                   ARTICLE V.
                 THE FORWARD PURCHASE CONTRACTS; THE REMARKETING

Section 5.1 Purchase of Shares of Common Stock.
- -----------------------------------------------

          (a) Each Forward Purchase  Contract shall,  unless an Early Settlement
     has occurred in accordance  with Section 5.9, or a Merger Early  Settlement
     has occurred in accordance  with Section  5.10,  obligate the Holder of the
     related  Equity Units or Stripped  Units,  as the case may be, to purchase,
     and the Company to sell, on the Stock Purchase Date at a price equal to $50
     (the  "Purchase  Price"),  a number of newly issued  shares of Common Stock
     equal to the  Settlement  Rate  unless,  on or prior to the Stock  Purchase
     Date,  there shall have  occurred a  Termination  Event with respect to the
     Units of which such Forward  Purchase  Contract is a part. The  "Settlement
     Rate" is equal to,

               (i)  if the Applicable Market Value (as defined below) is greater
                    than  or  equal  to  $49.08  (the  "Threshold   Appreciation
                    Price"),  1.0187 shares of Common Stock per Forward Purchase
                    Contract,

               (ii) if the  Applicable  Market Value is less than the  Threshold
                    Appreciation  Price, but is greater than $40.90,  the number
                    of shares of Common  Stock  per  Forward  Purchase  Contract
                    equal to $50 divided by the Applicable Market Value, and

               (iii)if the  Applicable  Market  Value is  equal to or less  than
                    $40.90,  1.2225 shares of Common Stock per Forward  Purchase
                    Contract,

     in each case subject to  adjustment  as provided in Section 5.6 and in each
     case rounded upward or downward to the nearest 1/10,000th of a share.

          As provided in Section 5.12, no fractional shares of Common Stock will
     be issued upon settlement of Forward Purchase Contracts.

          Promptly  after  the  calculation  of  the  Settlement  Rate  and  the
     Applicable  Market Value,  the Company shall give the Agent notice thereof.
     All  calculations  and  determinations  of  the  Settlement  Rate  and  the
     Applicable Market Value shall be made by the Company or its agents based on
     their good faith  calculations,  and the Agent shall have no responsibility
     with respect thereto.

          (b) The  "Applicable  Market  Value"  means the average of the Closing
     Price per share of Common Stock on each of the 20 consecutive  Trading Days
     ending on the third Trading Day  immediately  preceding the Stock  Purchase
     Date. The "Closing Price" of the Common Stock on any date of  determination
     means the closing sale price (or, if no closing price is reported, the last
     reported  sale  price) of the Common  Stock on the New York Stock  Exchange
     (the "NYSE") on such date or, if the Common Stock is not listed for trading
     on the NYSE on any such date, as reported in the composite transactions for
     the principal United States  securities  exchange on which the Common Stock
     is so listed,  or if the Common  Stock is not so listed on a United  States
     national or regional securities  exchange,  as reported by The NASDAQ Stock
     Market,  or, if the Common  Stock is not so  reported,  the last quoted bid
     price for the Common  Stock in the  over-the-counter  market as reported by
     the  National  Quotation  Bureau or similar  organization,  or, if such bid
     price is not  available,  the market value of the Common Stock on such date
     as determined by a nationally  recognized  independent  investment  banking
     firm retained for this purpose by the Company.  A "Trading Day" means a day
     on which the Common Stock (A) is not suspended from trading on any national
     or regional securities  exchange or association or over-the-counter  market
     at the close of business  and (B) has traded at least once on the  national
     or regional securities  exchange or association or over-the-counter  market
     that is the primary market for the trading of the Common Stock.

          (c) Each Holder of Equity Units or Stripped Units, as the case may be,
     by its acceptance thereof,  irrevocably  authorizes the Agent to enter into
     and  perform  the related  Forward  Purchase  Contract on its behalf as its
     attorney-in-fact (including the execution of Certificates on behalf of such
     Holder), agrees to be bound by the terms and provisions thereof,  covenants
     and  agrees  to  perform  its  obligations   under  such  Forward  Purchase
     Contracts,  and consents to the provisions hereof,  irrevocably  authorizes
     the Agent as its  attorney-in-fact  to enter  into and  perform  the Pledge
     Agreement on its behalf as its attorney-in-fact, and consents to and agrees
     to  be  bound  by  the  Pledge  of  the  Notes,  the  appropriate  Treasury
     Consideration or Applicable  Ownership Interest in the Treasury  Portfolio,
     or the Treasury Securities pursuant to the Pledge Agreement;  provided that
     upon a Termination  Event, the rights of the Holder of such Equity Units or
     Stripped Units, as the case may be, under the Forward Purchase Contract may
     be enforced without regard to any other rights or obligations.  Each Holder
     of Equity Units or Stripped  Units,  as the case may be, by its  acceptance
     thereof, further covenants and agrees that, to the extent and in the manner
     provided in Section 5.4 and the Pledge Agreement,  but subject to the terms
     thereof,  payments  in  respect  of the  Notes,  the  appropriate  Treasury
     Consideration or Applicable  Ownership Interest in the Treasury  Portfolio,
     or the Treasury  Securities,  to be paid upon  settlement  of such Holder's
     obligations to purchase Common Stock under the Forward  Purchase  Contract,
     shall be paid on the Stock  Purchase  Date by the  Collateral  Agent to the
     Company in  satisfaction  of such Holder's  obligations  under such Forward
     Purchase Contract and such Holder shall acquire no right, title or interest
     in such payment.

          (d) Upon  registration  of transfer of a  Certificate,  the transferee
     shall be bound  (without  the  necessity of any other action on the part of
     such  transferee)  under the terms of this Agreement,  the Forward Purchase
     Contracts  underlying such  Certificate and the Pledge  Agreement,  and the
     transferor shall be released from the obligations under this Agreement, the
     Forward Purchase  Contracts  underlying the Certificates so transferred and
     the Pledge Agreement.  The Company covenants and agrees, and each Holder of
     a Certificate, by its acceptance thereof, likewise covenants and agrees, to
     be bound by the provisions of this paragraph.

     Section 5.2 Contract Adjustment Payments.
     -----------------------------------------

          (a) Contract Adjustment Payments shall accrue on each Forward Purchase
     Contract  constituting  a part of an Equity Unit or Stripped  Unit at 3.50%
     per year of the Stated  Amount of such Equity Unit or Stripped  Unit,  from
     June 11, 2002 through and including the Stock Purchase Date,  provided that
     no Contract  Adjustment  Payment shall accrue after an Early  Settlement or
     Merger Early Settlement.  Subject to Section 5.3 herein,  the Company shall
     pay, on each  Payment  Date,  the  Contract  Adjustment  Payments,  if any,
     payable in respect of each Forward Purchase Contract to the Person in whose
     name a Certificate (or one or more Predecessor  Certificates) is registered
     at the close of  business  on the Record Date  immediately  preceding  such
     Payment  Date in such coin or currency of the United  States as at the time
     of payment  shall be legal tender for  payments.  The  Contract  Adjustment
     Payments,  if any,  will be payable  at the  office in New York,  New York,
     maintained  for that  purpose  or, at the option of the  Company,  by check
     mailed to the  address of the  Person  entitled  thereto  at such  Person's
     address as it appears on the  Register  or by wire  transfer to the account
     designated to the Agent by a prior written notice by such Person  delivered
     at least five Business Days prior to the applicable Payment Date.

          (b)  Upon  the  occurrence  of  a  Termination  Event,  the  Company's
     obligation  to pay  Contract  Adjustment  Payments  (including  any accrued
     Deferred Contract Adjustment Payments), if any, shall cease.

          (c) Each Certificate  delivered under this Agreement upon registration
     of transfer of or in exchange for or in lieu of (including as a result of a
     Collateral  Substitution  or the  re-establishment  of an Equity  Unit) any
     other Certificate shall carry the rights to Contract  Adjustment  Payments,
     if any, accrued and unpaid, and to accrue Contract Adjustment Payments,  if
     any, which were carried by the Forward Purchase  Contracts  underlying such
     other Certificates.

          (d) Subject to Sections 5.9 and 5.10,  in the case of any Equity Units
     or  Stripped  Units,  as the  case may be,  with  respect  to  which  Early
     Settlement or Merger Early  Settlement of the underlying  Forward  Purchase
     Contract  is  effected  on an  Early  Settlement  Date  or a  Merger  Early
     Settlement  Date,  respectively,  or in respect of which Cash Settlement of
     the  underlying  Forward  Purchase  Contract  is  effected  on the  seventh
     Business Day immediately preceding the Stock Purchase Date, or with respect
     to which a Collateral  Substitution or an establishment or re-establishment
     of an Equity Units pursuant to Section 3.14 is effected,  in each case on a
     date that is after any Record  Date and on or prior to the next  succeeding
     Payment Date, Contract Adjustment Payments on the Forward Purchase Contract
     underlying  such  Equity  Units  or  Stripped  Units,  as the  case may be,
     otherwise  payable on such  Payment  Date shall be payable on such  Payment
     Date notwithstanding such Cash Settlement,  Early Settlement,  Merger Early
     Settlement, Collateral Substitution or establishment or re-establishment of
     Equity Units,  and such Contract  Adjustment  Payments shall be paid to the
     Person  in whose  name the  Certificate  evidencing  such  Equity  Units or
     Stripped Units (or one or more  Predecessor  Certificates) is registered at
     the close of business on such Record Date.  Except as  otherwise  expressly
     provided in the immediately  preceding sentence,  in the case of any Equity
     Units or  Stripped  Units  with  respect to which  Cash  Settlement,  Early
     Settlement,  Merger Early  Settlement of the  underlying  Forward  Purchase
     Contract is effected on the seventh Business Day immediately  preceding the
     Stock Purchase Date, an Early  Settlement  Date or Merger Early  Settlement
     Date,  as  the  case  may  be,  or  with  respect  to  which  a  Collateral
     Substitution or an establishment or  re-establishment of an Equity Unit has
     been effected,  Contract Adjustment Payments,  if any, that would otherwise
     be payable  after the Early  Settlement  Date,  or Merger Early  Settlement
     Date,  Collateral  Substitution or such  establishment or  re-establishment
     with respect to such Forward Purchase Contract shall not be payable.

     Section 5.3 Deferral of Contract Adjustment Payments.
     -----------------------------------------------------

          (a) The Company  shall have the right,  at any time prior to the Stock
     Purchase  Date,  to  defer  the  payment  of any  or  all  of the  Contract
     Adjustment  Payments otherwise payable on any Payment Date, but only if the
     Company shall give the Holders and the Agent written notice of its election
     to defer each such deferred  Contract  Adjustment  Payment  (specifying the
     amount to be deferred)  at least ten Business  Days prior to the earlier of
     (i) the next  succeeding  Payment  Date or (ii) the  date  the  Company  is
     required to give notice of the Record Date or Payment  Date with respect to
     payment  of  such  Contract  Adjustment  Payments  to  the  NYSE  or  other
     applicable  self-regulatory  organization or to Holders of the Equity Units
     and Stripped  Units,  but in any event not less than one Business Day prior
     to such Record Date. Any Contract Adjustment Payments so deferred shall, to
     the extent permitted by law, bear additional  Contract  Adjustment Payments
     thereon at the rate of 5.75% per year  (computed  on the basis of a 360-day
     year of twelve 30-day months), compounding on each succeeding Payment Date,
     until paid in full  (such  deferred  installments  of  Contract  Adjustment
     Payments, if any, together with the additional Contract Adjustment Payments
     accrued  thereon,  being  referred  to  herein  as the  "Deferred  Contract
     Adjustment Payments"). Deferred Contract Adjustment Payments, if any, shall
     be due on the next  succeeding  Payment  Date  except  to the  extent  that
     payment is deferred  pursuant to this Section  5.3. No Contract  Adjustment
     Payments  may be deferred to a date that is after the Stock  Purchase  Date
     and no such  deferral  period may end other than on a Payment  Date. If the
     Forward  Purchase  Contracts  are  terminated  upon  the  occurrence  of  a
     Termination  Event,  the  Holder's  right to  receive  Contract  Adjustment
     Payments,   if  any,  and  Deferred  Contract  Adjustment  Payments,   will
     terminate.  If Deferred Contract Adjustment Payments are deferred until the
     Stock Purchase Date, all payments in respect  thereof shall be made in cash
     on the Stock Purchase Date.

          (b) In the event  that the  Company  elects to defer  the  payment  of
     Contract  Adjustment  Payments on the Forward  Purchase  Contracts  until a
     Payment Date prior to the Stock Purchase Date,  then all Deferred  Contract
     Adjustment Payments,  if any, shall be payable to the registered Holders as
     of the close of  business  on the Record Date  immediately  preceding  such
     Payment Date.

          (c) In the event the Company exercises its option to defer the payment
     of  Contract   Adjustment   Payments  then,  until  the  Deferred  Contract
     Adjustment  Payments  have been paid,  the Company shall not declare or pay
     dividends on, make  distributions  with respect to, or redeem,  purchase or
     acquire,  or  make  a  liquidation  payment  with  respect  to,  any of the
     Company's Common Stock other than:

               (i)  purchases,  redemptions or  acquisitions of shares of Common
                    Stock in connection  with any employment  contract,  benefit
                    plan or other similar arrangement with or for the benefit of
                    employees,  officers  or  directors  or a stock  purchase or
                    dividend  reinvestment  plan,  or  the  satisfaction  by the
                    Company  of its  obligations  pursuant  to any  contract  or
                    security  outstanding on the date the Company  exercises its
                    right to defer the Contract Adjustment Payments;

               (ii) as a result of a  reclassification  of the Company's Capital
                    Stock or the exchange or  conversion  of one class or series
                    of the  Company's  Capital Stock for another class or series
                    of the Company's Capital Stock;

               (iii)the  purchase of  fractional  interests  of the Common Stock
                    pursuant to the  conversion  or exchange  provisions of such
                    Common Stock or the security being converted or exchanged;

               (iv) dividends or  distributions  in any series of the  Company's
                    Common  Stock  (or  rights  to  acquire   Common  Stock)  or
                    repurchases,  acquisitions or redemptions of Common Stock in
                    connection with the issuance or exchange of the Common Stock
                    (or securities  convertible  into or exchangeable for shares
                    of the Company's Common Stock); or

               (v)  redemptions,   exchanges  or   repurchases   of  any  rights
                    outstanding   under  a   shareholder   rights  plan  or  the
                    declaration   or  payment   thereunder   of  a  dividend  or
                    distribution of or with respect to rights in the future.

     Section 5.4 Payment of Purchase Price; Remarketing.
     ---------------------------------------------------

          (a) Unless a Tax Event Redemption, successful remarketing, Termination
     Event,  Merger Early  Settlement or Early  Settlement  has  occurred,  each
     Holder of an Equity Unit may pay in cash ("Cash  Settlement")  the Purchase
     Price for the shares of Common Stock to be purchased  pursuant to a Forward
     Purchase  Contract if such Holder  notifies the Agent by use of a notice in
     substantially  the form of Exhibit E hereto of its intention to make a Cash
     Settlement.  Such notice  shall be made on or prior to 5:00 p.m.,  New York
     City  time,  on the tenth  Business  Day  immediately  preceding  the Stock
     Purchase Date. The Agent shall promptly notify the Collateral  Agent of the
     receipt of such a notice from a Holder intending to make a Cash Settlement.

               (i)  A Holder of an Equity Unit who has so notified  the Agent of
                    its  intention to make a Cash  Settlement is required to pay
                    the Purchase  Price to the  Collateral  Agent prior to 11:00
                    a.m.,  New York  City  time,  on the  seventh  Business  Day
                    immediately  preceding  the  Stock  Purchase  Date in lawful
                    money of the United  States by certified or cashiers'  check
                    or wire transfer,  in each case payable to or upon the order
                    of the Company.  Any cash received by the  Collateral  Agent
                    will be paid to the  Company on the Stock  Purchase  Date in
                    settlement  of the Forward  Purchase  Contract in accordance
                    with the terms of this Agreement and the Pledge Agreement.

               (ii) If a Holder of an Equity  Unit  fails to notify the Agent of
                    its intention to make a Cash  Settlement in accordance  with
                    this  paragraph  (a),  the  Holder  shall be  deemed to have
                    consented to the  disposition  of the Pledged Notes pursuant
                    to the  remarketing as described in paragraph  5.4(b) below.
                    If a Holder  of an  Equity  Unit  does  notify  the Agent as
                    provided in this  paragraph  (a) of its intention to pay the
                    Purchase  Price in cash,  but fails to make such  payment as
                    required by  paragraph  (a)(i)  above,  the Holder  shall be
                    deemed to have  consented to the  disposition of the Pledged
                    Notes pursuant to the  remarketing as described in paragraph
                    5.4 (b) below.

          (b) The Company has engaged the Remarketing Agent to sell the Notes of
     (A) Holders of Equity  Units,  other than  Holders that have elected not to
     participate  in the  remarketing  pursuant to the  procedures  set forth in
     subsection  (g) below,  and (B) holders of Separate Notes that have elected
     to participate in the  remarketing  pursuant to the procedures set forth in
     Section 4.5(d) of the Pledge  Agreement.  On the seventh Business Day prior
     to the  Remarketing  Date, the Agent shall give Holders of Equity Units and
     holders of  Separate  Notes  notice of the  remarketing  (the form of which
     notice to be provided by the  Company) in a daily  newspaper in the English
     language of general  circulation in The City of New York, which is expected
     to be The  Wall  Street  Journal,  including  the  specific  U.S.  Treasury
     security or  securities  (including  the CUSIP number  and/or the principal
     terms of such Treasury security or securities)  described in subsection (g)
     below,  that must be delivered by Holders of Equity Units that elect not to
     participate in the  remarketing  pursuant to subsection (g) below, no later
     than 10:00 a.m.,  New York City time, on the fourth  Business Day preceding
     the Remarketing Date or the first day of any Subsequent Remarketing Period,
     as applicable.  The Agent shall notify,  by 10:00 a.m., New York City time,
     on the third Business Day preceding the  Remarketing  Date or the first day
     of any subsequent Remarketing Period, as applicable,  the Remarketing Agent
     and the Collateral  Agent of the aggregate  number of Notes of Equity Units
     Holders to be remarketed.  On the third Business Day immediately  preceding
     the Remarketing Date or the first day of any subsequent Remarketing Period,
     as applicable,  no later than by 10:00 a.m. New York City time, pursuant to
     the terms of the Pledge  Agreement,  the  Custodial  Agent will  notify the
     Remarketing  Agent  of  the  aggregate  number  of  Separate  Notes  to  be
     remarketed. On the third Business Day immediately preceding the Remarketing
     Date or the first day of any subsequent  Remarketing Period, as applicable,
     the Collateral Agent and the Custodial Agent,  pursuant to the terms of the
     Pledge Agreement, will deliver for remarketing to the Remarketing Agent all
     Notes to be remarketed.

          (c) Upon receipt of such notice from the Agent and the Custodial Agent
     and such Notes  from the  Collateral  Agent and the  Custodial  Agent,  the
     Remarketing  Agent will,  on the  Remarketing  Date,  use its  commercially
     reasonable  best efforts to (i)  establish a rate of interest  that, in the
     opinion of the  Remarketing  Agent,  will,  when applied to the outstanding
     Notes,  enable the then current aggregate market value of the Notes to have
     a  value  equal  to  approximately,  but  not  less  than,  100.25%  of the
     Remarketing  Value  as of the  Remarketing  Date  or as of  any  Subsequent
     Remarketing  Date, as the case may be (the "Reset Rate") and (ii) sell such
     Notes on such date at a price  equal to  approximately,  but not less than,
     100.25% of the Remarketing Value.

          (d)  If the  remarketing  occurs  prior  to the  fourth  Business  Day
     preceding  the Stock  Purchase  Date,  the  Remarketing  Agent will use the
     proceeds from a successful  remarketing  to purchase the  appropriate  U.S.
     Treasury securities (the "Agent-purchased Treasury Consideration") with the
     CUSIP numbers,  if any,  selected by the  Remarketing  Agent,  described in
     clauses (1) and (2) of the definition of  Remarketing  Value related to the
     Notes of Holders of Equity  Units or that were  remarketed.  On or prior to
     the third  Business Day following the  Remarketing  Date or any  Subsequent
     Remarketing Date the Remarketing  Agent shall deliver such  Agent-purchased
     Treasury  Consideration  to the Agent,  which shall thereupon  deliver such
     Agent-purchased   Treasury  Consideration  to  the  Collateral  Agent.  The
     Collateral Agent, for the benefit of the Company, will thereupon apply such
     Agent-purchased  Treasury  Consideration,  in  accordance  with the  Pledge
     Agreement,  to secure such Holders'  obligations under the Forward Purchase
     Contracts.  If the  remarketing  occurs on or after the fourth Business Day
     preceding the Stock Purchase Date, the proceeds of the remarketing will not
     be used to purchase the Agent-purchased  Treasury  Consideration,  but such
     proceeds will be paid to the Agent in direct  settlement of the obligations
     of the Holders  under the related  Forward  Purchase  Contracts to purchase
     Common  Stock of the  Company.  The  Remarketing  Agent  will  deduct  as a
     remarketing  fee an amount not  exceeding  25 basis  points  (0.25%) of the
     total  proceeds  from  the  remarketing   (the   "Remarketing   Fee").  The
     Remarketing Agent will remit (1) the remaining portion of the proceeds from
     the  remarketing  attributable to the Separate Notes to the Custodial Agent
     for the benefit of the holders of Separate  Notes that were  remarketed and
     (2) the  remaining  portion of the  proceeds,  less those  proceeds used to
     purchase the Agent-purchased  Treasury  Consideration or to pay the Company
     in direct settlement of the Holders' obligations under the Forward Purchase
     Contracts, to the Agent for payment to the Holders of the Equity Units that
     were  remarketed,  all determined on a pro rata basis,  in each case, on or
     prior  to the  third  Business  Day  following  such  Remarketing  Date  or
     Subsequent Remarketing Date. Holders whose Notes are so remarketed will not
     otherwise  be  responsible  for  the  payment  of  any  Remarketing  Fee in
     connection therewith.

          (e)
               (i)  If,  in spite  of using  its  commercially  reasonable  best
                    efforts,  the Remarketing  Agent cannot  establish the Reset
                    Rate and remarket the Notes included in the remarketing at a
                    price equal to approximately,  but not less than, 100.25% of
                    the  Remarketing  Value,  the  Remarketing  Agent will again
                    attempt to  establish  the Reset Rate and remarket the Notes
                    included   in  the   remarketing   at  a  price   equal   to
                    approximately, but not less than, 100.25% of the Remarketing
                    Value  on  each of the two  immediately  following  Business
                    Days.  If the  Remarketing  Agent cannot  remarket the Notes
                    included   in  the   remarketing   at  a  price   equal   to
                    approximately, but not less than, 100.25% of the Remarketing
                    Value on either of those days,  it will attempt to establish
                    the  Reset  Rate and  remarket  the  Notes  included  in the
                    remarketing at a price equal to approximately,  but not less
                    than,  100.25% of the Remarketing Value on each of the three
                    Business Days  immediately  preceding  June 16, 2005. If the
                    Remarketing  Agent cannot remarket the Notes included in the
                    remarketing at a price equal to approximately,  but not less
                    than, 100.25% of the Remarketing Value on any of those days,
                    it will attempt to establish the Reset Rate and remarket the
                    Notes  included  in the  remarketing  at a  price  equal  to
                    approximately, but not less than, 100.25% of the Remarketing
                    Value  on  each  of  the  three  Business  Days  immediately
                    preceding  July 16, 2005.  If the  Remarketing  Agent cannot
                    establish the Reset Rate and remarket the Notes  included in
                    the remarketing at a price equal to  approximately,  but not
                    less than, 100.25% of the Remarketing Value either on any of
                    the two Business Days immediately  following the Remarketing
                    Date  or on any  of  the  three  Business  Days  immediately
                    preceding June 16, 2005 or on any of the three Business Days
                    immediately preceding July 16, 2005, the remarketing in each
                    period  will be  deemed  to have  failed  (each,  a  "Failed
                    Remarketing"). If the Remarketing Agent cannot establish the
                    Reset  Rate  and   remarket   the  Notes   included  in  the
                    remarketing at a price equal to approximately,  but not less
                    than,  100.25% of the Remarketing  Value on any of the three
                    Business  Days  immediately  preceding  July 16,  2005,  the
                    Remarketing  Agent will  further  attempt to  establish  the
                    Reset  Rate  and   remarket   the  Notes   included  in  the
                    remarketing at a price equal to approximately,  but not less
                    than,  100.25% of the Remarketing Value on each of the three
                    Business Days immediately  preceding August 12, 2005. If, in
                    spite of using its commercially reasonable best efforts, the
                    Remarketing Agent fails to remarket the Notes underlying the
                    Equity Units at a price equal to approximately, but not less
                    than,  100.25% of the  Remarketing  Value in accordance with
                    the terms of the Pledge  Agreement  by 4:00  p.m.,  New York
                    City time, on the third Business Day  immediately  preceding
                    the Stock Purchase Date, a "Last Failed Remarketing" will be
                    deemed to have occurred.

               (ii) Within three  Business  Days  following  the end of the Last
                    Failed  Remarketing,  the Remarketing Agent shall return any
                    Notes  delivered  to it to  the  Collateral  Agent  and  the
                    Custodial Agent, as applicable, together with written notice
                    from the Remarketing Agent of such Last Failed  Remarketing.
                    The Collateral  Agent,  for the benefit of the Company,  may
                    exercise its rights as a secured  party with respect to such
                    Notes,  including those actions  specified in Section 5.4(f)
                    below,  and the Holders of Equity Units, by their acceptance
                    of the Equity  Units  shall be deemed to have agreed to such
                    exercise  by the  Collateral  Agent in such case;  provided,
                    that if upon the Last  Failed  Remarketing,  the  Collateral
                    Agent delivers any Notes to the Company in full satisfaction
                    of  the  Holder's   obligation  under  the  related  Forward
                    Purchase  Contracts,  any accumulated and unpaid interest on
                    such Notes will  become  payable by the Company to the Agent
                    for payment to the Holder of the Equity  Units to which such
                    Notes relate. Such payment will be made by the Company on or
                    prior to  11:00  a.m.,  New York  City  time,  on the  Stock
                    Purchase  Date in  lawful  money  of the  United  States  by
                    certified or cashier's check or wire transfer in immediately
                    available  funds  payable to or upon the order of the Agent.
                    The Company  will publish  notice by means of Bloomberg  and
                    Reuters newswires of any Remarketing  Period during which no
                    successful remarketing occurred, such notice to be published
                    not later than the fourth  Business Day following the end of
                    such  Remarketing  Period.  The  Company  will also  cause a
                    notice of the Last Failed Remarketing to be published on the
                    fourth  Business Day  following  the date of the Last Failed
                    Remarketing in a daily newspaper in the English  language of
                    general  circulation  in The  City  of New  York,  which  is
                    expected to be The Wall Street Journal.

          (f) With  respect to any Notes which  constitute  part of Equity Units
     which are subject to the Last Failed Remarketing,  the Collateral Agent for
     the benefit of the Company  reserves  all of its rights as a secured  party
     with respect  thereto and,  subject to  applicable  law and Section 5.4 (j)
     below, may, among other things, permit the Company to cause the Notes to be
     sold  or to  retain  and  cancel  such  Notes,  in  either  case,  in  full
     satisfaction  of  the  Holders'  obligations  under  the  Forward  Purchase
     Contracts and the Holders of the Equity Units,  by their  acceptance of the
     Equity  Units  shall  be  deemed  to  have  agreed  to such  action  by the
     Collateral Agent.

          (g) A Holder of Equity  Units  may  elect  not to  participate  in the
     remarketing and retain the Notes  underlying such Equity Units by notifying
     the Agent of such  election  and  delivering  the  specific  U.S.  Treasury
     security or  securities  (including  the CUSIP number  and/or the principal
     terms  of  such  security  or  securities)  identified  by the  Agent  that
     constitute the U.S. Treasury securities described in clauses (1) and (2) of
     the definition of  Remarketing  Value relating to the retained Notes (as if
     only  such  Notes   were   being   remarketed)   (the   "Opt-out   Treasury
     Consideration")  to the Agent not  later  than  10:00  a.m.  on the  fourth
     Business  Day prior to the  Remarketing  Date (or,  in the case of a Failed
     Remarketing,  not  later  than  10:00  a.m.  on  the  fourth  Business  Day
     immediately  prior to the  subsequent  Remarketing  Period).  Upon  receipt
     thereof  by the  Agent,  the Agent  shall  deliver  such  Opt-out  Treasury
     Consideration to the Collateral  Agent,  which will, for the benefit of the
     Company, thereupon apply such Opt-out Treasury Consideration to secure such
     Holder's  obligations  under the Forward Purchase  Contracts.  On the first
     Business Day immediately preceding the Remarketing Date (or, in the case of
     a Failed Remarketing,  the subsequent  Remarketing  Period), the Collateral
     Agent,  pursuant  to the terms of the Pledge  Agreement,  will  deliver the
     Pledged  Notes of such  Holder to the Agent.  Within  three  Business  Days
     following any  Remarketing  Period,  (A) if the remarketing was successful,
     the Agent shall distribute such Notes to the new holders  thereof,  and (B)
     if there was a Failed Remarketing, the Agent will deliver such Notes to the
     Collateral  Agent,  which will,  for the benefit of the Company,  thereupon
     apply such Notes to secure  such  Holders'  obligations  under the  Forward
     Purchase Contracts and return the Opt-out Treasury Consideration  delivered
     by such  Holders to such  Holders.  A Holder  that does not so deliver  the
     Opt-out Treasury  Consideration pursuant to this clause (g) shall be deemed
     to have elected to participate in the remarketing.

          (h) Upon the maturity of the Pledged  Treasury  Securities  underlying
     the  Stripped  Units and the  Pledged  Treasury  Consideration  or  Pledged
     Applicable  Ownership Interest in the Treasury  Portfolio,  as the case may
     be, underlying the Equity Units, on the Stock Purchase Date, the Collateral
     Agent shall remit to the Company an amount equal to the aggregate  Purchase
     Price  applicable to such Units,  as payment for the Common Stock  issuable
     upon settlement thereof without receiving any instructions from the Holders
     of such Units. In the event the payments in respect of the Pledged Treasury
     Securities,  Pledged Treasury Consideration or Pledged Applicable Ownership
     Interest in the Treasury  Portfolio  underlying a Unit are in excess of the
     Purchase Price under the Forward  Purchase  Contract being settled thereby,
     the  Collateral  Agent  will  distribute  such  excess to the Agent for the
     benefit of the Holder of such Units when received.

               (i)  Any  distribution  to Holders of excess  funds and  interest
                    described  in Section  5.4(c) and (d) above shall be payable
                    at  the  Office  of  the  Agent  in The  City  of  New  York
                    maintained  for that purpose or, at the option of the Holder
                    or the holder of Separate  Notes,  as  applicable,  by check
                    mailed to the address of the Person entitled thereto at such
                    address as it appears on the  relevant  Register  or by wire
                    transfer to an account specified by the Holder or the holder
                    of Separate Notes, as applicable.

          (j) The  obligations  of each  Holder  to pay the  Purchase  Price are
     non-recourse  obligations and except to the extent paid by Cash Settlement,
     Early Settlement or Merger Early Settlement,  are payable solely out of the
     proceeds of any Collateral pledged to secure the obligations of the Holder,
     and in no event will any Holder be liable for any  deficiency  between such
     proceeds and the Purchase Price.

          (k) Notwithstanding anything to the contrary herein, the Company shall
     not be obligated to issue any Common Stock in respect of a Forward Purchase
     Contract or deliver any certificates  therefor to the Holder of the related
     Equity  Units or  Stripped  Units,  as the case may be,  unless the Company
     shall have  received  payment in full for the shares of Common  Stock to be
     purchased thereunder by such Holder in the manner herein set forth.

          (l) In the event of a successful remarketing, the interest rate on all
     of the outstanding Notes (whether or not included in the remarketing) shall
     be adjusted to the Reset Rate.

Section 5.5 Issuance of Shares of Common Stock.
- -----------------------------------------------

     Unless a  Termination  Event  shall have  occurred on or prior to the Stock
Purchase  Date or an Early  Settlement or a Merger Early  Settlement  shall have
occurred with respect to all of the  outstanding  Units,  on the Stock  Purchase
Date,  upon its receipt of payment for the shares of Common  Stock  purchased by
the Holders  pursuant to the  provisions  of this Article and subject to Section
5.4, the Company shall issue and deposit with the Agent,  for the benefit of the
Holders  of the  Outstanding  Units,  one or  more  certificates  or  book-entry
interests representing the newly issued shares of Common Stock registered in the
name  of the  Agent  (or  its  nominee)  as  custodian  for  the  Holders  (such
certificates or book-entry  interests for shares of Common Stock,  together with
any dividends or distributions for which a record date and payment date for such
dividend or  distribution  has occurred  after the Stock  Purchase  Date,  being
hereinafter  referred to as the "Forward Purchase Contract  Settlement Fund") to
which the  Holders  are  entitled  hereunder.  Subject  to the  foregoing,  upon
surrender of a  Certificate  to the Agent on or after the Stock  Purchase  Date,
together with settlement  instructions thereon duly completed and executed,  the
Holder of such Certificate  shall be entitled to receive in exchange  therefor a
certificate or book-entry  interest  representing that number of whole shares of
Common Stock which such Holder is entitled to receive pursuant to the provisions
of this Article V (after taking into account all Equity Units and Stripped Units
then held by such Holder)  together  with cash in lieu of  fractional  shares as
provided in Section 5.12 and any dividends or distributions with respect to such
shares  constituting part of the Forward Purchase Contract  Settlement Fund, but
without any interest thereon, and the Certificate so surrendered shall forthwith
be  cancelled.  Such shares shall be registered in the name of the Holder or the
Holder's  designee as specified in the settlement  instructions  provided by the
Holder to the  Agent.  If any  shares of Common  Stock  issued in  respect  of a
Forward Purchase Contract are to be registered to a Person other than the Person
in whose name the  Certificate  evidencing  such  Forward  Purchase  Contract is
registered, no such registration shall be made unless the Person requesting such
registration  has paid any transfer  and other taxes  required by reason of such
registration  in a name  other  than  that  of the  registered  Holder  of  such
Certificate or has established to the  satisfaction of the Company that such tax
either has been paid or is not payable.


Section 5.6 Adjustment of Settlement Rate.
- ------------------------------------------

          (a) Adjustments for Dividends, Distributions, Stock Splits, Etc.

               (1)  Stock  Dividends.  In case the  Company  shall pay or make a
          dividend or other  distribution  on the Common Stock in Common  Stock,
          the Settlement  Rate or Early  Settlement  Rate, as applicable,  as in
          effect at the opening of business on the day  following the date fixed
          for  the  determination  of  stockholders  entitled  to  receive  such
          dividend or other  distribution  shall be increased  by dividing  such
          Settlement  Rate or Early  Settlement  Rate by a fraction of which the
          numerator shall be the number of shares of Common Stock outstanding at
          the close of business on the date fixed for such determination and the
          denominator  shall be the sum of such  number of shares  and the total
          number of shares  constituting  such  dividend or other  distribution,
          such  increase to become  effective  immediately  after the opening of
          business on the day following  the date fixed for such  determination.
          For the purposes of this paragraph (1), the number of shares of Common
          Stock at the time  outstanding  shall not  include  shares held in the
          treasury  of the  Company  but shall  include  any shares  issuable in
          respect  of any  scrip  certificates  issued in lieu of  fractions  of
          shares of Common Stock.  The Company will not pay any dividend or make
          any distribution on shares of Common Stock held in the treasury of the
          Company.

               (2)  Stock  Purchase  Rights.  In case the  Company  shall  issue
          rights,  options or warrants  to all holders of its Common  Stock (not
          being available on an equivalent  basis to Holders of the Equity Units
          and Stripped Units upon settlement of the Forward  Purchase  Contracts
          underlying  such Equity Units and Stripped  Units)  entitling  them to
          subscribe for or purchase  shares of Common Stock at a price per share
          less than the Current  Market  Price per share of the Common  Stock on
          the date  fixed for the  determination  of  stockholders  entitled  to
          receive such  rights,  options or warrants  (other than  pursuant to a
          dividend reinvestment, share purchase or similar plan), the Settlement
          Rate or Early Settlement Rate, as applicable, in effect at the opening
          of business on the day following the date fixed for such determination
          shall  be  increased  by  dividing  such   Settlement  Rate  or  Early
          Settlement Rate, as applicable,  by a fraction, the numerator of which
          shall be the number of shares of Common Stock outstanding at the close
          of business on the date fixed for such  determination  plus the number
          of shares of Common Stock which the aggregate of the offering price of
          the total number of shares of Common Stock so offered for subscription
          or  purchase  would  purchase  at such  Current  Market  Price and the
          denominator  of which  shall be the  number of shares of Common  Stock
          outstanding  at the  close  of  business  on the date  fixed  for such
          determination plus the number of shares of Common Stock so offered for
          subscription   or  purchase,   such   increase  to  become   effective
          immediately  after the opening of business  on the day  following  the
          date fixed for such determination.  For the purposes of this paragraph
          (2),  the  number of shares  of Common  Stock at any time  outstanding
          shall not include shares held in the treasury of the Company but shall
          include  any shares  issuable  in  respect  of any scrip  certificates
          issued in lieu of  fractions  of shares of Common  Stock.  The Company
          shall not issue any such  rights,  options or  warrants  in respect of
          shares of Common Stock held in the treasury of the Company.

               (3) Stock Splits;  Reverse Splits. In case outstanding  shares of
          Common  Stock shall be  subdivided  or split into a greater  number of
          shares of Common Stock,  the Settlement Rate or Early Settlement Rate,
          as  applicable,  in  effect  at the  opening  of  business  on the day
          following  the day  upon  which  such  subdivision  or  split  becomes
          effective shall be proportionately increased, and, conversely, in case
          outstanding  shares of Common  Stock shall be combined  into a smaller
          number  of  shares  of  Common  Stock,  the  Settlement  Rate or Early
          Settlement  Rate, as applicable,  in effect at the opening of business
          on the day  following  the day upon  which  such  combination  becomes
          effective  shall  be   proportionately   reduced,   such  increase  or
          reduction,  as the case may be, to become effective  immediately after
          the opening of business on the day  following  the day upon which such
          subdivision, split or combination becomes effective.

               (4) Debt or Asset Distributions.

               (i)  In  case  the  Company  shall,  by  dividend  or  otherwise,
                    distribute  to all holders of its Common Stock  evidences of
                    its  indebtedness  or  assets  (including  securities,   but
                    excluding  any rights or warrants  referred to in  paragraph
                    (2) of this  Section,  any  dividend  or  distribution  paid
                    exclusively  in cash and any  dividend,  shares  of  capital
                    stock of any class or series,  or similar equity  interests,
                    of or relating to a subsidiary or other business unit in the
                    case of a Spin-Off  referred  to in the next  paragraph,  or
                    distribution  referred to in paragraph (1) of this Section),
                    the Settlement Rate or Early Settlement Rate, as applicable,
                    shall be  adjusted  so that the same  shall  equal  the rate
                    determined  by  dividing  the   Settlement   Rate  or  Early
                    Settlement Rate, as applicable,  in effect immediately prior
                    to  the  close  of  business  on  the  date  fixed  for  the
                    determination  of  stockholders  entitled  to  receive  such
                    distribution by a fraction,  the numerator of which shall be
                    the Current  Market  Price per share of the Common  Stock on
                    the date  fixed  for such  determination  less the then fair
                    market value (as determined by the Board of Directors, whose
                    determination  shall be conclusive  and described in a Board
                    Resolution)  of the  portion of the assets or  evidences  of
                    indebtedness  so  distributed  applicable  to one  share  of
                    Common  Stock  and the  denominator  of which  shall be such
                    Current  Market  Price per share of the Common  Stock,  such
                    adjustment  to  become  effective  immediately  prior to the
                    opening of business on the day  following the date fixed for
                    the  determination of stockholders  entitled to receive such
                    distribution.  In any case in which  this  paragraph  (4) is
                    applicable,  paragraph  (2) of  this  Section  shall  not be
                    applicable.

               (ii) In the  case of a  Spin-Off,  the  Settlement  Rate or Early
                    Settlement Rate, as applicable, in effect immediately before
                    the  close  of   business  on  the  record  date  fixed  for
                    determination  of  stockholders  entitled  to  receive  that
                    distribution will be increased by multiplying the Settlement
                    Rate or Early Settlement Rate, as applicable, by a fraction,
                    the numerator of which is the Current Market Price per share
                    of the  Common  Stock  plus  the  Fair  Market  Value of the
                    portion of those shares of Capital  Stock or similar  equity
                    interests so  distributed  applicable to one share of Common
                    Stock and the  denominator  of which is the  Current  Market
                    Price per share of the Common Stock.  Any  adjustment to the
                    Settlement   Rate  or  Early   Settlement  Rate  under  this
                    paragraph  4(ii) will occur at the  earlier of (1) the tenth
                    Trading Day from, and  including,  the effective date of the
                    Spin-Off and (2) the date of the securities being offered in
                    the Initial Public Offering of the Spin-Off, if that Initial
                    Public   Offering  is  effected   simultaneously   with  the
                    Spin-Off.

               (5)  Cash  Distributions.  In  case  the  Company  shall,  (i) by
          dividend or  otherwise,  distribute to all holders of its Common Stock
          cash (excluding any cash that is distributed in a Reorganization Event
          to which Section 5.6(b) applies or as part of a distribution  referred
          to in  paragraph  (4) of this  Section) in an  aggregate  amount that,
          combined  together  with  (ii)  the  aggregate  amount  of  any  other
          distributions  to all holders of its Common Stock made  exclusively in
          cash  within  the 12  months  preceding  the date of  payment  of such
          distribution  and in respect of which no  adjustment  pursuant to this
          paragraph (5) or paragraph (6) of this Section has been made and (iii)
          the aggregate of any cash plus the fair market value as of the date of
          the  expiration of the tender or exchange  offer referred to below (as
          determined by the Board of  Directors,  whose  determination  shall be
          conclusive  and  described  in a Board  Resolution)  of  consideration
          payable in respect of any tender or  exchange  offer by the Company or
          any of its  subsidiaries  for all or any  portion of the Common  Stock
          concluded  within the 12 months  preceding  the date of payment of the
          distribution  described in clause (i) above and in respect of which no
          adjustment  pursuant to this  paragraph  (5) or paragraph  (6) of this
          Section  has been made,  exceeds  15% of the  product  of the  Current
          Market  Price  per  share  of the  Common  Stock  on the  date for the
          determination of holders of shares of Common Stock entitled to receive
          such  distribution   times  the  number  of  shares  of  Common  Stock
          outstanding  on such date,  then,  and in each such case,  immediately
          after  the  close of  business  on such  date for  determination,  the
          Settlement  Rate or Early  Settlement  Rate, as  applicable,  shall be
          increased so that the same shall equal the rate determined by dividing
          the Settlement Rate or Early Settlement Rate, as applicable, in effect
          immediately  prior to the  close of  business  on the date  fixed  for
          determination   of  the   stockholders   entitled   to  receive   such
          distribution  by a fraction (A) the  numerator of which shall be equal
          to the Current  Market Price per share of the Common Stock on the date
          fixed for such  determination  less an amount equal to the quotient of
          (x) the combined  amount  distributed  or payable in the  transactions
          described in clauses  (i),  (ii) and (iii) above and (y) the number of
          shares of Common Stock  outstanding on such date for determination and
          (B) the  denominator  of which  shall be equal to the  Current  Market
          Price per share of the Common Stock on such date for determination.

               (6) Tender Offers. In case (i) a tender or exchange offer made by
          the Company or any subsidiary of the Company for all or any portion of
          the Common  Stock shall  expire and such tender or exchange  offer (as
          amended  upon the  expiration  thereof)  shall  require the payment to
          stockholders  (based on the acceptance (up to any maximum specified in
          the terms of the tender or exchange offer) of Purchased  Shares) of an
          aggregate  consideration  having a fair market value (as determined by
          the Board of Directors,  whose  determination  shall be conclusive and
          described in a Board  Resolution) that combined together with (ii) the
          aggregate of the cash plus the fair market value (as determined by the
          Board  of  Directors,  whose  determination  shall be  conclusive  and
          described in a Board Resolution),  as of the expiration of such tender
          or exchange  offer, of  consideration  payable in respect of any other
          tender or  exchange  offer,  by the Company or any  subsidiary  of the
          Company for all or any portion of the Common Stock expiring within the
          12 months  preceding the  expiration of such tender or exchange  offer
          and in respect of which no  adjustment  pursuant to  paragraph  (5) of
          this  Section  or this  paragraph  (6) has  been  made and  (iii)  the
          aggregate amount of any  distributions to all holders of the Company's
          Common Stock made  exclusively in cash within the 12 months  preceding
          the  expiration  of such  tender or  exchange  offer and in respect of
          which no adjustment  pursuant to paragraph (5) of this Section or this
          paragraph (6) has been made, exceeds 15% of the product of the Current
          Market  Price per share of the  Common  Stock as of the last time (the
          "Expiration  Time")  tenders  could  have been made  pursuant  to such
          tender or exchange  offer (as it may be  amended)  times the number of
          shares of Common Stock outstanding  (including any tendered shares) at
          the Expiration Time, then, and in each such case, immediately prior to
          the opening of  business  on the day after the date of the  Expiration
          Time, the  Settlement  Rate or Early  Settlement  Rate, as applicable,
          shall be adjusted so that the same shall equal the rate  determined by
          dividing the Settlement Rate or Early  Settlement Rate, as applicable,
          immediately  prior  to  the  close  of  business  on the  date  of the
          Expiration  Time by a fraction  (A) the  numerator  of which  shall be
          equal to (x) the product of (I) the Current  Market Price per share of
          the  Common  Stock  on the  date of the  Expiration  Time and (II) the
          number of shares of Common Stock  outstanding  (including any tendered
          shares)  at the  Expiration  Time less (y) the amount of cash plus the
          fair  market  value   (determined   as  aforesaid)  of  the  aggregate
          consideration  payable  to  stockholders  based  on  the  transactions
          described in clauses (i),  (ii) and (iii) above  (assuming in the case
          of clause (i) the acceptance, up to any maximum specified in the terms
          of the tender or exchange  offer,  of Purchased  Shares),  and (B) the
          denominator  of which shall be equal to the product of (x) the Current
          Market Price per share of the Common Stock as of the  Expiration  Time
          and (y) the number of shares of Common  Stock  outstanding  (including
          any tendered  shares) as of the Expiration Time less the number of all
          shares validly  tendered and not withdrawn as of the  Expiration  Time
          (the shares deemed so accepted, up to any such maximum, being referred
          to as the "Purchased Shares").

               (7)  Reclassification.  The reclassification of Common Stock into
          securities  including  securities  other than Common Stock (other than
          any  reclassification  upon a  Reorganization  Event to which  Section
          5.6(b)  applies) shall be deemed to involve (i) a distribution of such
          securities other than Common Stock to all holders of Common Stock (and
          the effective date of such reclassification shall be deemed to be "the
          date fixed for the  determination of stockholders  entitled to receive
          such distribution" and the "date fixed for such determination"  within
          the meaning of paragraph (4) of this Section), and (ii) a subdivision,
          split or  combination,  as the case may be, of the number of shares of
          Common Stock outstanding  immediately  prior to such  reclassification
          into the  number of shares of  Common  Stock  outstanding  immediately
          thereafter (and the effective date of such  reclassification  shall be
          deemed to be "the day upon which  such  subdivision  or split  becomes
          effective" or "the day upon which such combination becomes effective,"
          as the case may be, and "the day upon which such subdivision, split or
          combination  becomes effective" within the meaning of paragraph (3) of
          this Section).

               (8) "Current  Market  Price".  The "Current  Market Price" of the
          Common  Stock means (a) on any day the average of the Sales Prices for
          the 5  consecutive  Trading  Days  preceding  the  earlier  of the day
          preceding  the day in  question  and the day before the "ex date" with
          respect to the issuance or distribution requiring computation,  (b) in
          the  case of any  Spin-Off  that is  effected  simultaneously  with an
          Initial  Public  Offering of the securities  being  distributed in the
          Spin-Off,  the Sale Price of the Common  Stock on the  Trading  Day on
          which  the  Initial  Public  Offering  price of the  securities  being
          distributed in the Spin-Off is determined,  and (c) in the case of any
          other  Spin-Off,  the average of the Sale  Prices of the Common  Stock
          over the  first 10  Trading  Days  after  the  effective  date of such
          Spin-Off.  For  purposes of this  paragraph,  the term "ex date," when
          used with  respect to any  issuance  or  distribution,  shall mean the
          first  date on  which  the  Common  Stock  trades  regular  way on the
          relevant  exchange  or in the  relevant  market  without  the right to
          receive such issuance or distribution.

               (9) Calculation of Adjustments. All adjustments to the Settlement
          Rate or Early Settlement  Rate, as applicable,  shall be calculated to
          the nearest  1/10,000th of a share of Common Stock (or if there is not
          a nearest  1/10,000th  of a share to the next  lower  1/10,000th  of a
          share). No adjustment in the Settlement Rate or Early Settlement Rate,
          as applicable,  shall be required unless such adjustment would require
          an increase or  decrease  of at least one percent  therein;  provided,
          that any  adjustments  which by  reason of this  subparagraph  are not
          required to be made shall be carried forward and taken into account in
          any subsequent adjustment.  If an adjustment is made to the Settlement
          Rate or Early  Settlement  Rate, as applicable,  pursuant to paragraph
          (1), (2), (3), (4), (5), (6), (7) or (10) of this Section  5.6(a),  an
          adjustment shall also be made to the Applicable Market Value solely to
          determine  which of clauses (i),  (ii) or (iii) of the  definition  of
          Settlement Rate or Early  Settlement  Rate, as applicable,  in Section
          5.1(a) will apply on the Stock Purchase Date. Such adjustment shall be
          made by  multiplying  the Applicable  Market Value by a fraction,  the
          numerator of which shall be the  Settlement  Rate or Early  Settlement
          Rate, as applicable,  immediately  after such  adjustment  pursuant to
          paragraph  (1),  (2),  (3), (4), (5), (6), (7) or (10) of this Section
          5.6(a) and the  denominator of which shall be the  Settlement  Rate or
          Early  Settlement  Rate,  as  applicable,   immediately   before  such
          adjustment;  provided,  that if such adjustment to the Settlement Rate
          or Early  Settlement  Rate,  as  applicable,  is  required  to be made
          pursuant  to the  occurrence  of any of  the  events  contemplated  by
          paragraph  (1), (2), (3), (4), (5), (7) or (10) of this Section 5.6(a)
          during  the  period  taken  into  consideration  for  determining  the
          Applicable Market Value,  appropriate and customary  adjustments shall
          be  made  to  the  Settlement  Rate  or  Early   Settlement  Rate,  as
          applicable.

               (10)  Increase  of  Settlement  Rate.  The  Company may make such
          increases  in  the  Settlement  Rate  or  Early  Settlement  Rate,  as
          applicable,  in addition  to those  required  by this  Section,  as it
          considers to be advisable in order to avoid or diminish any income tax
          to any holders of shares of Common Stock  resulting  from any dividend
          or distribution of stock or issuance of rights or warrants to purchase
          or  subscribe  for stock or from any event  treated as such for income
          tax purposes or for any other reasons.

          (b)  Adjustment  for  Consolidation,  Merger  or Other  Reorganization
     Event.

               In the event of

                    (1) any  consolidation or merger of the Company with or into
               another Person (other than a merger or consolidation in which the
               Company  is the  continuing  corporation  and in which the Common
               Stock   outstanding   immediately   prior   to  the   merger   or
               consolidation  is not  exchanged  for cash,  securities  or other
               property of the Company or another corporation),

                    (2) any  sale,  transfer,  lease or  conveyance  to  another
               Person  of  the  property  of  the  Company  as  an  entirety  or
               substantially as an entirety,

                    (3) any statutory exchange of securities of the Company with
               another  Person  (other  than  in  connection  with a  merger  or
               acquisition), or

                    (4)  any  liquidation,  dissolution  or  winding  up of  the
               Company  other than as a result of or after the  occurrence  of a
               Termination Event (any such event, a "Reorganization Event"),

     each  share of Common  Stock  covered  by each  Forward  Purchase  Contract
     forming  a part of an Equity  Unit or  Stripped  Unit,  as the case may be,
     immediately  prior  to  such   Reorganization   Event  shall,   after  such
     Reorganization  Event,  be converted  for purposes of the Forward  Purchase
     Contract into the kind and amount of  securities,  cash and other  property
     receivable in such Reorganization  Event (without any interest thereon, and
     without any right to dividends or distributions thereon which have a record
     date that is prior to the Stock Purchase Date) per share of Common Stock by
     a holder of Common  Stock that (i) is not a Person  with which the  Company
     consolidated  or into which the  Company  merged or which  merged  into the
     Company or to which such sale or transfer was made, as the case may be (any
     such Person,  a  "Constituent  Person"),  or an Affiliate of a  Constituent
     Person to the extent  such  Reorganization  Event  provides  for  different
     treatment  of  Common  Stock  held  by   Affiliates   of  the  Company  and
     non-Affiliates, and (ii) failed to exercise his rights of election, if any,
     as to the kind or amount of securities,  cash and other property receivable
     upon  such  Reorganization  Event  (provided  that if the kind or amount of
     securities,  cash and other property  receivable  upon such  Reorganization
     Event is not the same for each share of Common Stock held immediately prior
     to such  Reorganization  Event by other  than a  Constituent  Person  or an
     Affiliate thereof and in respect of which such rights of election shall not
     have been exercised  ("Non-electing  Share"),  then for the purpose of this
     Section  the  kind and  amount  of  securities,  cash  and  other  property
     receivable upon such Reorganization  Event by each Non-electing Share shall
     be deemed to be the kind and amount so receivable  per share by a plurality
     of the  Non-electing  Shares).  On the Stock  Purchase Date, the Settlement
     Rate then in effect will be applied to the value on the Stock Purchase Date
     of  such  securities,  cash  or  other  property.  In the  event  of such a
     Reorganization  Event, the Person formed by such  consolidation,  merger or
     exchange or the Person which  acquires the assets of the Company or, in the
     event of a  liquidation  or  dissolution  of the Company,  the Company or a
     liquidating  trust  created in  connection  therewith,  shall  execute  and
     deliver to the Agent an agreement  supplemental  hereto  providing that the
     Holder of each  Outstanding  Unit shall have the  rights  provided  by this
     Section 5.6. Such  supplemental  agreement  shall  provide for  adjustments
     which,  for events  subsequent to the effective  date of such  supplemental
     agreement,  shall be as  nearly  equivalent  as may be  practicable  to the
     adjustments  provided for in this  Section.  The above  provisions  of this
     Section shall similarly apply to successive Reorganization Events.

Section 5.7 Notice of Adjustments and Certain Other Events.
- -----------------------------------------------------------

          (a)  Whenever  the  Settlement  Rate  or  Early  Settlement  Rate,  as
     applicable, is adjusted as herein provided, the Company shall:

               (i)  forthwith  compute the Settlement  Rate or Early  Settlement
                    Rate,  as  applicable,  and the  Applicable  Market Value in
                    accordance  with Section 5.6 and prepare and transmit to the
                    Agent an Officer's  Certificate setting forth the Settlement
                    Rate  and  the  Applicable   Market  Value,  the  method  of
                    calculation  thereof  in  reasonable  detail,  and the facts
                    requiring such  adjustment and upon which such adjustment is
                    based; and

               (ii) as soon as practicable  following the occurrence of an event
                    that requires an adjustment to the Settlement  Rate or Early
                    Settlement Rate, as applicable,  pursuant to Section 5.6 (or
                    if the Company is not aware of such  occurrence,  as soon as
                    practicable  after  becoming  so  aware),  provide a written
                    notice to the Holders of the Equity Units and Stripped Units
                    of  the   occurrence  of  such  event  and  a  statement  in
                    reasonable  detail  setting  forth  the  method by which the
                    adjustment to the Settlement Rate or Early  Settlement Rate,
                    as  applicable,   and  the   Applicable   Market  Value  was
                    determined and setting forth the adjusted Settlement Rate or
                    Early  Settlement  Rate, as  applicable,  and the Applicable
                    Market Value.

          (b)  The   Agent   shall  not  at  any  time  be  under  any  duty  or
     responsibility  to any  Holder  of  Equity  Units  and  Stripped  Units  to
     determine  whether any facts exist which may require any  adjustment of the
     Settlement Rate or Early Settlement Rate, as applicable, and the Applicable
     Market Value, or with respect to the nature or extent or calculation of any
     such adjustment when made, or with respect to the method employed in making
     the same. The Agent shall not be  accountable  with respect to the validity
     or value (or the kind or amount) of any shares of Common  Stock,  or of any
     securities or property,  which may at any time be issued or delivered  with
     respect  to  any  Forward  Purchase  Contract;   and  the  Agent  makes  no
     representation with respect thereto. The Agent shall not be responsible for
     any  failure of the  Company to issue,  transfer  or deliver  any shares of
     Common Stock pursuant to a Forward Purchase  Contract or to comply with any
     of the duties,  responsibilities  or covenants of the Company  contained in
     this Article.

Section 5.8 Termination Event; Notice.
- --------------------------------------

     The  Forward  Purchase  Contracts  and all  obligations  and  rights of the
Company and the Holders  thereunder,  including  the rights and  obligations  of
Holders to purchase Common Stock, shall immediately and automatically terminate,
without the  necessity  of any notice or action by any Holder,  the Agent or the
Company,  if, on or prior to the Stock Purchase Date, a Termination  Event shall
have occurred.  Upon and after the occurrence of a Termination Event, the Equity
Units  shall  thereafter  represent  the  right  to  receive  the  Notes  or the
appropriate  Treasury  Consideration  or  Applicable  Ownership  Interest in the
Treasury Portfolio, as the case may be, forming a part of such Equity Units, and
the Stripped Units shall thereafter  represent the right to receive the Treasury
Securities  forming a part of such  Stripped  Units,  in each case in accordance
with the provisions of Section 4.3 of the Pledge Agreement.  Upon the occurrence
of a Termination  Event,  the Company shall  promptly but in no event later than
two Business Days  thereafter  give written notice to the Agent,  the Collateral
Agent and to the Holders,  at their  addresses as they appear in the  applicable
Register.

Section 5.9 Early Settlement.
- -----------------------------

          (a) Subject to and upon compliance with the provisions of this Section
     5.9, Forward Purchase  Contracts  underlying Equity Units or Stripped Units
     may,  at the  option  of the  Holder  thereof,  be  settled  early  ("Early
     Settlement") at any time not later than 10:00 a.m. on the seventh  Business
     Day immediately preceding the Stock Purchase Date. In order to exercise the
     right to effect  Early  Settlement  with  respect to any  Forward  Purchase
     Contracts,  the Holder of the  Certificate  evidencing  the related  Equity
     Units or Stripped Units, as the case may be, shall deliver such Certificate
     to the Agent at the  Corporate  Trust Office duly  endorsed for transfer to
     the Company or in blank with the form of  Election  to Settle  Early on the
     reverse  thereof duly completed and  accompanied by payment  payable to the
     Company in immediately  available funds in an amount (the "Early Settlement
     Amount")  equal to (A) the product of (i) the Stated  Amount of such Equity
     Units or Stripped Units, as the case may be,  multiplied by (ii) the number
     of Forward Purchase  Contracts with respect to which the Holder has elected
     to effect Early Settlement,  plus (B) if such delivery is made with respect
     to any  Forward  Purchase  Contracts  during the  period  from the close of
     business on any Record Date next  preceding any Payment Date to the opening
     of  business  on  such  Payment  Date,  an  amount  equal  to the  Contract
     Adjustment  Payments,  if any, payable on such Payment Date with respect to
     such Forward Purchase Contracts; provided that no payment shall be required
     pursuant to clause (B) of this  sentence if the Company  shall have elected
     to defer the Contract  Adjustment  Payments that would otherwise be payable
     on such  Payment  Date and  further  provided  that,  at that  time,  if so
     required by the United  States  federal  securities  laws,  a  registration
     statement is in effect and a prospectus is available covering the shares of
     the Common  Stock of the Company to be  delivered in respect of the Forward
     Purchase  Contracts  being settled.  Except as provided in the  immediately
     preceding  sentence and subject to Section 5.2(d), no payment or adjustment
     shall be made upon Early Settlement of any Forward Purchase Contract on any
     Contract  Adjustment  Payments accrued on such Forward Purchase Contract or
     on account of any  dividends  on the Common  Stock  issued  upon such Early
     Settlement.  If the foregoing requirements are first satisfied with respect
     to Forward  Purchase  Contracts  underlying  any Equity  Units or  Stripped
     Units, as the case may be, at or prior to 5:00 p.m., New York City time, on
     a Business Day, such day shall be the "Early  Settlement Date" with respect
     to such  Equity  Units or Stripped  Units,  as the case may be, and if such
     requirements  are first satisfied after 5:00 p.m., New York City time, on a
     Business Day or on a day that is not a Business Day, the "Early  Settlement
     Date" with respect to such Equity Units or Stripped  Units, as the case may
     be, shall be the next succeeding Business Day.

          (b)  Holders  of  Equity  Units  may  settle  only in  units of 20 and
     integral  multiples  of 20.  If a  successful  remarketing  or a Tax  Event
     Redemption  has  occurred,  Holders  of  Stripped  Units may  effect  Early
     Settlement  pursuant  to this  Section 5.9 only in  integral  multiples  of
     32,000.

          (c) Upon Early  Settlement  of any  Forward  Purchase  Contract by the
     Holder of the related Equity Units or Stripped  Units,  as the case may be,
     the  Company  shall  issue,  and the Holder  shall be  entitled to receive,
     1.0187  shares of Common  Stock for each Equity  Unit or  Stripped  Unit on
     account of such Forward Purchase  Contract (the "Early  Settlement  Rate").
     The Early  Settlement  Rate shall be adjusted in the same manner and at the
     same time as the  Settlement  Rate is adjusted.  As promptly as practicable
     after Early Settlement of Forward Purchase Contracts in accordance with the
     provisions  of this Section 5.9, the Company  shall issue and shall deliver
     to the Agent at the Corporate Trust Office a certificate or certificates or
     book entry  interest for the full number of shares of Common Stock issuable
     upon such Early Settlement together with payment in lieu of any fraction of
     a share, as provided in Section 5.12.

          (d) No later than the third  Business Day after the  applicable  Early
     Settlement  Date the  Company  shall  cause (i) the shares of Common  Stock
     issuable upon Early Settlement of Forward  Purchase  Contracts to be issued
     and  delivered,  and (ii) the  related  Pledged  Notes or Pledged  Treasury
     Consideration  or Pledged  Applicable  Ownership  Interest in the  Treasury
     Portfolio,  in the case of Equity Units,  or the related  Pledged  Treasury
     Securities,  in the case of Stripped  Units, to be released from the Pledge
     by the  Collateral  Agent and  transferred,  in each case, to the Agent for
     delivery to the Holder thereof or the Holder's designee.

          (e) Upon Early  Settlement  of any  Forward  Purchase  Contracts,  and
     subject  to  receipt of shares of Common  Stock  from the  Company  and the
     Pledged Notes, Pledged Treasury Consideration, Pledged Applicable Ownership
     Interest in the Treasury Portfolio, or Pledged Treasury Securities,  as the
     case may be, from the Collateral Agent, as applicable,  the Agent shall, in
     accordance  with the  instructions  provided  by the Holder  thereof on the
     applicable  form  of  Election  to  Settle  Early  on  the  reverse  of the
     Certificate  evidencing the related Equity Units or Stripped  Units, as the
     case may be, (i) transfer to the Holder the Pledged Notes, Pledged Treasury
     Consideration,  Pledged  Applicable  Ownership  Interest  in  the  Treasury
     Portfolio,  or Pledged Treasury  Securities,  as the case may be, forming a
     part of such Equity Units or Stripped  Units,  as the case may be, and (ii)
     deliver to the Holder a certificate or certificates or book-entry  interest
     for the full  number of shares of Common  Stock  issuable  upon such  Early
     Settlement  together  with payment in lieu of any  fraction of a share,  as
     provided in Section 5.12.

          (f) In the event that Early  Settlement  is effected  with  respect to
     Forward  Purchase  Contracts  underlying  less than all the Equity Units or
     Stripped Units, as the case may be,  evidenced by a Certificate,  upon such
     Early   Settlement   the  Company   shall   execute  and  the  Agent  shall
     authenticate,  execute on behalf of the Holder  thereof  and deliver to the
     Holder thereof, at the expense of the Company, a Certificate evidencing the
     Equity  Units or  Stripped  Units,  as the case may be,  as to which  Early
     Settlement was not effected.

Section 5.10 Early Settlement Upon Merger.
- ------------------------------------------

          (a) In the event of a merger or  consolidation  of the  Company of the
     type  described  in clause (1) of Section  5.6(b) in which the Common Stock
     outstanding  immediately prior to such merger or consolidation is exchanged
     for consideration  consisting of at least 30% cash or cash equivalents (any
     such event a "Cash  Merger"),  then the  Company (or the  successor  to the
     Company  hereunder)  shall be  required  to offer the Holder of each Equity
     Unit or Stripped  Unit, as the case may be, the right to settle the Forward
     Purchase  Contract  underlying  such Equity Units or Stripped Units, as the
     case may be, prior to the Stock Purchase Date ("Merger  Early  Settlement")
     as  provided  herein.  On or  before  the  fifth  Business  Day  after  the
     consummation  of a Cash Merger,  the Company or, at the request and expense
     of the Company,  the Agent, shall give all Holders notice of the occurrence
     of the Cash Merger and of the right of Merger Early Settlement arising as a
     result thereof. The Company shall also deliver a copy of such notice to the
     Agent and the Collateral Agent.

          Each such notice shall contain:

               (i)  the date,  which  shall be not less than 20 nor more than 30
                    calendar  days after the date of such  notice,  on which the
                    Merger Early  Settlement will be effected (the "Merger Early
                    Settlement Date");

               (ii) the date, which shall be on or one Business Day prior to the
                    Merger  Early  Settlement  Date,  by which the Merger  Early
                    Settlement right must be exercised;

               (iii)the  Settlement  Rate in  effect  as a result  of such  Cash
                    Merger and the kind and amount of securities, cash and other
                    property  receivable  by the Holder upon  settlement of each
                    Forward Purchase Contract pursuant to Section 5.6(b);

               (iv) a  statement  to the  effect  that all or a  portion  of the
                    Purchase  Price  payable by the Holder to settle the Forward
                    Purchase  Contract will be offset against the amount of cash
                    so receivable upon exercise of Merger Early  Settlement,  as
                    applicable; and

               (v)  the instructions a Holder must follow to exercise the Merger
                    Early Settlement right.

          (b) To  exercise  a Merger  Early  Settlement  right,  a Holder  shall
     deliver to the Agent at the Corporate  Trust Office on or before 5:00 p.m.,
     New York City time on the date  specified in the notice the  Certificate(s)
     evidencing  the Equity  Units or Stripped  Units,  as the case may be, with
     respect to which the Merger Early  Settlement right is being exercised duly
     endorsed  for transfer to the Company or in blank with the form of Election
     to Settle Early on the reverse  thereof duly  completed and  accompanied by
     payment payable to the Company in immediately  available funds in an amount
     equal to the Early Settlement Amount less the amount of cash that otherwise
     would be deliverable by the Company or its successor upon settlement of the
     Forward  Purchase  Contract  in lieu of Common  Stock  pursuant  to Section
     5.4(b)  and as  described  in the  notice to  Holders  (the  "Merger  Early
     Settlement Amount").

          (c) On the Merger Early  Settlement Date, the Company shall deliver or
     cause to be delivered (i) the net cash, securities and other property to be
     received  by  such  exercising  Holder,  equal  to the  Settlement  Rate as
     adjusted  pursuant  to  Section  5.6,  in  respect of the number of Forward
     Purchase  Contracts  for  which  such  Merger  Early  Settlement  right was
     exercised,   and  (ii)  the  related   Pledged  Notes,   Pledged   Treasury
     Consideration  or Pledged  Applicable  Ownership  Interest in the  Treasury
     Portfolio, in the case of Equity Units, or Pledged Treasury Securities,  in
     the  case  of  Stripped  Units,  to be  released  from  the  Pledge  by the
     Collateral Agent and  transferred,  in each case, to the Agent for delivery
     to the  Holder  thereof  or its  designee.  In the  event  a  Merger  Early
     Settlement  right shall be  exercised  by a Holder in  accordance  with the
     terms hereof,  all  references  herein to the Stock  Purchase Date shall be
     deemed to refer to such Merger Early Settlement Date.

          (d) Upon Merger Early  Settlement of any Forward  Purchase  Contracts,
     and subject to receipt of such net cash,  securities or other property from
     the Company and the Pledged Notes, Pledged Treasury Consideration,  Pledged
     Applicable Ownership Interest in the Treasury Portfolio or Pledged Treasury
     Securities,  as the case may be, from the Collateral  Agent, as applicable,
     the Agent shall, in accordance with the instructions provided by the Holder
     thereof on the  applicable  form of Election to Settle Early on the reverse
     of the  Certificate  evidencing the related Equity Units or Stripped Units,
     as the case may be, (i) transfer to the Holder the Pledged  Notes,  Pledged
     Treasury  Consideration,  Pledged  Applicable  Ownership  Interest  in  the
     Treasury  Portfolio,  or Pledged Treasury  Securities,  as the case may be,
     forming a part of such Equity Units or Stripped  Units, as the case may be,
     and (ii) deliver to the Holder such net cash,  securities or other property
     issuable upon such Merger Early Settlement together with payment in lieu of
     any fraction of a share, as provided in Section 5.12.

          (e) In the event that Merger Early Settlement is effected with respect
     to Forward Purchase Contracts  underlying less than all the Equity Units or
     Stripped Units, as the case may be,  evidenced by a Certificate,  upon such
     Merger  Early  Settlement  the  Company  (or the  successor  to the Company
     hereunder)  shall  execute  and the Agent  shall  authenticate,  execute on
     behalf of the Holder  thereof  and  deliver to the Holder  thereof,  at the
     expense of the  Company,  a  Certificate  evidencing  the  Equity  Units or
     Stripped Units, as the case may be, as to which Merger Early Settlement was
     not effected.

Section 5.11 Charges and Taxes.
- -------------------------------

     The Company will pay all stock transfer and similar taxes  attributable  to
the initial  issuance and delivery of the shares of Common Stock pursuant to the
Forward Purchase Contracts;  provided, that the Company shall not be required to
pay any such tax or taxes which may be payable in respect of any  exchange of or
substitution for a Certificate  evidencing Equity Units or Stripped Units or any
issuance of a share of Common Stock in a name other than that of the  registered
Holder of a Certificate  surrendered in respect of the Equity Units and Stripped
Units evidenced  thereby,  other than in the name of the Agent, as custodian for
such  Holder,  and the Company  shall not be  required to issue or deliver  such
share certificates or book-entry interest in Common Stock or Certificates unless
and until the Person or Persons  requesting  the  transfer or  issuance  thereof
shall have paid to the Company the amount of such tax or shall have  established
to the satisfaction of the Company that such tax has been paid.

Section 5.12 No Fractional Shares.
- ----------------------------------

     No  fractional  shares or scrip  representing  fractional  shares of Common
Stock shall be issued or delivered upon settlement on the Stock Purchase Date or
upon  Early  Settlement  or Merger  Early  Settlement  of any  Forward  Purchase
Contracts.  If Certificates  evidencing more than one Forward Purchase  Contract
shall be surrendered  for settlement at one time by the same Holder,  the number
of full shares of Common Stock which shall be delivered upon settlement shall be
computed  on the basis of the  aggregate  number of Forward  Purchase  Contracts
evidenced by the Certificates so surrendered. Instead of any fractional share of
Common Stock which would otherwise be deliverable upon settlement of any Forward
Purchase Contracts on the applicable Settlement Date or upon Early Settlement or
Merger  Early  Settlement,  the  Company,  through the Agent,  shall make a cash
payment in respect of such  fractional  share in an amount equal to the value of
such  fractional  share times the  Applicable  Market  Value.  The Company shall
provide the Agent from time to time with sufficient funds to permit the Agent to
make all cash payments required by this Section 5.12 in a timely manner.

Section 5.13 Tax Treatment.
- ---------------------------

     The Company  covenants and agrees and each Holder, by purchasing the Equity
Units  agrees,  (i) to treat a Holder's  acquisition  of the Equity Units as the
acquisition of the Note and Forward  Purchase  Contract  constituting the Equity
Units,  (ii) to  treat a  Holder's  acquisition  of the  Stripped  Units  as the
acquisition of the Treasury Security and Forward Purchase Contract  constituting
the Stripped Unit, (iii) to treat each Holder as the owner of the related Notes,
Treasury Consideration,  Applicable Ownership Interest in the Treasury Portfolio
or Treasury  Securities,  as the case may be and (iv) to allocate  the  purchase
price of the Equity Unit between the Note and Forward  Purchase  Contract as $50
and $0, respectively.

                                   ARTICLE VI.
                                    REMEDIES

Section 6.1 Unconditional Right of Holders to Purchase Common Stock.
- --------------------------------------------------------------------

          (a) The Holder of any Equity Units or Stripped  Units, as the case may
     be shall have the right,  which is absolute and  unconditional,  subject to
     the right of the Company to defer payment thereof  pursuant to Section 5.3,
     and to the  forfeiture of any Deferred  Contract  Adjustment  Payments upon
     Cash Settlement  pursuant to Section 5.2(d), upon Early Settlement pursuant
     to Section 5.9(a), upon Merger Early Settlement pursuant to Section 5.10 or
     upon the  occurrence of a  Termination  Event,  to receive  payment of each
     installment of the Contract  Adjustment  Payments,  if any, with respect to
     the Purchase Contract  constituting a part of such Equity Units or Stripped
     Units,  as the case may be, on the respective  Payment Date for such Equity
     Units or Stripped Units, as the case may be, and

          (b)  Subject to Section  5.6,  the Holder of any Units  shall have the
     right,  which is  absolute  and  unconditional,  to purchase  Common  Stock
     pursuant to the Forward Purchase Contract constituting a part of such Units
     and to  institute  suit for the  enforcement  of any such right to purchase
     Common Stock,  and such right shall not be impaired  without the consent of
     such Holder.

Section 6.2 Restoration of Rights and Remedies.
- -----------------------------------------------

     If any Holder has  instituted any proceeding to enforce any right or remedy
under this Agreement and such proceeding has been  discontinued or abandoned for
any reason, or has been determined  adversely to such Holder,  then and in every
such case, subject to any determination in such proceeding, the Company and such
Holder shall be restored  severally and  respectively to their former  positions
hereunder and  thereafter  all rights and remedies of such Holder shall continue
as though no such proceeding had been instituted.

Section 6.3 Rights and Remedies Cumulative.
- -------------------------------------------

     Except as otherwise  provided with respect to the replacement or payment of
mutilated,  destroyed,  lost or stolen Certificates in Section 3.10(f), no right
or remedy  herein  conferred  upon or  reserved to the Holders is intended to be
exclusive of any other right or remedy, and every right and remedy shall, to the
extent  permitted by law, be cumulative and in addition to every other right and
remedy  given  hereunder  or now or  hereafter  existing  at law or in equity or
otherwise.  The  assertion or employment  of any right or remedy  hereunder,  or
otherwise, shall not prevent the concurrent assertion or employment of any other
appropriate right or remedy.

Section 6.4 Delay or Omission Not Waiver.
- -----------------------------------------

     No delay or omission  of any Holder to exercise  any right or remedy upon a
default shall impair any such right or remedy or constitute a waiver of any such
right. Every right and remedy given by this Article or by law to the Holders may
be exercised from time to time, and as often as may be deemed expedient, by such
Holders.

Section 6.5 Undertaking For Costs.
- ----------------------------------

     All parties to this  Agreement  agree,  and each Holder of Equity  Units or
Stripped  Units,  as the case may be, by its  acceptance of such Equity Units or
Stripped  Units,  as the case may be, shall be deemed to have  agreed,  that any
court may in its  discretion  require,  in any suit for the  enforcement  of any
right or remedy under this  Agreement,  or in any suit against the Agent for any
action  taken,  suffered  or  omitted  by it as Agent,  the  filing by any party
litigant in such suit of an  undertaking to pay the costs of such suit, and that
such court may in its discretion assess reasonable costs,  including  reasonable
attorneys'  fees and expenses,  against any party litigant in such suit,  having
due regard to the merits and good faith of the claims or  defenses  made by such
party litigant;  provided that the provisions of this Section shall not apply to
any suit instituted by the Company,  to any suit instituted by the Agent, to any
suit  instituted  by any Holder,  or group of Holders,  holding in the aggregate
more than 10% of the Outstanding  Units, or to any suit instituted by any Holder
for the  enforcement  of  distributions  on any  Notes or any  Forward  Purchase
Contract  on or after the  respective  Payment  Date  therefor in respect of any
Equity Units or Stripped Units, as the case may be, held by such Holder,  or for
enforcement  of the right to purchase  shares of Common  Stock under the Forward
Purchase  Contract  constituting  part of any Equity Units or Stripped Units, as
the case may be, held by such Holder.

Section 6.6 Waiver of Stay or Extension Laws.
- ---------------------------------------------

     The Company  covenants  (to the extent that it may  lawfully do so) that it
will not at any time insist upon, or plead, or in any manner whatsoever claim or
take the benefit or advantage  of, any stay or extension  law wherever  enacted,
now or at any time hereafter in force,  which may affect the covenants in or the
performance  of this  Agreement;  and the  Company  (to the  extent  that it may
lawfully do so) hereby  expressly  waives all benefit or  advantage  of any such
law,  but will suffer and permit the  execution  of every power of the Agent and
the Holders as though no such law had been enacted.

                                   ARTICLE VII
                                    THE AGENT

Section 7.1 Certain Duties, Rights and Immunities.
- --------------------------------------------------

          (a) The Agent shall act as agent and  attorney-in-fact for the Holders
     of the Equity Units and Stripped  Units  hereunder  with such powers as are
     specifically vested in the Agent by the terms of this Agreement, the Pledge
     Agreement,  the  Remarketing  Agreement,  the Notes,  the Equity  Units and
     Stripped Units,  and any documents  evidencing them or related thereto (the
     "Transaction Documents"), together with such other powers as are reasonably
     incidental thereto. The Agent:

               (1)  shall  have  no  duties  or  responsibilities  except  those
                    expressly  set  forth in the  Transaction  Documents  and no
                    implied  covenants or obligations shall be inferred from any
                    Transaction Documents against the Agent, nor shall the Agent
                    be bound by the  provisions  of any  agreement  by any party
                    hereto beyond the specific terms hereof;

               (2)  shall  be  entitled  to  conclusively   rely  upon  (x)  any
                    certificate,  order,  judgment,  opinion,  notice  or  other
                    communication (including, without limitation, any thereof by
                    telephone  or  facsimile)  reasonably  believed  by it to be
                    genuine and correct and to have been signed or sent by or on
                    behalf  of the  proper  Person  or  Persons  (without  being
                    required to  determine  the  correctness  of any fact stated
                    therein),   (y)  the  truth  of  the   statements   and  the
                    correctness of the opinions expressed therein and (z) advice
                    and  statements of legal counsel and other experts  selected
                    by the Agent;

               (3)  shall in all  cases  be fully  protected  in  acting,  or in
                    refraining  from acting,  hereunder or under any Transaction
                    Documents  in  accordance  with  instructions  given  by the
                    Company or the  Holders in  accordance  herewith or with the
                    Transaction Documents;

               (4)  shall not be responsible  for any recitals  contained in any
                    Transaction   Document,  or  in  any  certificate  or  other
                    document  referred to or provided  for in, or received by it
                    under,  any  Transaction  Document  or the  Equity  Units or
                    Stripped Units, or for the value,  validity,  effectiveness,
                    genuineness,    enforceability   or   sufficiency   of   any
                    Transaction  Document  (other  than as against the Agent) or
                    the Equity  Units or  Stripped  Units or any other  document
                    referred  to or  provided  for  herein or therein or for any
                    failure  by the  Company,  any  Holder or any  other  Person
                    (except  the  Agent)  to  perform  any  of  its  obligations
                    hereunder or thereunder or for the perfection,  priority or,
                    except as expressly  required hereby,  existence,  validity,
                    perfection or maintenance of any security  interest  created
                    under the Pledge Agreement, or for the use or application by
                    the  Company  of the  proceeds  in  respect  of the  Forward
                    Purchase Contracts;

               (5)  shall not be required to initiate or conduct any  litigation
                    or collection proceedings hereunder;

               (6)  shall not be responsible  for any action taken or omitted to
                    be taken by it hereunder or under the Transaction  Documents
                    or any other document or instrument  referred to or provided
                    for  herein  or  therein  or  in   connection   herewith  or
                    therewith,  except  for its own  negligence,  bad  faith  or
                    willful misconduct; and

               (7)  shall not be  required  to advise any party as to selling or
                    retaining,  or taking or  refraining  from taking any action
                    with respect to, the Equity Units or Stripped Units or other
                    rights under any Transaction Document.

          (b) No provision  of any  Transaction  Document  shall be construed to
     relieve the Agent from  liability  for its own  negligent  action,  its own
     negligent failure to act, its own bad faith, or its own willful misconduct,
     except that:

               (1)  this  paragraph  (b)  shall  not be  construed  to limit the
                    effect of paragraph (a) of this Section;

               (2)  the Agent shall not be liable for any error of judgment made
                    in good faith by a Responsible  Officer,  unless it shall be
                    proved that the Agent was grossly  negligent in ascertaining
                    the pertinent facts; and

               (3)  in no event  shall the Agent be  required  to expend or risk
                    its own funds or otherwise incur any financial  liability in
                    the performance of any of its duties hereunder.

          (c) In no event shall the Agent or its  officers,  employees or agents
     be liable for any special, indirect, individual,  punitive or consequential
     loss or damages,  lost profits or loss of business,  arising in  connection
     with any Transaction  Document,  whether or not the likelihood of such loss
     or damage was known to the Agent, and regardless of the form of action.

          (d) Whether or not therein  expressly so provided,  every provision of
     every  Transaction  Document  relating  to the  conduct  or  affecting  the
     liability of or affording  protection  to the Agent shall be subject to the
     provisions of this Section.

          (e) The  Agent  is  authorized  to  execute  and  deliver  the  Pledge
     Agreement and the Remarketing  Agreement and any supplement  thereto in its
     capacity  as  Agent.  The Agent  shall be  entitled  to all of the  rights,
     privileges,  immunities  and  indemnities  contained in this Agreement with
     respect to any duties of the Agent under,  or actions taken,  omitted to be
     taken or suffered by the Agent pursuant to the Pledge Agreement.

          (f) The Agent  shall have no  liability  whatsoever  for the action or
     inaction of any Clearing  Agency or any book-entry  system  thereof.  In no
     event shall any Clearing Agency or any book-entry  system thereof be deemed
     an agent or subcustodian of the Agent.

          (g) The Agent  shall not be  responsible  or liable for any failure or
     delay in the performance of its obligations under any Transaction  Document
     arising out of or caused,  directly or indirectly,  by circumstances beyond
     its reasonable control, including, without limitation, acts of God; acts of
     terrorism;   earthquakes;   fires;   floods;   wars;   civil  or   military
     disturbances;   sabotage;   epidemics;   riots;   interruptions,   loss  or
     malfunctions   of   utilities,   computer   (hardware   or   software)   or
     communications  service;  accidents;  labor  disputes;  acts  of  civil  or
     military  authority;  governmental  actions;  or inability to obtain labor,
     material, equipment or transportation.

Section 7.2 Notice of Default.
- ------------------------------

     Within 30 days after the  occurrence  of any  default by the Company of its
obligations hereunder or under one or more Forward Purchase Contracts of which a
Responsible Officer of the Agent has actual knowledge,  the Agent shall transmit
by mail to the Company and the Holders of Equity  Units and Stripped  Units,  as
their  names and  addresses  appear  in the  Register,  notice  of such  default
hereunder, unless such default shall have been cured or waived.

Section 7.3 Certain Rights of Agent.
- ------------------------------------

     Subject to the provisions of Section 7.1:

          (a) the Agent may  conclusively  rely and shall be fully  protected in
     acting  or  refraining  from  acting  upon  any  resolution,   certificate,
     statement,   instrument,   opinion,  report,  notice,  request,  direction,
     consent,  order, bond,  debenture,  note, other evidence of indebtedness or
     other  paper or  document  believed  by it to be  genuine  and to have been
     signed or presented by the proper party or parties;

          (b) any request or direction of the Company  mentioned herein shall be
     sufficiently evidenced by an Officer's Certificate,  Issuer Order or Issuer
     Request, and any resolution of the Board of Directors of the Company may be
     sufficiently evidenced by a Board Resolution;

          (c) whenever in the  administration  of this Agreement the Agent shall
     deem it desirable that a matter be proved or  established  prior to taking,
     suffering  or  omitting  any  action  hereunder,  the Agent  (unless  other
     evidence  be herein  specifically  prescribed)  may,  in the absence of bad
     faith on its part, rely upon an Officer's Certificate of the Company;

          (d) the Agent may consult with counsel of its selection and the advice
     of such  counsel  or any  Opinion  of  Counsel  shall be full and  complete
     authorization  and  protection in respect of any action taken,  suffered or
     omitted by it hereunder in good faith and in reliance thereon;

          (e) the Agent  shall not be bound to make any  investigation  into the
     facts  or  matters  stated  in  any  resolution,   certificate,  statement,
     instrument,  opinion, report, notice, request,  direction,  consent, order,
     bond,  debenture,  note,  other evidence of  indebtedness or other paper or
     document,  but the Agent,  in its discretion,  may make reasonable  further
     inquiry  or  investigation  into  such  facts  or  matters  related  to the
     execution, delivery and performance of the Forward Purchase Contracts as it
     may see fit, and, if the Agent shall determine to make such further inquiry
     or investigation, it shall be given a reasonable opportunity to examine the
     books,  records and  premises  of the  Company,  personally  or by agent or
     attorney;

          (f) the Agent may execute any of the powers  hereunder  or perform any
     duties hereunder either directly or by or through agents or attorneys or an
     Affiliate  of the  Agent and the Agent  shall  not be  responsible  for any
     misconduct  or  negligence  on the  part of any  agent  or  attorney  or an
     Affiliate appointed with due care by it hereunder;

          (g) the rights, privileges, protections, immunities and benefits given
     to the Agent,  including,  but not limited to, its right to be indemnified,
     are  extended  to,  and shall be  enforceable  by, the Agent in each of its
     capacities  hereunder,  and to each custodian and other person  employed to
     act hereunder;

          (h) the Agent shall not be charged  with  knowledge  of any default by
     the Company hereunder unless a Responsible  Officer of the Agent shall have
     received at the Corporate  Trust Office of the Agent written notice of such
     default; and

          (i) the permissive right of the Agent to do things  enumerated in this
     Agreement shall not be construed as a duty.

Section 7.4 Not Responsible For Recitals, Etc.
- ----------------------------------------------

     The recitals  contained herein,  in any other Transaction  Documents and in
the  Certificates  shall be taken as the statements of the Company and the Agent
assumes no responsibility for their accuracy. The Agent makes no representations
as to the  validity  or  sufficiency  of  either  this  Agreement  or any  other
Transaction  Documents.  The  Agent  shall  not be  accountable  for  the use or
application  by the Company of the  proceeds  in respect of the Equity  Units or
Stripped  Units or the Forward  Purchase  Contracts and shall not be responsible
for the perfection, priority or maintenance of any security interests created or
intended to be created under the Pledge Agreement.

Section 7.5 May Hold Equity Units and Stripped Units and Other Dealings.
- ------------------------------------------------------------------------

     Any  Registrar  or any  other  agent of the  Company,  or the Agent and its
Affiliates,  in their individual or any other capacity,  may become the owner or
pledgee of Equity Units or Stripped Units, as the case may be, and may otherwise
deal with the Company,  the  Collateral  Agent or any other Person with the same
rights it would have if it were not Registrar or such other agent, or the Agent.
The Agent and its  Affiliates  may  (without  having to account  therefor to the
Company or any Holder of Equity  Units or  Stripped  Units or holder of Separate
Notes)  accept  deposits  from,  lend money to,  make other  investments  in and
generally  engage  in any kind of  banking,  trust or  other  business  with the
Company, any Holder of Equity Units or Stripped Units and any holder of Separate
Notes (and any of their respective subsidiaries or Affiliates) as if it were not
acting as the Agent and the Agent and its  Affiliates  may accept fees and other
consideration from the Company,  any Holder of Equity Units or Stripped Units or
any holder of Separate  Notes without having to account for the same to any such
Person.

Section 7.6 Money Held In Custody.
- ----------------------------------

     Money held by the Agent in custody  hereunder  need not be segregated  from
the Agent's other funds except to the extent required by law or provided herein.
The Agent shall be under no  obligation  to invest or pay  interest on any money
received by it hereunder except as otherwise agreed in writing with the Company.

Section 7.7 Compensation and Reimbursement.
- -------------------------------------------

         The Company agrees:

          (a) to pay to the  Agent  from  time  to  time  compensation  for  all
     services  rendered by it  hereunder or under the  Transaction  Documents as
     shall be agreed in writing between the Company and the Agent;

          (b) to  reimburse  the  Agent  upon  its  request  for all  reasonable
     expenses,  disbursements  and  advances  incurred  or made by the  Agent in
     accordance  with any provision of this  Agreement or the other  Transaction
     Documents  (including  the  reasonable   compensation  and  the  reasonable
     expenses  and  disbursements  of its agents and  counsel),  except any such
     expense,  disbursement or advance as may be attributable to its negligence,
     willful misconduct or bad faith; and

          (c) to indemnify the Agent for, and to hold it harmless  against,  any
     loss, liability or reasonable  out-of-pocket expense incurred without gross
     negligence,  willful misconduct or bad faith on its part, arising out of or
     in connection with the acceptance or administration of its duties under the
     other Transaction  Documents,  including the costs and expenses  (including
     reasonable  fees and expenses of counsel) of defending  itself  against any
     claim,  whether asserted by the Company,  a Holder or any other Person,  or
     liability  in  connection  with the exercise or  performance  of any of its
     powers or duties under the Transaction Documents.  The Agent shall promptly
     notify the  Company  of any third  party  claim  which may give rise to the
     indemnity  hereunder and give the Company the opportunity to participate in
     the  defense of such  claim with  counsel  reasonably  satisfactory  to the
     indemnified  party,  and no such claim shall be settled without the written
     consent of the Company,  which consent shall not be unreasonably  withheld,
     provided  that any  failure  to give any such  notice  shall not affect the
     obligation  of the  Company  under this  Section.  The  provisions  of this
     Section  7.7  shall  survive  the  termination  of any and all  Transaction
     Documents,  the  satisfaction  or discharge of the Equity Units or Stripped
     Units  and/ or the  Separate  Notes or the  resignation  or  removal of the
     Agent.

Section 7.8 Corporate Agent Required; Eligibility.
- --------------------------------------------------

     There shall at all times be an Agent hereunder which shall be a corporation
organized and doing business under the laws of the United States of America, any
State  thereof  or the  District  of  Columbia,  authorized  under  such laws to
exercise  corporate  trust  powers,  having (or being a member of a bank holding
company having) a combined capital and surplus of at least $500,000,000, subject
to supervision or examination by federal or state authority and having (or being
a member of a bank  holding  company  having) a  Corporate  Trust  Office in the
Borough  of  Manhattan,  the City of New York,  if there be such a  corporation,
qualified  and  eligible  under this  Article and  willing to act on  reasonable
terms.  If such  corporation  publishes  reports of condition at least annually,
pursuant  to  law  or to the  requirements  of  said  supervising  or  examining
authority,  then for the  purposes of this  Section,  the  combined  capital and
surplus  of such  corporation  shall be deemed to be its  combined  capital  and
surplus as set forth in its most recent report of condition so published.  If at
any time the Agent shall cease to be eligible in accordance  with the provisions
of this Section,  it shall resign  immediately in the manner and with the effect
hereinafter specified in this Article.

Section 7.9 Resignation and Removal; Appointment of Successor.
- --------------------------------------------------------------

          (a) No  resignation  or removal of the Agent and no  appointment  of a
     successor  Agent pursuant to this Article shall become  effective until the
     acceptance of  appointment  by the successor  Agent in accordance  with the
     applicable requirements of Section 7.10.

          (b) The Agent may resign at any time by giving  written notice thereof
     to the Company 60 days prior to the effective date of such resignation.  If
     the instrument of acceptance by a successor  Agent required by Section 7.10
     shall not have been  delivered to the Agent within 30 days after the giving
     of such notice of  resignation,  the resigning  Agent may petition,  at the
     expense  of the  Company,  any  court  of  competent  jurisdiction  for the
     appointment of a successor Agent.

          (c) The Agent may be  removed  at any time by Act of the  Holders of a
     majority  in number of the  Outstanding  Units upon  delivery  of a written
     notice to the Agent and the Company.  If the  instrument of acceptance by a
     successor  Agent  required by Section 7.10 shall not have been delivered to
     the Agent  within 30 days after the giving of such notice of  removal,  the
     Agent to be removed may petition,  at the expense of the Company, any court
     of competent jurisdiction for the appointment of a successor Agent.

          (d) If at any time:

               (1)  the  Agent  has a  "conflicting  interest"  (as  defined  in
                    Section  310(b)  of the TIA)  and  fails  to  eliminate  the
                    conflicting interest or resign pursuant to Section 310(b) of
                    the TIA upon written  request  therefor by the Company or by
                    any Holder who has been a bona fide  Holder of a Unit for at
                    least six months,  as if this  Agreement  were an  indenture
                    qualified  under the TIA, as if the Equity Units or Stripped
                    Units were in default  and as if such  default  had not been
                    cured or waived within the  applicable  period under Section
                    310(b) of the TIA; or

               (2)  the Agent shall cease to be eligible  under  Section 7.8 and
                    shall fail to resign after written  request  therefor by the
                    Company or by any such Holder; or

               (3)  the  Agent  shall  become  incapable  of  acting or shall be
                    adjudged a bankrupt or  insolvent or a receiver of the Agent
                    or of its property  shall be appointed or any public officer
                    shall take charge or control of the Agent or of its property
                    or affairs for the purpose of  rehabilitation,  conservation
                    or liquidation;

     then, in any such case,  (x) the Company by a Board  Resolution  may remove
     the  Agent,  or (y) any  Holder  who has been a bona fide  Holder of Equity
     Units or  Stripped  Equity  Units for at least six months may, on behalf of
     himself and all others similarly situated,  petition any court of competent
     jurisdiction  for  the  removal  of the  Agent  and  the  appointment  of a
     successor Agent.

          (e) If the Agent  shall  resign,  be  removed or become  incapable  of
     acting,  or if a vacancy  shall occur in the office of Agent for any cause,
     the Company,  by a Board  Resolution,  shall  promptly  appoint a successor
     Agent and shall comply with the applicable requirements of Section 7.10. If
     no successor Agent shall have been so appointed by the Company and accepted
     appointment in the manner required by Section 7.10, any Holder who has been
     a bona fide Holder of Equity  Units or Stripped  Equity  Units for at least
     six months  may, on behalf of himself  and all others  similarly  situated,
     petition  any court of  competent  jurisdiction  for the  appointment  of a
     successor Agent.

          (f) The Company  shall give,  or shall cause such  successor  Agent to
     give,  notice of each  resignation  and each  removal of the Agent and each
     appointment of a successor Agent by mailing written notice of such event by
     first-class  mail,  postage  prepaid,  to all  Holders  as their  names and
     addresses appear in the applicable Register.  Each notice shall include the
     name of the successor Agent and the address of its Corporate Trust Office.

Section 7.10 Acceptance of Appointment By Successor.
- ----------------------------------------------------

          (a) In case of the appointment  hereunder of a successor Agent,  every
     such successor Agent so appointed shall execute, acknowledge and deliver to
     the  Company  and  to the  retiring  Agent  an  instrument  accepting  such
     appointment, and thereupon the resignation or removal of the retiring Agent
     shall become effective and such successor  Agent,  without any further act,
     deed or  conveyance,  shall  become  vested  with all the  rights,  powers,
     agencies,  trusts and duties of the retiring Agent;  but, on the request of
     the Company or the successor Agent, such retiring Agent shall, upon payment
     of its  charges,  execute and deliver an  instrument  transferring  to such
     successor Agent all the rights, powers, agencies,  trusts and duties of the
     retiring  Agent and duly  assign,  transfer  and deliver to such  successor
     Agent all property and money held by such retiring Agent hereunder.

          (b) Upon  request  of any such  successor  Agent,  the  Company  shall
     execute any and all instruments for more fully and certainly vesting in and
     confirming  to such  successor  Agent all such  rights,  powers,  agencies,
     trusts and duties referred to in paragraph (a) of this Section.

          (c) No successor Agent shall accept its appointment unless at the time
     of such  acceptance  such  successor  Agent shall be qualified and eligible
     under this Article.

Section 7.11 Merger, Conversion, Consolidation or Succession to Business.
- -------------------------------------------------------------------------

     Any  corporation  into which the Agent may be merged or  converted  or with
which it may be  consolidated,  or any  corporation  resulting  from any merger,
conversion  or  consolidation  to which  the  Agent  shall  be a  party,  or any
corporation  succeeding to all or substantially all the corporate trust business
of the Agent,  shall be the  successor  of the Agent  hereunder,  provided  such
corporation  shall be  otherwise  qualified  and  eligible  under this  Article,
without the  execution  or filing of any paper or any further act on the part of
any  of  the  parties  hereto.   In  case  any  Certificates   shall  have  been
authenticated and executed on behalf of the Holders,  but not delivered,  by the
Agent then in office,  any successor by merger,  conversion or  consolidation to
such Agent  shall  adopt such  authentication  and  execution  and  deliver  the
Certificates  so  authenticated  and  executed  with the same  effect as if such
successor  Agent had itself  authenticated  and  executed  such Equity Units and
Stripped Units.

Section 7.12 Preservation of Information; Communications to Holders.
- --------------------------------------------------------------------

          (a) The Agent shall  preserve,  in as current a form as is  reasonably
     practicable,  the names and  addresses of Holders  received by the Agent in
     its capacity as Registrar.

          (b) If three or more  Holders  (herein  referred  to as  "Applicants")
     apply in writing to the Agent,  and furnish to the Agent  reasonable  proof
     that each such applicant has owned Equity Units or Stripped  Units,  as the
     case may be, for a period of at least six months preceding the date of such
     application,  and such  application  states that the  Applicants  desire to
     communicate  with other  Holders  with  respect to their  rights under this
     Agreement or under the Equity Units or Stripped  Units, as the case may be,
     and is  accompanied  by a copy of the form of proxy or other  communication
     which such Applicants propose to transmit, then the Agent shall mail to all
     the  Holders  copies of the form of proxy or other  communication  which is
     specified in such request, with reasonable promptness after a tender to the
     Agent of the materials to be mailed and of payment,  or  provision,  in the
     absence of bad faith,  satisfactory  to the Agent for the  payment,  of the
     reasonable expenses of such mailing.

Section 7.13 Failure to Act.
- ----------------------------

     In the event of any ambiguity in the provisions of any Transaction Document
or any dispute  between or conflicting  claims by or among the parties hereto or
any other  Person,  the Agent  shall be  entitled,  after  prompt  notice to the
Company and the Holders of Equity Units and Stripped  Units, at its sole option,
to refuse to comply with any and all such  claims,  demands or  instructions  so
long as such dispute or conflict shall  continue,  and the Agent shall not be or
become liable in any way to any of the parties hereto for its failure or refusal
to comply with such conflicting claims, demands or instructions. The Agent shall
be entitled to refuse to act until either (i) such conflicting or adverse claims
or  demands  shall  have  been  finally  determined  by  a  court  of  competent
jurisdiction  or  settled  by  agreement  between  the  conflicting  parties  as
evidenced in a writing,  reasonably satisfactory to the Agent, or (ii) the Agent
shall have  received  security or an indemnity  reasonably  satisfactory  to the
Agent  sufficient to save the Agent  harmless from and against any and all loss,
liability  or  reasonable  out-of-pocket  expense  which  the Agent may incur by
reason of its acting without bad faith,  willful misconduct or gross negligence.
The Agent may in addition elect to commence an interpleader action or seek other
judicial  relief or orders  as the  Agent  may deem  necessary.  Notwithstanding
anything  contained  herein to the contrary,  the Agent shall not be required to
take any action  that is in its  opinion  contrary to law or to the terms of any
Transaction  Document,  or which would in its  opinion  subject it or any of its
officers, employees or directors to liability.

Section 7.14 No Obligations of Agent.
- -------------------------------------

     Except  to the  extent  otherwise  provided  in this  Agreement,  the Agent
assumes  no  obligation  and shall not be subject  to any  liability  under this
Agreement,  the Pledge Agreement or any Forward Purchase  Contract in respect of
the obligations of the Holder of any Equity Units or Stripped Units  thereunder.
The  Company  agrees,  and  each  Holder  of a  Certificate,  by  such  Holder's
acceptance  thereof,  shall be deemed to have agreed, that the Agent's execution
of the  Certificates  on  behalf  of the  Holders  shall be  solely as agent and
attorney-in-fact for the Holders, and that the Agent shall have no obligation to
perform such Forward Purchase Contracts on behalf of the Holders,  except to the
extent expressly  provided in Article V. Anything contained in this Agreement to
the  contrary  notwithstanding,  in no event  shall the  Agent or its  officers,
employees or agents be liable for indirect,  special, punitive, or consequential
loss or damage of any kind  whatsoever,  including,  but not  limited  to,  lost
profits,  whether or not the  likelihood of such loss or damage was known to the
Agent and regardless of the form of action.

Section 7.15 Tax Compliance.
- ----------------------------

          (a) The Agent,  on its own behalf and on behalf of the  Company,  will
     comply  with  all  applicable  certification,   information  reporting  and
     withholding (including "backup" withholding)  requirements imposed on it as
     a paying  agent by  applicable  tax  laws,  regulations  or  administrative
     practice with respect to any payments made with respect to the Equity Units
     and Stripped Units. Such compliance shall include, without limitation,  the
     preparation and timely filing of required returns and the timely payment of
     all amounts required to be withheld to the appropriate  taxing authority or
     its designated agent.

          (b) The Agent  shall  comply  with any  reasonable  written  direction
     timely  received from the Company with respect to the  application  of such
     requirements  to  particular  payments  to Holders  or in other  particular
     circumstances,  and may for  purposes  of this  Agreement  rely on any such
     direction in accordance with Section 7.1(a)(2).

          (c) The Agent  shall  maintain  all  appropriate  records  documenting
     compliance with such  requirements,  and shall make such records available,
     on written request, to the Company or its authorized  representative within
     a reasonable period of time after receipt of such request.

                                 ARTICLE VIII.
                             SUPPLEMENTAL AGREEMENTS

Section 8.1 Supplemental Agreements Without Consent of Holders.
- ---------------------------------------------------------------

     Without the consent of any Holders,  the Company and the Agent, at any time
and from  time to time,  may  enter  into  one or more  agreements  supplemental
hereto,  in form  satisfactory  to the  Company  and the  Agent,  for any of the
following purposes:

          (a) to evidence the succession of another  Person to the Company,  and
     the assumption by any such successor of the covenants of the Company herein
     and in the Certificates; or

          (b) to add to the  covenants  of the  Company  for the  benefit of the
     Holders,  or to  surrender  any right or power  herein  conferred  upon the
     Company; or

          (c)  to  evidence  and  provide  for  the  acceptance  of  appointment
     hereunder by a successor Agent; or

          (d) to make provision  with respect to the rights of Holders  pursuant
     to the requirements of Section 5.6(b) or 5.10; or

          (e) to cure any  ambiguity,  to correct or supplement  any  provisions
     herein which may be inconsistent  with any other provisions  herein,  or to
     make any other provisions with respect to such matters or questions arising
     under this Agreement,  provided such action shall not adversely  affect the
     interests of the Holders; or

          (f) to permit the  substitution by Holders of designated  Company debt
     instruments for the Pledged Notes as Collateral under this Agreement.

Section 8.2 Supplemental Agreements With Consent of Holders.
- ------------------------------------------------------------

          (a) With the consent of the Holders of not less than a majority of the
     outstanding Forward Purchase Contracts voting together as one class, by Act
     of said Holders  delivered to the Company and the Agent, the Company,  when
     authorized by a Board Resolution, and the Agent may enter into an agreement
     or agreements  supplemental hereto, in form satisfactory to the Company and
     the  Agent,  for the  purpose of  modifying  in any manner the terms of the
     Forward  Purchase  Contracts,  or the  provisions of this  Agreement or the
     rights of the Holders in respect of the Equity  Units and  Stripped  Units;
     provided,  that,  except  as  contemplated  herein,  no  such  supplemental
     agreement shall, without the consent of the Holder of each Outstanding Unit
     affected thereby:

               (1)  change any Payment Date;

               (2)  change the amount or the type of  Collateral  required to be
                    Pledged to secure a Holder's  Obligations  under the Forward
                    Purchase Contract unless not adverse to Holders,  impair the
                    right of the  Holder of any  Forward  Purchase  Contract  to
                    receive  distributions on the related  Collateral (except as
                    provided  in  Section  8.1(f)  and  except for the rights of
                    Holders  of  Equity   Units  to   substitute   the  Treasury
                    Securities   for  the  Pledged   Notes,   Pledged   Treasury
                    Consideration or Pledged  Applicable  Ownership  Interest in
                    the Treasury Portfolio, or the rights of holders of Stripped
                    Units   to   substitute   Notes  or   appropriate   Treasury
                    Consideration  or  Applicable   Ownership  Interest  in  the
                    Treasury  Portfolio for the Pledged Treasury  Securities) or
                    otherwise adversely affect the Holder's rights in or to such
                    Collateral;

               (3)  reduce any  Contract  Adjustment  Payments,  if any,  or any
                    Deferred Contract  Adjustment  Payment,  or change any place
                    where,  or the  coin or  currency  in  which,  any  Contract
                    Adjustment Payment is payable;

               (4)  impair the right to institute  suit for the  enforcement  of
                    any  Forward  Purchase  Contract,  any  Contract  Adjustment
                    Payment,   if  any,  or  any  Deferred  Contract  Adjustment
                    Payment, if any;

               (5)  impair the right to institute  suit for the  enforcement  of
                    any Forward Purchase Contract;

               (6)  reduce the number of shares of Common  Stock to be purchased
                    pursuant  to any Forward  Purchase  Contract,  increase  the
                    price to purchase  shares of Common Stock upon settlement of
                    any Forward  Purchase  Contract,  change the Stock  Purchase
                    Date or otherwise  materially  adversely affect the Holder's
                    rights under any Forward Purchase Contract; or

               (7)  reduce the percentage of the  outstanding  Forward  Purchase
                    Contracts  the consent of whose  Holders is required for any
                    such supplemental agreement;

     provided,  that if any  amendment  or  proposal  referred  to  above  would
     adversely affect only the Equity Units or the Stripped Units, then only the
     affected class of Holder as of the record date for the Holders  entitled to
     vote  thereon will be entitled to vote on such  amendment or proposal,  and
     such amendment or proposal  shall not be effective  except with the consent
     of Holders of not less than a majority or 100% of such  class,  as the case
     may be;  provided  further,  however,  that no  agreement,  whether with or
     without the consent of Holders shall affect Section 3.16.

          (b) It  shall  not be  necessary  for any Act of  Holders  under  this
     Section  to  approve  the  particular  form  of any  proposed  supplemental
     agreement,  but it  shall  be  sufficient  if such Act  shall  approve  the
     substance thereof.

Section 8.3 Execution of Supplemental Agreements.
- -------------------------------------------------

     In  executing,  or  accepting  the  additional  agencies  created  by,  any
supplemental agreement permitted by this Article or the modifications thereby of
the agencies created by this Agreement, the Agent shall be provided and (subject
to Section 7.1) shall be fully  protected in relying upon, an Opinion of Counsel
stating that the  execution of such  supplemental  agreement  is  authorized  or
permitted by this Agreement. The Agent may, but shall not be obligated to, enter
into any such  supplemental  agreement  which  affects  the  Agent's own rights,
duties or immunities under this Agreement or otherwise.

Section 8.4 Effect of Supplemental Agreements.
- ----------------------------------------------

     Upon the execution of any supplemental  agreement under this Article,  this
Agreement  shall be  modified in  accordance  therewith,  and such  supplemental
agreement shall form a part of this Agreement for all purposes; and every Holder
of Certificates theretofore or thereafter  authenticated,  executed on behalf of
the Holders and delivered hereunder shall be bound thereby.

Section 8.5 Reference to Supplemental Agreements.
- -------------------------------------------------

     Certificates authenticated, executed on behalf of the Holders and delivered
after the execution of any supplemental  agreement pursuant to this Article may,
and shall if  required  by the Agent,  bear a notation  in form  approved by the
Agent as to any  matter  provided  for in such  supplemental  agreement.  If the
Company shall so determine,  new Certificates so modified as to conform,  in the
opinion of the Agent and the Company, to any such supplemental  agreement may be
prepared  and executed by the Company and  authenticated,  executed on behalf of
the Holders and delivered by the Agent in exchange for outstanding Certificates.

                                  ARTICLE IX.
                    CONSOLIDATION, MERGER, SALE OR CONVEYANCE

Section 9.1 Company May Consolidate, Etc., Only on Certain Terms.
- -----------------------------------------------------------------

     The Company  shall not  consolidate  with or merge into any other Person or
convey, transfer or lease its properties and assets substantially as an entirety
to any Person, unless:

          (a) the Person formed by such  consolidation or into which the Company
     is merged or the Person which acquires by conveyance, transfer or lease the
     properties and assets of the Company  substantially as an entirety shall be
     a corporation,  partnership,  limited liability company or trust,  shall be
     organized  and  validly  existing  under the laws of the  United  States of
     America,  any State thereof or the District of Columbia and shall expressly
     assume every covenant of this Agreement,  the Forward  Purchase  Contracts,
     the Notes,  the Remarketing  Agreement and the Pledge Agreement on the part
     of the Company to be  performed  or  observed  by one or more  supplemental
     agreements in form reasonably  satisfactory to the Agent and the Collateral
     Agent, executed and delivered to the Agent and the Collateral Agent by such
     Person;

          (b) immediately  after giving effect to such  transaction,  no default
     under this  Agreement,  the Forward  Purchase  Contracts,  the  Remarketing
     Agreement or the Pledge  Agreement  shall have happened and be  continuing;
     and

          (c) the Company has  delivered to the Agent an  Officers'  Certificate
     and an Opinion of Counsel,  each stating that such  consolidation,  merger,
     conveyance,  transfer or lease and such  supplemental  agreement(s)  comply
     with this Section 9.1 and that all conditions precedent herein provided for
     relating to such transaction have been complied with.

     This  Section 9.1 shall not apply to any merger or  consolidation  in which
     the Company is the surviving corporation.

Section 9.2 Successor Substituted.
- ----------------------------------

          (a) Upon any  consolidation  with or  merger of the  Company  into any
     other Person,  or any  conveyance,  transfer or lease of the properties and
     assets of the  Company  substantially  as an entirety  in  accordance  with
     Section 9.1, the  successor  Person  formed by such  consolidation  or into
     which the Company is merged or to which such conveyance,  transfer or lease
     is made shall succeed to, and be  substituted  for, and may exercise  every
     right and power of, the Company under this  Agreement  with the same effect
     as if such  successor  Person had been  named as the  Company  herein,  and
     thereafter,  except in the case of a lease, the predecessor Person shall be
     relieved of all obligations and covenants under this Agreement, the Forward
     Purchase Contracts, the Notes, the Units, the Remarketing Agreement and the
     Pledge Agreement.

          (b) In case  of any  such  consolidation,  merger,  sale,  assignment,
     transfer,  lease or conveyance such change in phraseology and form (but not
     in substance) may be made in the  Certificates  evidencing Units thereafter
     to be issued as may be appropriate.

                                   ARTICLE X.
                                    COVENANTS

Section 10.1 Performance Under Forward Purchase Contracts.
- ----------------------------------------------------------


     The Company  covenants  and agrees for the benefit of the Holders from time
to time of the Equity Units and Stripped  Units that it will duly and punctually
perform its obligations under the Forward Purchase  Contracts in accordance with
the terms of the Forward Purchase  Contracts and this Agreement.  In the case of
Early  Settlement  pursuant  to  Section  5.9,  if  the  United  States  federal
securities laws so require, the Company will use commercially reasonable efforts
to (i) have in effect a  registration  statement  covering  the shares of Common
Stock to be delivered in respect of the Forward Purchase Contracts being settled
and (ii) provide a prospectus in connection therewith,  in each case that may be
used in connection with such Early Settlement.

Section 10.2 Maintenance of Office or Agency.
- ---------------------------------------------

          (a) The Company will maintain in the Borough of Manhattan, The City of
     New York an  office  or  agency  where  Certificates  may be  presented  or
     surrendered  for payment of Contract  Adjustment  Payments,  acquisition of
     shares of Common Stock upon settlement of the Forward Purchase Contracts on
     any  Settlement  Date and for transfer of Collateral  upon  occurrence of a
     Termination  Event,  where Certificates may be surrendered for registration
     of transfer or exchange,  for a Collateral  Substitution or reestablishment
     of Equity  Units and where  notices  and  demands to or upon the Company in
     respect of the Equity Units and Stripped  Units and this  Agreement  may be
     served.  The Company  will give prompt  written  notice to the Agent of the
     location,  and any change in the location,  of such office or agency. If at
     any time the Company  shall fail to maintain  any such  required  office or
     agency or shall fail to furnish  the Agent with the address  thereof,  such
     presentations, surrenders, notices and demands may be made or served at the
     Corporate  Trust Office,  Office of the Agent in The City of New York,  and
     the  Company  hereby  appoints  the Agent as its agent to receive  all such
     presentations, surrenders, notices and demands.

          (b) The Company may also from time to time designate one or more other
     offices or agencies where  Certificates may be presented or surrendered for
     any  or  all  such  purposes  and  may  from  time  to  time  rescind  such
     designations; provided, that no such designation or rescission shall in any
     manner  relieve  the  Company of its  obligation  to  maintain an office or
     agency in the Borough of Manhattan, The City of New York for such purposes.
     The  Company  will  give  prompt  written  notice  to the Agent of any such
     designation  or  rescission  and of any change in the  location of any such
     other  office or agency.  The  Company  hereby  designates  as the place of
     payment for the Equity Units and Stripped  Units the Office of the Agent in
     The City of New York and  appoints  the Agent at the Office of the Agent in
     The City of New York as paying agent in such city.

Section 10.3 Company to Reserve Common Stock.
- ---------------------------------------------

     The Company shall at all times prior to the Stock Purchase Date reserve and
keep available,  free from preemptive rights, out of its authorized but unissued
Common Stock the full number of shares of Common Stock  issuable  against tender
of payment in respect of all Forward Purchase  Contracts  constituting a part of
the Equity Units and Stripped Units evidenced by outstanding Certificates.

Section 10.4 Covenants as to Common Stock.
- ------------------------------------------

     The Company  covenants  that all shares of Common Stock which may be issued
against  tender  of  payment  in  respect  of  any  Forward  Purchase   Contract
constituting  a part of the  Outstanding  Units  will,  upon  issuance,  be duly
authorized, validly issued, fully paid and nonassessable.

Section 10.5 Statements of Officer of the Company as to Default.
- ----------------------------------------------------------------

     The  Company  will  deliver to the Agent,  within 120 days after the end of
each fiscal year of the  Company  ending  after the date  hereof,  an  Officer's
Certificate,  stating whether or not to the best knowledge of the signer thereof
the Company is in default in the performance and observance of any of the terms,
provisions  and  conditions  hereof,  and if the  Company  shall be in  default,
specifying  all such  defaults  and the nature and status  thereof of which such
officer may have knowledge.

Section 10.6 ERISA.
- -------------------

         Each Holder from time to time of the Equity Units or Stripped Units
which is a Plan hereby represents that its acquisition of the Equity Units or
Stripped Units and the holding of the same satisfies the applicable fiduciary
requirements of ERISA and that it is entitled to exemption relief from the
prohibited transaction provisions of ERISA and the Code in accordance with one
or more prohibited transaction exemptions or otherwise will not result in a
nonexempt prohibited transaction.

                            [SIGNATURE PAGES FOLLOW]

<PAGE>


     IN WITNESS  WHEREOF,  the parties  hereto have caused this  Agreement to be
duly executed as of the day and year first above written.



                               AMERICAN ELECTRIC POWER COMPANY, INC.



                               By:              /s/ A. A. Pena
                                      Name:         A. A. Pena
                                      Title:        Treasurer



<PAGE>




                               THE BANK OF NEW YORK,
                               as Forward Purchase Contract Agent

                               By:            /s/ Terence Rawlins
                                      Name:       Terence Rawlins
                                      Title:      Vice President





<PAGE>

                                    EXHIBIT A
                        FORM OF EQUITY UNITS CERTIFICATE

     [FOR INCLUSION IN GLOBAL  CERTIFICATES ONLY -- THIS CERTIFICATE IS A GLOBAL
CERTIFICATE  WITHIN THE MEANING OF THE FORWARD PURCHASE  CONTRACT  AGREEMENT (AS
HEREINAFTER  DEFINED) AND IS REGISTERED IN THE NAME OF THE CLEARING  AGENCY OR A
NOMINEE THEREOF. THIS CERTIFICATE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A
CERTIFICATE REGISTERED,  AND NO TRANSFER OF THIS CERTIFICATE IN WHOLE OR IN PART
MAY BE REGISTERED,  IN THE NAME OF ANY PERSON OTHER THAN SUCH CLEARING AGENCY OR
A NOMINEE THEREOF,  EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD
PURCHASE CONTRACT AGREEMENT.

     Unless this Certificate is presented by an authorized representative of The
Depository Trust Company (55 Water Street, New York, New York) to the Company or
its agent for registration of transfer, exchange or payment, and any Certificate
issued is  registered in the name of Cede & Co., or such other name as requested
by an authorized representative of The Depository Trust Company, and any payment
hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE
OR OTHERWISE BY A PERSON IS WRONGFUL since the registered  owner hereof,  Cede &
Co., has an interest herein.]

                   (Form of Face of Equity Units Certificate)

No. ______________                                       CUSIP No. ____________

Number of Equity Units____________

     This Equity  Units  Certificate  certifies  that [For  inclusion  in Global
Certificates  only -- Cede & Co.] is the  registered  Holder  of the  number  of
Equity  Units set forth above [For  inclusion in Global  Certificates  only - or
such other  number of Equity  Units  reflected  in the  Schedule of Increases or
Decreases in Global Certificates  attached hereto].  Each Equity Unit represents
(i) either (a)  beneficial  ownership by the Holder of one 5.75% Senior Note Due
August 16, 2007 (the "Note") of American  Electric  Power  Company,  Inc., a New
York  corporation  (the "Company")  having a principal amount of $50, subject to
the Pledge of such Note by such Holder pursuant to the Pledge Agreement,  or (b)
if the Note has been remarketed by the  Remarketing  Agent (or if the Holder has
elected not to have the Note  remarketed  by  delivering  the  Opt-out  Treasury
Consideration specified by the Remarketing Agent), the Agent-purchased  Treasury
Consideration,  subject to the  Pledge of such  Treasury  Consideration  by such
Holder pursuant to the Pledge  Agreement,  or (c) if a Tax Event  Redemption has
occurred, the Applicable Ownership Interest in the Treasury Portfolio subject to
the Pledge of such  Applicable  Ownership  Interest  in the  Treasury  Portfolio
pursuant to the Pledge  Agreement,  and (ii) the rights and  obligations  of the
Holder under one Forward  Purchase  Contract with the Company.  All  capitalized
terms used herein which are defined in the Forward Purchase  Contract  Agreement
have the meaning set forth therein.

     Pursuant  to the  Pledge  Agreement,  the Note,  the  appropriate  Treasury
Consideration or the Applicable Ownership Interest in the Treasury Portfolio, as
the case may be, constituting part of each Equity Unit evidenced hereby has been
pledged to the Collateral  Agent, for the benefit of the Company,  to secure the
obligations of the Holder under the Forward Purchase Contract  comprising a part
of such Equity Unit.

     The Pledge  Agreement  provides that all payments in respect of the Pledged
Notes,  Pledged Treasury  Consideration or Pledged Applicable Ownership Interest
in the Treasury  Portfolio received by the Collateral Agent shall be paid by the
Collateral  Agent  by wire  transfer  in same day  funds  (i) in the case of (A)
quarterly  cash  distributions  on Equity  Units which  include  Pledged  Notes,
Pledged Treasury  Consideration or Pledged Applicable  Ownership Interest in the
Treasury  Portfolio  and (B) any  payments  in respect  of the  Notes,  Treasury
Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the
case may be,  that have been  released  from the Pledge  pursuant  to the Pledge
Agreement,  to the Agent to the account  designated by the Agent,  no later than
10:00 a.m.,  New York City time, on the Business Day such payment is received by
the Collateral Agent (provided that in the event such payment is received by the
Collateral  Agent on a day that is not a Business  Day or after  9:00 a.m.,  New
York City time, on a Business Day, then such payment shall be made no later than
9:30 a.m., New York City time, on the next succeeding  Business Day) and (ii) in
the  case  of  payments  in  respect  of any  Pledged  Notes,  Pledged  Treasury
Consideration  or  Pledged   Applicable   Ownership  Interest  in  the  Treasury
Portfolio,  as the case may be,  to be paid  upon  settlement  of such  Holder's
obligations to purchase Common Stock under the Forward Purchase Contract, to the
Company on the Stock  Purchase Date (as defined  herein) in accordance  with the
terms  of  the  Pledge  Agreement,   in  full  satisfaction  of  the  respective
obligations  of the  Holders of the Equity  Units of which such  Pledged  Notes,
Pledged Treasury  Consideration or Pledged Applicable  Ownership Interest in the
Treasury  Portfolio,  as the case may be, are a part under the Forward  Purchase
Contracts forming a part of such Equity Units. Quarterly distributions on Equity
Units which include Pledged Notes,  Pledged  Treasury  Consideration  or Pledged
Applicable  Ownership  Interest in the Treasury  Portfolio,  as the case may be,
which are payable  quarterly  in arrears on February  16, May 16,  August 16 and
November 16, each year,  commencing  August 16, 2002 (a "Payment Date"),  shall,
subject  to  receipt  thereof  by the Agent  from the  Collateral  Agent (if the
Collateral Agent is the registered  owner thereof),  be paid by the Agent to the
Person in whose name this Equity  Units  Certificate  (or a  Predecessor  Equity
Units Certificate) is registered at the close of business on the Record Date for
such Payment Date.

     Each Forward  Purchase  Contract  evidenced  hereby obligates the Holder of
this Equity Units  Certificate  to purchase,  and the Company to sell, on August
16,  2005 (the "Stock  Purchase  Date"),  at a price  equal to $50 (the  "Stated
Amount"),  a number of newly issued shares of common stock,  $6.50 par value per
share ("Common Stock"),  of the Company,  equal to the Settlement Rate unless on
or prior to the Stock  Purchase  Date there  shall have  occurred a  Termination
Event or a Cash  Settlement,  Early  Settlement or Merger Early  Settlement with
respect to the Equity Units of which such Forward  Purchase  Contract is a part,
all as  provided  in the  Forward  Purchase  Contract  Agreement  and more fully
described on the reverse hereof.  The Purchase Price (as defined herein) for the
shares of Common  Stock  purchased  pursuant to each Forward  Purchase  Contract
evidenced hereby, if not paid earlier,  shall be paid on the Stock Purchase Date
by  application of payments  received in respect of the Pledged  Notes,  Pledged
Treasury  Consideration or Pledged Applicable Ownership Interest in the Treasury
Portfolio,  as the case may be, pledged to secure the  obligations of the Holder
under such Forward Purchase  Contract in accordance with the terms of the Pledge
Agreement.

     Payments  on the  Notes,  the  appropriate  Treasury  Consideration  or the
Applicable  Ownership  Interest in the Treasury  Portfolio,  as the case may be,
will be  payable  at the  Office of the Agent in The City of New York or, at the
option of the  Company,  by check  mailed to the address of the Person  entitled
thereto as such address appears on the Equity Units Register or by wire transfer
to an account  specified by such Person at least five Business Days prior to the
applicable Payment Date.

     The  Company  shall pay on each  Payment  Date in respect  of each  Forward
Purchase Contract forming part of an Equity Unit evidenced hereby an amount (the
"Contract  Adjustment  Payment")  equal to 3.50% per year of the Stated  Amount,
computed  on the basis of a 360-day  year of twelve  30-day  months,  subject to
deferral  at the  option of the  Company as  provided  in the  Forward  Purchase
Contract Agreement and more fully described on the reverse hereof (provided that
if any date on which a Contract  Adjustment Payment is to be made on the Forward
Purchase  Contracts  is not a  Business  Day,  then  payment  of  such  Contract
Adjustment  Payment payable on such date will be made on the next succeeding day
which is a Business  Day,  and no interest or payment will be paid in respect of
such delay,  except  that if such next  succeeding  Business  Day is in the next
succeeding  calendar  year,  then such payment  will be made on the  immediately
preceding Business Day). Such Contract  Adjustment  Payments shall be payable to
the Person in whose name this Equity Units Certificate (or a Predecessor  Equity
Units Certificate) is registered at the close of business on the Record Date for
such Payment Date.

     Contract  Adjustment Payments will be payable at the Office of the Agent in
The City of New York or, at the option of the  Company,  by check  mailed to the
address of the Person  entitled  thereto as such  address  appears on the Equity
Units  Register or by wire transfer to the account  designated to the Agent by a
prior written notice by such Person  delivered at least five Business Days prior
to the  applicable  Payment  Date.  Reference  is  hereby  made  to the  further
provisions set forth on the reverse hereof,  which further  provisions shall for
all purposes have the same effect as if set forth at this place.

     Unless the  certificate of  authentication  hereon has been executed by the
Agent by manual  signature,  this Equity Units Certificate shall not be entitled
to any  benefit  under the Pledge  Agreement  or the Forward  Purchase  Contract
Agreement or be valid or obligatory for any purpose.


         IN WITNESS WHEREOF, the Company has caused this instrument to be duly
executed.


                               AMERICAN ELECTRIC POWER COMPANY, INC.


                               By:    _____________________________________
                                      Name:
                                      Title:



                               HOLDER SPECIFIED ABOVE (as to
                                    obligations of such Holder
                                    under the Forward Purchase
                                    Contracts evidenced hereby)

                               By:  THE BANK OF NEW YORK, not individually but
                                     solely as Attorney-in-Fact of such Holder


                               By:  __________________________________________
                                    Authorized Signatory



                      AGENT'S CERTIFICATE OF AUTHENTICATION

     This  is  one  of  the  Equity  Units  Certificates   referred  to  in  the
within-mentioned Forward Purchase Contract Agreement.

                                 THE BANK OF NEW YORK,
                                 as Forward Purchase Contract Agent


Dated: June 11, 2002             By: ___________________________________
                                     Authorized Signatory



<PAGE>


                  (Form of Reverse of Equity Units Certificate)

     Each Forward  Purchase  Contract  evidenced hereby is governed by a Forward
Purchase Contract  Agreement,  dated as of June 11, 2002 (as may be supplemented
from time to time,  the  "Forward  Purchase  Contract  Agreement"),  between the
Company and The Bank of New York, as Forward Purchase  Contract Agent (including
its successors thereunder, herein called the "Agent"), to which Forward Purchase
Contract Agreement and supplemental  agreements thereto reference is hereby made
for a description of the respective rights, limitations of rights,  obligations,
duties and immunities  thereunder of the Agent, the Company, and the Holders and
of the terms  upon  which the  Equity  Units  Certificates  are,  and are to be,
executed and delivered.

     Each Forward  Purchase  Contract  evidenced  hereby obligates the Holder of
this Equity Units Certificate to purchase, and the Company to sell, on the Stock
Purchase Date at a price equal to $50 (the "Purchase Price"), a number of shares
of Common Stock of the Company equal to the Settlement Rate, unless, on or prior
to the Stock Purchase Date, there shall have occurred a Termination  Event or an
Early Settlement, Merger Early Settlement or Cash Settlement with respect to the
Units of which such Forward Purchase  Contract is a part. The "Settlement  Rate"
is equal to (a) if the  Applicable  Market  Value (as defined  below) is greater
than or equal to $49.08 (the "Threshold  Appreciation Price"),  1.0187 shares of
Common Stock per Forward Purchase  Contract,  (b) if the Applicable Market Value
is less than the Threshold  Appreciation  Price but is greater than $40.90,  the
number of shares of Common  Stock per  Forward  Purchase  Contract  equal to the
Stated Amount of the related Equity Units divided by the Applicable Market Value
and (c) if the Applicable  Market Value is less than or equal to $40.90,  1.2225
shares of Common Stock per Forward  Purchase  Contract,  in each case subject to
adjustment as provided in the Forward Purchase Contract Agreement. No fractional
shares of Common  Stock  will be issued  upon  settlement  of  Forward  Purchase
Contracts, as provided in the Forward Purchase Contract Agreement.

     The  "Applicable  Market  Value" means the average of the Closing Price per
share of Common Stock on each of the 20  consecutive  Trading Days ending on the
third Trading Day immediately preceding the Stock Purchase Date.

     The "Closing Price" of the Common Stock on any date of determination  means
the closing sale price (or, if no closing  price is reported,  the last reported
sale price) of the Common Stock on the New York Stock  Exchange  (the "NYSE") on
such date or, if the Common  Stock is not listed for  trading on the NYSE on any
such date, as reported in the composite  transactions  for the principal  United
States  securities  exchange on which the Common  Stock is so listed,  or if the
Common Stock is not so listed on a United States national or regional securities
exchange, as reported by The NASDAQ Stock Market, or, if the Common Stock is not
so   reported,   the  last  quoted  bid  price  for  the  Common  Stock  in  the
over-the-counter  market as reported by the National Quotation Bureau or similar
organization,  or, if such bid price is not  available,  the market value of the
Common Stock on such date as determined by a nationally  recognized  independent
investment banking firm retained for this purpose by the Company.

     A "Trading  Day" means a day on which the Common Stock (A) is not suspended
from trading on any national or regional  securities  exchange or association or
over-the-counter  market at the close of  business  and (B) has  traded at least
once  on  the  national  or  regional  securities  exchange  or  association  or
over-the-counter market that is the primary market for the trading of the Common
Stock.

     Each Forward Purchase Contract evidenced hereby may be settled prior to the
Stock Purchase Date through Early Settlement or Merger Early Settlement, and may
be settled on the Stock Purchase Date through Cash Settlement, all in accordance
with the terms of the Forward Purchase Contract Agreement.

     In accordance with the terms of the Forward  Purchase  Contract  Agreement,
the Holder of this Equity Units Certificate shall pay the Purchase Price for the
shares of Common  Stock  purchased  pursuant to each Forward  Purchase  Contract
evidenced hereby (i) by effecting a Cash Settlement,  Early Settlement or Merger
Early  Settlement,  (ii) by application  of payments  received in respect of the
Pledged  Treasury  Consideration  acquired from the proceeds of a remarketing of
the related Pledged Notes underlying the Equity Units represented by this Equity
Units  Certificate,  (iii) if the Holder has elected not to  participate  in the
remarketing,  by  application  of  payments  received  in respect of the Pledged
Treasury  Consideration  deposited  by such  Holder in respect  of such  Forward
Purchase  Contract,  or (iv) if a Tax Event Redemption has occurred prior to the
successful  remarketing of the Notes,  by  application  of payments  received in
respect of the Pledged  Applicable  Ownership Interest in the Treasury Portfolio
purchased by the  Collateral  Agent on behalf of the Holder of this Equity Units
Certificate.  If, as provided in the Forward Purchase Contract  Agreement,  upon
the occurrence of the Last Failed  Remarketing,  the Collateral  Agent,  for the
benefit of the Company,  exercises its rights as a secured creditor with respect
to the Pledged Notes related to this Equity Units  Certificate,  any accrued and
unpaid  interest on such Pledged Notes will become payable by the Company to the
Holder of this  Equity  Units  Certificate  in the  manner  provided  for in the
Forward Purchase Contract Agreement.

     The Company  shall not be  obligated to issue any shares of Common Stock in
respect of a Forward Purchase Contract or deliver any certificates or book-entry
interest therefor to the Holder unless it shall have received payment in full of
the  aggregate  Purchase  Price for the shares of Common  Stock to be  purchased
thereunder in the manner herein set forth.

     Under the terms of the  Pledge  Agreement,  the Agent will be  entitled  to
exercise the voting and any other  consensual  rights  pertaining to the Pledged
Notes, but only to the extent instructed by the Holders as described below. Upon
receipt of notice of any meeting at which  holders of Notes are entitled to vote
or upon the  solicitation  of consents,  waivers or proxies of holders of Notes,
the Agent  shall,  as soon as  practicable  thereafter,  mail to the  Holders of
Equity Units a notice (a)  containing  such  information  as is contained in the
notice or solicitation, (b) stating that each such Holder on the record date set
by the Agent therefor (which, to the extent possible,  shall be the same date as
the record date for  determining the holders of Notes entitled to vote) shall be
entitled  to  instruct  the  Agent  as to  the  exercise  of the  voting  rights
pertaining to the Pledged  Notes  constituting  a part of such  Holder's  Equity
Units and (c) stating the manner in which such  instructions may be given.  Upon
the written  request of the Holders of Equity  Units on such  record  date,  the
Agent shall endeavor  insofar as  practicable  to vote or cause to be voted,  in
accordance with the instructions set forth in such requests,  the maximum number
of Pledged Notes as to which any particular voting instructions are received. In
the  absence of specific  instructions  from the Holder of an Equity  Unit,  the
Agent shall abstain from voting the Pledged Note evidenced by such Equity Units.

     The Equity Units Certificates are issuable only in registered form and only
in denominations of a single Equity Unit and any integral multiple thereof.  The
transfer of any Equity Units  Certificate  will be  registered  and Equity Units
Certificates  may be  exchanged  as provided in the  Forward  Purchase  Contract
Agreement.  The Equity Units Registrar may require a Holder, among other things,
to furnish  appropriate  endorsements  and transfer  documents  permitted by the
Forward Purchase Contract Agreement. No service charge shall be required for any
such  registration  of transfer or  exchange,  but the Company and the Agent may
require  payment  of a sum  sufficient  to cover  any tax or other  governmental
charge  payable  in  connection  therewith.  The  Holder of an Equity  Units may
substitute  for the Pledged  Notes  securing its  obligations  under the related
Forward Purchase  Contract  Treasury  Securities in accordance with the terms of
the Forward Purchase Contract Agreement and the Pledge Agreement. From and after
such  Collateral  Substitution,  the  Units  for  which  such  Pledged  Treasury
Securities  secure the Holder's  obligation under the Forward Purchase  Contract
shall be referred to as a "Stripped  Unit." A Holder that elects to substitute a
Treasury  Security for Pledged Notes thereby creating  Stripped Units,  shall be
responsible for any fees or expenses payable in connection therewith.  Except as
provided in the Forward Purchase Contract Agreement,  for so long as the Forward
Purchase Contract  underlying an Equity Unit remains in effect, such Equity Unit
shall  not  be  separable  into  its  constituent  parts,  and  the  rights  and
obligations of the Holder of such Equity Unit in respect of the Pledged Note and
Forward Purchase  Contract  constituting such Equity Unit may be transferred and
exchanged only as an Equity Unit.

     A Holder of Stripped  Units may  reestablish  Equity Units by delivering to
the Collateral  Agent Notes in exchange for the release of the Pledged  Treasury
Securities  in  accordance  with the  terms  of the  Forward  Purchase  Contract
Agreement and the Pledge Agreement.

     Subject to the next  succeeding  paragraph,  the Company  shall pay on each
Payment Date, the Contract  Adjustment  Payments,  if any, payable in respect of
each  Forward  Purchase  Contract  to the Person in whose name the Equity  Units
Certificate evidencing such Forward Purchase Contract is registered at the close
of  business  on the Record  Date for such  Payment  Date.  Contract  Adjustment
Payments,  if any, will be payable at the office of the Agent in the City of New
York or, at the option of the  Company,  by check  mailed to the  address of the
Person  entitled  thereto at such  address  as it  appears  on the Equity  Units
Register or by wire transfer to the account designated by such Person in writing
at least five Business Days prior to the applicable Payment Date.

     The Company shall have the right,  at any time prior to the Stock  Purchase
Date,  to defer the payment of any or all of the  Contract  Adjustment  Payments
otherwise  payable on any Payment  Date,  but only if the Company shall give the
Holders  and  the  Agent  written  notice  of its  election  to  defer  Contract
Adjustment Payments as provided in the Forward Purchase Contract Agreement.  Any
Contract  Adjustment Payments so deferred shall, to the extent permitted by law,
bear additional  Contract  Adjustment  Payments thereon at the rate of 5.75% per
year  (computed  on the  basis  of a  360-day  year of  twelve  30-day  months),
compounding on each succeeding  Payment Date,  until paid in full (such deferred
installments  of  Contract  Adjustment  Payments,  if  any,  together  with  the
additional Contract Adjustment  Payments,  if any, accrued thereon, are referred
to herein as the "Deferred  Contract  Adjustment  Payments").  Deferred Contract
Adjustment  Payments,  if any, shall be due on the next succeeding  Payment Date
except to the extent that payment is deferred  pursuant to the Forward  Purchase
Contract  Agreement.  No Contract  Adjustment Payments may be deferred to a date
that is after the Stock Purchase Date and no such deferral  period may end other
than on a Payment Date.

     In the event  that the  Company  elects to defer the  payment  of  Contract
Adjustment Payments on the Forward Purchase Contracts until a Payment Date prior
to the Stock Purchase Date, then all Deferred Contract Adjustment  Payments,  if
any, shall be payable to the  registered  Holders as of the close of business on
the Record Date immediately preceding such Payment Date.

     In the event the  Company  exercises  its  option to defer the  payment  of
Contract  Adjustment  Payments,  then,  until the Deferred  Contract  Adjustment
Payments have been paid, the Company shall not declare or pay dividends on, make
distributions  with  respect  to, or  redeem,  purchase  or  acquire,  or make a
liquidation  payment  with  respect  to, any of its Common  Stock other than (i)
purchases,  redemptions or  acquisitions of shares of Common Stock in connection
with any employment contract,  benefit plan or other similar arrangement with or
for the benefit of  employees,  officers  or  directors  or a stock  purchase or
dividend   reinvestment  plan,  or  the  satisfaction  by  the  Company  of  its
obligations  pursuant to any  contract or security  outstanding  on the date the
Company exercises its rights to defer the Contract Adjustment Payments;  (ii) as
a result of a reclassification of the Company's Capital Stock or the exchange or
conversion  of one  class  or  series  of for  another  class or  series  of the
Company's Capital Stock; (iii) the purchase of fractional interests in shares of
any series of the Company's  Common Stock pursuant to the conversion or exchange
provisions  of such Common Stock or the security  being  converted or exchanged;
(iv) dividends or  distributions in any series of the Company's Common Stock (or
rights to acquire Common Stock) or  repurchases,  acquisitions or redemptions of
Common Stock in connection with the issuance or exchange of any series of Common
Stock  (or  securities  convertible  into  or  exchangeable  for  shares  of the
Company's  Common Stock);  or (v)  redemptions,  exchanges or repurchases of any
rights outstanding under a shareholder rights plan or the declaration or payment
thereunder  of a dividend or  distribution  of or with  respect to rights in the
future.

     The  Forward  Purchase  Contracts  and all  obligations  and  rights of the
Company and the Holders thereunder,  including,  without limitation,  the rights
and  obligations  of the Holders to receive and the obligation of the Company to
pay Contract  Adjustment  Payments,  if any, or any Deferred Contract Adjustment
Payments,  and the  rights  of the  Holders  to  purchase  Common  Stock,  shall
immediately and automatically terminate,  without the necessity of any notice or
action by any  Holder,  the Agent or the  Company,  if, on or prior to the Stock
Purchase Date, a Termination Event shall have occurred. Upon the occurrence of a
Termination  Event,  the Company  shall  promptly but in no event later than two
Business Days thereafter give written notice to the Agent,  the Collateral Agent
and to the  Holders,  at their  addresses  as they  appear in the  Equity  Units
Register.  Upon and after the occurrence of a Termination  Event, the Collateral
Agent shall release the Pledged Notes, Pledged Treasury Consideration or Pledged
Applicable  Ownership  Interest in the Treasury  Portfolio,  as the case may be,
from the Pledge in accordance with the provisions of the Pledge Agreement.

     Upon  registration  of  transfer  of this  Equity  Units  Certificate,  the
transferee shall be bound (without the necessity of any other action on the part
of such  transferee,  except as may be  required  by the Agent  pursuant  to the
Forward  Purchase  Contract  Agreement),  by the terms of the  Forward  Purchase
Contract Agreement and the Forward Purchase  Contracts  evidenced hereby and the
transferor  shall be released from the  obligations  under the Forward  Purchase
Contracts evidenced by this Equity Units Certificate.  The Company covenants and
agrees, and the Holder, by its acceptance hereof, likewise covenants and agrees,
to be bound by the provisions of this paragraph.

     The Holder of this Equity  Units  Certificate,  by its  acceptance  hereof,
authorizes  the Agent to enter into and  perform the  related  Forward  Purchase
Contracts forming part of the Equity Units evidenced hereby on its behalf as its
attorney-in-fact,  expressly  withholds  any  consent to the  assumption  (i.e.,
affirmance) of the Forward  Purchase  Contracts by the Company or its trustee in
the event that the Company  becomes  the subject of a case under the  Bankruptcy
Code,  agrees to be bound by the terms and  provisions  of the Forward  Purchase
Contracts,  covenants and agrees to perform such Holder's obligations under such
Forward Purchase  Contracts,  consents to the provisions of the Forward Purchase
Contract Agreement,  irrevocably  authorizes the Agent to enter into and perform
the Pledge Agreement on such Holder's behalf as  attorney-in-fact,  and consents
to and agrees to be bound by the Pledge of the Notes or the appropriate Treasury
Consideration or Applicable Ownership Interest in the Treasury Portfolio, as the
case may be,  underlying  this Equity Units  Certificate  pursuant to the Pledge
Agreement,  provided, that upon a Termination Event, the rights of the Holder of
such Units under the Forward Purchase Contract may be enforced without regard to
any other rights or obligations.  The Holder further covenants and agrees, that,
to the  extent and in the  manner  provided  in the  Forward  Purchase  Contract
Agreement and the Pledge Agreement,  but subject to the terms thereof,  payments
in respect of the  Pledged  Notes,  Pledged  Treasury  Consideration  or Pledged
Applicable Ownership Interest in the Treasury Portfolio,  as the case may be, to
be paid upon  settlement of such Holder's  obligations to purchase  Common Stock
under the Forward Purchase Contract, shall be paid on the Stock Purchase Date by
the Collateral Agent to the Company in satisfaction of such Holder's obligations
under such Forward  Purchase  Contract  and such Holder shall  acquire no right,
title or interest in such payments.

     The Company and each Holder of an Equity Unit,  and each  Beneficial  Owner
thereof, by its acceptance thereof or of its interest therein, further agrees to
treat (i) the purchase of Equity Units as the purchase of a unit  consisting  of
the Forward Purchase Contract and the Note and to allocate the purchase price of
the Equity Unit  between the Note and the Forward  Purchase  Contract as $50 and
$0, respectively, and (ii) the holder as the owner of the applicable interest in
the Collateral Account,  including the related Notes, Treasury  Consideration or
Applicable Ownership Interest in the Treasury Portfolio, as the case may be.

     Subject to certain  exceptions,  the  provisions  of the  Forward  Purchase
Contract  Agreement may be amended with the consent of the Holders of a majority
of the Forward Purchase Contracts.

     The Forward  Purchase  Contracts shall for all purposes be governed by, and
construed in accordance with, the laws of the State of New York,  without regard
to its principles of conflicts of laws. The Company,  the Agent and any agent of
the  Company or the Agent may treat the Person in whose name this  Equity  Units
Certificate is registered as the owner of the Equity Units evidenced  hereby for
the  purpose  of  receiving  quarterly  payments  on  the  Notes,  the  Treasury
Consideration or the Applicable Ownership Interest in the Treasury Portfolio, as
the case may be, receiving payments of Contract Adjustment Payments, if any, and
any Deferred Contract Adjustment  Payments,  performance of the Forward Purchase
Contracts  and for all other  purposes  whatsoever  (subject  to the Record Date
provisions  hereof),  whether or not any payments in respect  thereof be overdue
and  notwithstanding  any notice to the contrary,  and neither the Company,  the
Agent, nor any such agent shall be affected by notice to the contrary.

     The Forward Purchase Contracts shall not, prior to the settlement  thereof,
entitle the Holder to any of the rights of a holder of shares of Common Stock.

     A copy  of  the  Forward  Purchase  Contract  Agreement  is  available  for
inspection by any Holder at the Corporate Trust Office.



<PAGE>


                                  ABBREVIATIONS

     The following  abbreviations,  when used in the  inscription on the face of
this  instrument,  shall be  construed  as though they were  written out in full
according to applicable laws or regulations:

TEN COM -               as tenants in common
UNIF GIFT MIN ACT -     Custodian
                        (cust)              (minor)
                        Under Uniform Gifts to Minors Act
                                            (State)
TEN ENT -               as tenants by the entireties
JT TEN -                as joint tenants with right of survivorship
                        and not as tenants in common

     Additional abbreviations may also be used though not in the above list.



<PAGE>


                                   ASSIGNMENT

FOR VALUE RECEIVED,  the undersigned  hereby sell(s),  assign(s) and transfer(s)
unto

(Please insert Social Security or Taxpayer I.D. or other  Identifying  Number of
Assignee)

(Please Print or Type Name and Address Including Postal Zip Code of Assignee)

the  within  Equity  Units  Certificate  and  all  rights   thereunder,   hereby
irrevocably constituting and appointing  ___________________________ attorney to
transfer said Equity Units  Certificate on the books of American  Electric Power
Company, Inc. with full power of substitution in the premises.

Dated: _________________________

Signature: _____________________________

     NOTICE:  The signature to this  assignment must correspond with the name as
it  appears  upon the  face of the  within  Equity  Units  Certificate  in every
particular, without alteration or enlargement or any change whatsoever.

Signature Guarantee: ___________________________.



<PAGE>


                             SETTLEMENT INSTRUCTIONS

     The  undersigned  Holder directs that a certificate or book-entry  interest
for shares of Common Stock  deliverable  upon  settlement  on or after the Stock
Purchase Date of the Forward Purchase Contracts  underlying the number of Equity
Units  evidenced by this Equity Units  Certificate be registered in the name of,
and delivered, together with a check in payment for any fractional share, to the
undersigned at the address  indicated  below unless a different name and address
have been  indicated  below.  If shares  are to be  registered  in the name of a
Person other than the  undersigned,  the  undersigned  will pay any transfer tax
payable incident thereto.

Dated: ______________________               Signature: _________________________

                                            Signature Guarantee: _______________
                                            (if assigned to another person)

If shares are to be registered in the name of REGISTERED HOLDER and delivered to
a Person other than the Holder, please (i) print such Person's name Please print
name and  address of and  address and (ii)  provide a  guarantee  of  Registered
Holder: your signature:

Name                                        Name

Address                                     Address

Social Security or other Taxpayer
Identification Number, if any


<PAGE>


                            ELECTION TO SETTLE EARLY

     The undersigned  Holder of this Equity Units Certificate hereby irrevocably
exercises the option to effect Early  Settlement in accordance with the terms of
the Forward  Purchase  Contract  Agreement with respect to the Forward  Purchase
Contracts  underlying the number of Equity Units  evidenced by this Equity Units
Certificate  specified  below.  The  option to effect  Early  Settlement  may be
exercised  only with respect to Forward  Purchase  Contracts  underlying  Equity
Units with an aggregate  Stated  Amount equal to $1,000 or an integral  multiple
thereof.  The  undersigned  Holder  directs  that a  certificate  or  book-entry
interest for shares of Common Stock  deliverable  upon such Early  Settlement be
registered in the name of, and  delivered,  together with a check in payment for
any fractional  share and any Equity Units  Certificate  representing any Equity
Units  evidenced  hereby as to which Early  Settlement  of the  related  Forward
Purchase Contracts is not effected,  to the undersigned at the address indicated
below unless a different name and address have been indicated below. The Pledged
Notes,  Pledged Treasury  Consideration or Pledged Applicable Ownership Interest
in the  Treasury  Portfolio,  as the case may be,  deliverable  upon such  Early
Settlement will be transferred in accordance with the transfer  instructions set
forth below.  If shares are to be  registered in the name of a Person other than
the  undersigned,  the  undersigned  will pay any transfer tax payable  incident
thereto.

Dated: ____________________           Signature: ___________________________

                                      Signature Guarantee: _________________

     Number  of Units  evidenced  hereby  as to which  Early  Settlement  of the
related Forward Purchase Contracts is being elected:

If shares of Common Stock are to be        EGISTERED HOLDER
registered in the name of
and delivered to and Pledged Notes,        Please print name and address of
Pledged Treasury Consideration or          Registered Holder:
Pledged Applicable Ownership
Interest in the Treasury Portfolio, as
the case may be, are to be transferred
to a Person other than the Holder,
please print such Person's name and
address:


Name                                        Name

Address                                     Address

Social Security or other Taxpayer
Identification Number, if any

     Transfer instructions for Pledged Notes, Pledged Treasury  Consideration or
the Pledged Applicable Ownership Interest in the Treasury Portfolio, as the case
may be, transferable upon Early Settlement or a Termination Event:



<PAGE>
<TABLE>
<CAPTION>


                     (TO BE ATTACHED TO GLOBAL CERTIFICATES)

            SCHEDULE OF INCREASES OR DECREASES IN GLOBAL CERTIFICATE

     The following  increases or decreases in this Global  Certificate have been
made:

<S>      <C>                   <C>                     <C>                       <C>
                                                          Stated Amount of the
         Amount of Decrease in  Amount of Increase in    Global Certificate
         Stated Amount of the   Stated Amount of the    Following Such Decrease        Signature of
 Date     Global Certificate     Global Certificate           or Increase          Authorized Signatory


</TABLE>
<PAGE>
                                    EXHIBIT B

                       FORM OF STRIPPED UNITS CERTIFICATE

     [FOR INCLUSION IN GLOBAL  CERTIFICATES ONLY -- THIS CERTIFICATE IS A GLOBAL
CERTIFICATE  WITHIN THE MEANING OF THE FORWARD PURCHASE  CONTRACT  AGREEMENT (AS
HEREINAFTER  DEFINED) AND IS  REGISTERED  IN THE NAME OF A CLEARING  AGENCY OR A
NOMINEE THEREOF. THIS CERTIFICATE MAY NOT BE EXCHANGED IN WHOLE OR IN PART FOR A
CERTIFICATE REGISTERED,  AND NO TRANSFER OF THIS CERTIFICATE IN WHOLE OR IN PART
MAY BE REGISTERED,  IN THE NAME OF ANY PERSON OTHER THAN SUCH CLEARING AGENCY OR
A NOMINEE THEREOF,  EXCEPT IN THE LIMITED CIRCUMSTANCES DESCRIBED IN THE FORWARD
PURCHASE CONTRACT AGREEMENT.

     Unless this Certificate is presented by an authorized representative of The
Depository Trust Company (55 Water Street, New York, New York) to the Company or
its agent for registration of transfer, exchange or payment, and any Certificate
issued is  registered in the name of Cede & Co., or such other name as requested
by an authorized representative of The Depository Trust Company, and any payment
hereon is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER USE HEREOF FOR VALUE
OR OTHERWISE BY A PERSON IS WRONGFUL since the registered  owner hereof,  Cede &
Co., has an interest herein.]

                  (Form of Face of Stripped Units Certificate)

No.                                                      CUSIP No. ____________

Number of Stripped Units

     This Stripped  Units  Certificate  certifies  that [For inclusion in Global
Certificates  only -- Cede & Co.] is the  registered  Holder  of the  number  of
Stripped Units set forth above [For inclusion in Global  Certificates  only - or
such other  number of Stripped  Units  reflected in the Schedule of Increases or
Decreases in Global Certificate attached hereto].  Each Stripped Unit represents
(i) a 1/20  undivided  beneficial  ownership  interest  in a Treasury  Security,
subject to the Pledge of such interest in such Treasury  Security by such Holder
pursuant to the Pledge  Agreement,  and (ii) the rights and  obligations  of the
Holder under one Forward Purchase Contract with American Electric Power Company,
Inc., a New York corporation (the "Company").  All capitalized terms used herein
which are defined in the Forward  Purchase  Contract  Agreement have the meaning
set forth therein.

     Pursuant to the Pledge Agreement,  the Treasury Security  constituting part
of each Stripped Unit evidenced hereby has been pledged to the Collateral Agent,
for the benefit of the Company,  to secure the  obligations  of the Holder under
the Forward Purchase Contract comprising a part of such Stripped Units.

     Each Forward  Purchase  Contract  evidenced  hereby obligates the Holder of
this Stripped  Units  Certificate  to purchase,  and the Company to sell, on the
Stock Purchase Date, at a price equal to $50 (the "Stated Amount"),  a number of
shares of common  stock,  $6.50 par  value per share  ("Common  Stock"),  of the
Company,  equal to the Settlement Rate, unless on or prior to the Stock Purchase
Date there  shall  have  occurred a  Termination  Event or an Early  Settlement,
Merger Early Settlement or Cash Settlement with respect to the Stripped Units of
which such Forward  Purchase  Contract is a part, all as provided in the Forward
Purchase Contract  Agreement and more fully described on the reverse hereof. The
Purchase  Price (as  defined  herein) for the shares of Common  Stock  purchased
pursuant  to each  Forward  Purchase  Contract  evidenced  hereby,  if not  paid
earlier,  shall be paid on the Stock  Purchase Date by  application  of payments
received in respect of the  Pledged  Treasury  Securities  pledged to secure the
obligations under such Forward Purchase Contract in accordance with the terms of
the Pledge Agreement.

     The  Company  shall pay on each  Payment  Date in respect  of each  Forward
Purchase  Contract  forming part of a Stripped Units evidenced  hereby an amount
(the  "Contract  Adjustment  Payments")  equal to 3.50%  per year of the  Stated
Amount, computed on the basis of a 360-day year of twelve 30-day months, subject
to deferral  at the option of the  Company as  provided in the Forward  Purchase
Contract Agreement and more fully described on the reverse hereof (provided that
if any date on which Contract  Adjustment Payments are to be made on the Forward
Purchase  Contracts  is  not a  Business  Day,  then  payment  of  the  Contract
Adjustment Payments payable on that date will be made on the next succeeding day
which is a Business  Day,  and no interest or payment will be paid in respect of
the  delay,  except  that if such next  succeeding  Business  Day is in the next
succeeding calendar year, such payment will be made on the immediately preceding
Business Day). Such Contract  Adjustment Payments shall be payable to the Person
in whose name this Stripped Units  Certificate (or a Predecessor  Stripped Units
Certificate)  is registered at the close of business on the Record Date for such
Payment Date.

     Contract Adjustment Payments,  if any, will be payable at the Office of the
Agent in the City of New York or, at the option of the Company,  by check mailed
to the address of the Person  entitled  thereto at such address as it appears on
the Stripped  Units  Register or by wire  transfer to the account  designated by
such  Person in  writing  at least five  Business  Days prior to the  applicable
Payment Date.

     Reference is hereby made to the further provisions set forth on the reverse
hereof,  which further provisions shall for all purposes have the same effect as
if set forth at this place.

     Unless the  certificate of  authentication  hereon has been executed by the
Agent by manual signature, this Stripped Units Certificate shall not be entitled
to any  benefit  under the Pledge  Agreement  or the Forward  Purchase  Contract
Agreement or be valid or obligatory for any purpose.



<PAGE>


     IN WITNESS  WHEREOF,  the  Company has caused  this  instrument  to be duly
executed.

                            AMERICAN ELECTRIC POWER COMPANY, INC.

                            By: ____________________________________
                                   Name:
                                   Title:

                            HOLDER SPECIFIED ABOVE (as to obligations of such
                                Holder under the Forward Purchase Contracts)

                            By:    THE BANK OF NEW YORK, not individually but
                                   solely as Attorney-in-Fact of such Holder


                            By: ____________________________________
                                  Authorized Signatory


<PAGE>


                      AGENT'S CERTIFICATE OF AUTHENTICATION

     This  is one of the  Stripped  Units  referred  to in the  within-mentioned
Forward Purchase Contract Agreement.

                                        THE BANK OF NEW YORK,
                                        as Forward Purchase Contract Agent


Dated: June 11, 2002                 By:_____________________________________
                                                 Authorized Signatory



<PAGE>


                     (Reverse of Stripped Units Certificate)

     Each Forward  Purchase  Contract  evidenced hereby is governed by a Forward
Purchase Contract  Agreement,  dated as of June 11, 2002 (as may be supplemented
from time to time,  the  "Forward  Purchase  Contract  Agreement"),  between the
Company and The Bank of New York, as Forward Purchase  Contract Agent (including
its successors thereunder, herein called the "Agent"), to which Forward Purchase
Contract Agreement and supplemental  agreements thereto reference is hereby made
for a description of the respective rights, limitations of rights,  obligations,
duties and immunities  thereunder of the Agent,  the Company and the Holders and
of the terms upon which the  Stripped  Units  Certificates  are,  and are to be,
executed and delivered.

     Each Forward  Purchase  Contract  evidenced  hereby obligates the Holder of
this Stripped  Units  Certificate  to purchase,  and the Company to sell, on the
Stock Purchase Date at a price equal to $50 (the "Purchase  Price"), a number of
shares of Common Stock of the Company equal to the Settlement Rate,  unless,  on
or prior to the Stock  Purchase  Date,  there shall have  occurred a Termination
Event or an Early  Settlement  or Merger  Early  Settlement  with respect to the
Stripped  Units  of  which  such  Forward  Purchase  Contract  is  a  part.  The
"Settlement  Rate" is equal to (a) if the  Applicable  Market  Value (as defined
below) is greater than or equal to $49.08 (the "Threshold  Appreciation Price"),
1.0187  shares  of  Common  Stock  per  Forward  Purchase  Contract,  (b) if the
Applicable  Market Value is less than the  Threshold  Appreciation  Price but is
greater than $40.90,  the number of shares of Common Stock per Forward  Purchase
Contract equal to the Stated Amount of the related Stripped Units divided by the
Applicable  Market Value and (c) if the Applicable  Market Value is less than or
equal $40.90,  1.2225 shares of Common Stock per Forward Purchase  Contract,  in
each case subject to  adjustment  as provided in the Forward  Purchase  Contract
Agreement.  No fractional  shares of Common Stock will be issued upon settlement
of Forward  Purchase  Contracts,  as provided in the Forward  Purchase  Contract
Agreement.

     The  "Applicable  Market  Value" means the average of the Closing Price per
share of Common Stock on each of the 20  consecutive  Trading Days ending on the
third Trading Day immediately preceding the Stock Purchase Date.

         The "Closing Price" of the Common Stock on any date of determination
means the closing sale price (or, if no closing price is reported, the last
reported sale price) of the Common Stock on the New York Stock Exchange (the
"NYSE") on such date or, if the Common Stock is not listed for trading on the
NYSE on any such date, as reported in the composite transactions for the
principal United States securities exchange on which the Common Stock is so
listed, or if the Common Stock is not so listed on a United States national or
regional securities exchange, as reported by The NASDAQ Stock Market, or, if the
Common Stock is not so reported, the last quoted bid price for the Common Stock
in the over-the-counter market as reported by the National Quotation Bureau or
similar organization, or, if such bid price is not available, the market value
of the Common Stock on such date as determined by a nationally recognized
independent investment banking firm retained for this purpose by the Company.

     A "Trading  Day" means a day on which the Common Stock (A) is not suspended
from trading on any national or regional  securities  exchange or association or
over-the-counter  market at the close of  business  and (B) has  traded at least
once  on  the  national  or  regional  securities  exchange  or  association  or
over-the-counter market that is the primary market for the trading of the Common
Stock.

     Each Forward Purchase Contract evidenced hereby may be settled prior to the
Stock Purchase Date through Early Settlement or Merger Early Settlement, and may
be settled on the Stock Purchase Date through Cash Settlement, all in accordance
with the terms of the Forward Purchase Contract Agreement.

     In accordance with the terms of the Forward  Purchase  Contract  Agreement,
the Holder of this Stripped Units  Certificate  shall pay the Purchase Price for
the shares of Common Stock purchased  pursuant to each Forward Purchase Contract
evidenced hereby (i) by effecting an Early  Settlement,  Merger Early Settlement
or Cash Settlement or (ii) by application of payments received in respect of the
Pledged Treasury  Securities  underlying the Stripped Units  represented by this
Stripped Units Certificate.

     The Company  shall not be  obligated to issue any shares of Common Stock in
respect of a Forward Purchase Contract or deliver any certificates or book-entry
interest therefor to the Holder unless it shall have received payment in full of
the  aggregate  Purchase  Price for the shares of Common  Stock to be  purchased
thereunder in the manner herein set forth.

     The Stripped Units  Certificates  are issuable only in registered  form and
only in  denominations  of a single  Stripped  Units and any  integral  multiple
thereof.  The transfer of any Stripped Units  Certificate will be registered and
Stripped Units Certificates may be exchanged as provided in the Forward Purchase
Contract  Agreement.  The Stripped Units  Registrar may require a Holder,  among
other  things,  to  furnish  appropriate  endorsements  and  transfer  documents
permitted by the Forward Purchase Contract Agreement. No service charge shall be
required for any such registration of transfer or exchange,  but the Company and
the Agent may  require  payment  of a sum  sufficient  to cover any tax or other
governmental  charge payable in connection  therewith.  The Holder of a Stripped
Unit may substitute for the Pledged Treasury Securities securing its obligations
under the related Forward  Purchase  Contract Notes in accordance with the terms
of the Forward Purchase Contract  Agreement and the Pledge  Agreement.  From and
after such  substitution,  the Units for which  such  Pledged  Notes  secure the
Holder's  obligation under the Forward Purchase Contract shall be referred to as
an "Equity Unit." A Holder that elects to substitute  Notes for Pledged Treasury
Securities,  thereby  reestablishing  Equity Units, shall be responsible for any
fees or  expenses  payable in  connection  therewith.  Except as provided in the
Forward  Purchase  Contract  Agreement,  for so  long  as the  Forward  Purchase
Contract underlying a Stripped Unit remains in effect, such Stripped Units shall
not be separable into its constituent  parts,  and the rights and obligations of
the Holder of such Stripped  Units in respect of the Pledged  Treasury  Security
and the  Forward  Purchase  Contract  constituting  such  Stripped  Units may be
transferred and exchanged only as a Stripped Unit.

     Subject to the next  succeeding  paragraph,  the Company  shall pay on each
Payment Date, the Contract  Adjustment  Payments,  if any, payable in respect of
each Forward  Purchase  Contract to the Person in whose name the Stripped  Units
Certificate evidencing such Forward Purchase Contract is registered at the close
of  business  on the Record  Date for such  Payment  Date.  Contract  Adjustment
Payments,  if any, will be payable at the Office of the Agent in the City of New
York or, at the option of the  Company,  by check  mailed to the  address of the
Person  entitled  thereto at such  address as it appears on the  Stripped  Units
Register or by wire transfer to the account designated by such Person in writing
at least five Business Days prior to the applicable Payment Date.

     The Company shall have the right,  at any time prior to the Stock  Purchase
Date,  to defer the payment of any or all of the  Contract  Adjustment  Payments
otherwise  payable on any Payment  Date,  but only if the Company shall give the
Holders  and  the  Agent  written  notice  of its  election  to  defer  Contract
Adjustment Payments as provided in the Forward Purchase Contract Agreement.  Any
Contract  Adjustment Payments so deferred shall, to the extent permitted by law,
bear additional  Contract  Adjustment  Payments thereon at the rate of 5.75% per
year  (computed  on the  basis  of a  360-day  year of  twelve  30-day  months),
compounding on each succeeding  Payment Date,  until paid in full (such deferred
installments  of  Contract  Adjustment  Payments,  if  any,  together  with  the
additional Contract Adjustment  Payments,  if any, accrued thereon, are referred
to herein as the "Deferred  Contract  Adjustment  Payments").  Deferred Contract
Adjustment  Payments,  if any, shall be due on the next succeeding  Payment Date
except to the extent that payment is deferred  pursuant to the Forward  Purchase
Contract  Agreement.  No Contract  Adjustment Payments may be deferred to a date
that is after the Stock Purchase Date and no such deferral  period may end other
than on a Payment Date.

     In the event  that the  Company  elects to defer the  payment  of  Contract
Adjustment Payments on the Forward Purchase Contracts until a Payment Date prior
to the Stock Purchase Date, then all Deferred Contract Adjustment  Payments,  if
any, shall be payable to the  registered  Holders as of the close of business on
the Record Date immediately preceding such Payment Date.

     In the event the  Company  exercises  its  option to defer the  payment  of
Contract  Adjustment  Payments,  then,  until the Deferred  Contract  Adjustment
Payments have been paid, the Company shall not declare or pay dividends on, make
distributions  with  respect  to, or  redeem,  purchase  or  acquire,  or make a
liquidation  payment  with  respect  to, any of its Common  Stock other than (i)
purchases,  redemptions or  acquisitions of shares of Common Stock in connection
with any employment contract,  benefit plan or other similar arrangement with or
for the benefit of  employees,  officers  or  directors  or a stock  purchase or
dividend   reinvestment  plan,  or  the  satisfaction  by  the  Company  of  its
obligations  pursuant to any  contract or security  outstanding  on the date the
Company exercises its rights to defer the Contract Adjustment Payments;  (ii) as
a result of a reclassification of the Company's Capital Stock or the exchange or
conversion  of one class or series of the  Company's  Capital  Stock for another
class or series of the Company's Capital Stock; (iii) the purchase of fractional
interests in shares of any series of the Company's  Common Stock pursuant to the
conversion  or exchange  provisions  of such Common Stock or the security  being
converted or exchanged;  (iv)  dividends or  distributions  in any series of the
Company's  Common  Stock (or rights to  acquire  Common  Stock) or  repurchases,
acquisitions  or redemptions of Common Stock in connection  with the issuance or
exchange  of any  series of  Common  Stock (or  securities  convertible  into or
exchangeable  for shares of the  Company's  Common  Stock;  or (v)  redemptions,
exchanges or repurchases of any rights  outstanding  under a shareholder  rights
plan or the  declaration or payment  thereunder of a dividend or distribution of
or with respect to rights in the future.

     The  Forward  Purchase  Contracts  and all  obligations  and  rights of the
Company and the Holders thereunder,  including,  without limitation,  the rights
and  obligations  of Holders to receive and the obligation of the Company to pay
Contract  Adjustment  Payments,  if any,  or any  Deferred  Contract  Adjustment
Payments,  and the rights and  obligations of Holders to purchase  Common Stock,
shall  immediately  and  automatically  terminate,  without the necessity of any
notice or action by any Holder, the Agent or the Company, if, on or prior to the
Stock  Purchase  Date,  a  Termination  Event  shall  have  occurred.  Upon  the
occurrence of a Termination  Event,  the Company shall  promptly but in no event
later than two Business Days  thereafter  give written notice to the Agent,  the
Collateral  Agent and to the Holders,  at their  addresses as they appear in the
Stripped Units Register.  Upon and after the occurrence of a Termination  Event,
the  Collateral  Agent shall release the Pledged  Treasury  Securities  from the
Pledge in accordance with the provisions of the Pledge Agreement.

     Upon  registration  of transfer of this  Stripped  Units  Certificate,  the
transferee shall be bound (without the necessity of any other action on the part
of such  transferee,  except as may be  required  by the Agent  pursuant  to the
Forward  Purchase  Contract  Agreement),  by the terms of the  Forward  Purchase
Contract Agreement and the Forward Purchase  Contracts  evidenced hereby and the
transferor  shall be released from the  obligations  under the Forward  Purchase
Contracts  evidenced by this Stripped Units  Certificate.  The Company covenants
and agrees,  and the Holder, by its acceptance  hereof,  likewise  covenants and
agrees, to be bound by the provisions of this paragraph.

     The Holder of this Stripped Units  Certificate,  by its acceptance  hereof,
authorizes  the Agent to enter into and  perform the  related  Forward  Purchase
Contracts  forming part of the Stripped Units evidenced  hereby on its behalf as
its  attorney-in-fact,  expressly withholds any consent to the assumption (i.e.,
affirmance) of the Forward  Purchase  Contracts by the Company or its trustee in
the event that the Company  becomes  the subject of a case under the  Bankruptcy
Code,  agrees to be bound by the terms and  provisions  of the Forward  Purchase
Contracts,  covenants and agrees to perform such Holder's obligations under such
Forward Purchase  Contracts,  consents to the provisions of the Forward Purchase
Contract Agreement,  irrevocably  authorizes the Agent to enter into and perform
the Pledge Agreement on such Holder's behalf as  attorney-in-fact,  and consents
to and agrees to be bound by the Pledge of the  Treasury  Securities  underlying
this Stripped Units Certificate pursuant to the Pledge Agreement, provided, that
upon a  Termination  Event,  the rights of the  Holder of such  Units  under the
Forward Purchase  Contract may be enforced without regard to any other rights or
obligations. The Holder further covenants and agrees, that, to the extent and in
the manner provided in the Forward  Purchase  Contract  Agreement and the Pledge
Agreement, but subject to the terms thereof,  payments in respect of the Pledged
Treasury Securities,  to be paid upon settlement of such Holder's obligations to
purchase Common Stock under the Forward Purchase Contract,  shall be paid on the
Stock Purchase Date by the Collateral  Agent to the Company in  satisfaction  of
such Holder's  obligations  under such Forward Purchase Contract and such Holder
shall acquire no right, title or interest in such payments.

     The Company  and each Holder of any  Stripped  Units,  and each  Beneficial
Owner thereof,  by its acceptance  thereof or of its interest  therein,  further
agrees to treat (i) the  formation  of Stripped  Units as the purchase of a unit
consisting  of the Purchase  Contract and the Treasury  Securities  and (ii) the
holder  as the  owner of the  applicable  interest  in the  Collateral  Account,
including the Treasury Securities.

     Subject to certain  exceptions,  the  provisions  of the  Forward  Purchase
Contract  Agreement may be amended with the consent of the Holders of a majority
of the Forward Purchase Contracts.

     The Forward  Purchase  Contracts shall for all purposes be governed by, and
construed in accordance with, the laws of the State of New York,  without regard
to its principles of conflicts of laws.

     The Company,  the Agent and any agent of the Company or the Agent may treat
the Person in whose name this Stripped  Units  Certificate  is registered as the
owner of the Stripped  Units  evidenced  hereby for the purpose of receiving any
Contract  Adjustment  Payments and any Deferred  Contract  Adjustment  Payments,
performance  of the  Forward  Purchase  Contracts  and  for all  other  purposes
whatsoever  (subject to the Record Date provisions  hereof),  whether or not any
payments  in respect  thereof be overdue and  notwithstanding  any notice to the
contrary,  and  neither  the  Company,  the Agent,  nor any such agent  shall be
affected by notice to the contrary.

     The Forward Purchase Contracts shall not, prior to the settlement  thereof,
entitle the Holder to any of the rights of a holder of shares of Common Stock.

     A copy  of  the  Forward  Purchase  Contract  Agreement  is  available  for
inspection by any Holder at the Corporate Trust Office.



<PAGE>


                                  ABBREVIATIONS

     The following  abbreviations,  when used in the  inscription on the face of
this  instrument,  shall be  construed  as though they were  written out in full
according to applicable laws or regulations:

TEN COM -               as tenants in common
UNIF GIFT MIN ACT -     Custodian
                        (cust) (minor)
                        Under Uniform Gifts to Minors Act
                        (State)
TEN ENT -               as tenants by the entireties
JT TEN -                as joint tenants with right of survivorship and
                        not as tenants in common

     Additional abbreviations may also be used though not in the above list.



<PAGE>


                                   ASSIGNMENT

FOR VALUE RECEIVED,  the undersigned  hereby sell(s),  assign(s) and transfer(s)
unto

(Please insert Social Security or Taxpayer I.D. or other  Identifying  Number of
Assignee)

(Please Print or Type Name and Address Including Postal Zip Code of Assignee)

the  within  Stripped  Units  Certificate  and  all  rights  thereunder,  hereby
irrevocably constituting and appointing ____________________________ attorney to
transfer said Stripped Units Certificate on the books of American Electric Power
Company, Inc. with full power of substitution in the premises.

Dated: ______________________     Signature: ___________________________

          NOTICE: The signature to this assignment must correspond with the name
          as it appears upon the face of the within  Stripped Units  Certificate
          in every particular,  without  alteration or enlargement or any change
          whatsoever.

Signature Guarantee: ________________________



<PAGE>


                             SETTLEMENT INSTRUCTIONS

     The  undersigned  Holder directs that a certificate or book-entry  interest
for shares of Common Stock  deliverable  upon  settlement  on or after the Stock
Purchase  Date of the  Forward  Purchase  Contracts  underlying  the  number  of
Stripped Units evidenced by this Stripped Units Certificate be registered in the
name of, and  delivered,  together  with a check in payment  for any  fractional
share, to the undersigned at the address indicated below unless a different name
and address have been  indicated  below.  If shares are to be  registered in the
name of a  Person  other  than the  undersigned,  the  undersigned  will pay any
transfer tax payable incident thereto.

Dated: ___________________        Signature: _________________________________

                                  Signature Guarantee: _______________________
                                               (if assigned to another person)

If shares are to be registered in the    REGISTERED HOLDER
name of and delivered to a Person other
than the Holder, please (i) print such   Please print name and address of
Person's name and address and (ii)       Registered Holder:
provide a guarantee of your signature:

Name                                      Name


Address                                   Address


Social Security or other Taxpayer
Identification Number, if any


<PAGE>


                            ELECTION TO SETTLE EARLY

     The  undersigned   Holder  of  this  Stripped  Units   Certificate   hereby
irrevocably  exercises the option to effect Early  Settlement in accordance with
the terms of the Forward Purchase Contract Agreement with respect to the Forward
Purchase  Contracts  underlying the number of Stripped  Units  evidenced by this
Stripped  Units  Certificate   specified  below.  The  option  to  effect  Early
Settlement  may be  exercised  only with respect to Forward  Purchase  Contracts
underlying  Stripped Units with an aggregate Stated Amount equal to $1,000 or an
integral multiple thereof.  The undersigned Holder directs that a certificate or
book-entry  interest  for  shares of Common  Stock  deliverable  upon such Early
Settlement be registered in the name of, and delivered, together with a check in
payment for any fractional share and any Stripped Units Certificate representing
any Stripped Units evidenced  hereby as to which Early Settlement of the related
Forward  Purchase  Contracts is not effected,  to the undersigned at the address
indicated  below unless a different name and address have been indicated  below.
Pledged  Treasury  Securities  deliverable  upon such Early  Settlement  will be
transferred in accordance  with the transfer  instructions  set forth below.  If
shares are to be registered in the name of a Person other than the  undersigned,
the undersigned will pay any transfer tax payable incident thereto.

Dated: ____________________       Signature: ___________________________________

                                  Signature Guarantee: _________________________

     Number of Stripped Units evidenced  hereby as to which Early  Settlement of
the related Forward Purchase Contracts is being elected:

If shares of Common Stock are to be           REGISTERED HOLDER
registered in the name of and
delivered to and Pledged Treasury             Please print name and address of
Securities are to be transferred to           Registered Holder:
a Person other than the Holder,
please print such Person's name
and address:

Name                                          Name

Address                                       Address

Social Security or other Taxpayer
Identification Number, if any

     Transfer  instructions for Pledged Treasury  Securities  transferable  upon
Early Settlement or a Termination Event:



<PAGE>
<TABLE>
<CAPTION>


                     (TO BE ATTACHED TO GLOBAL CERTIFICATES)

            SCHEDULE OF INCREASES OR DECREASES IN GLOBAL CERTIFICATE

     The following  increases or decreases in this Global  Certificate have been
made:
<S>    <C>                      <C>                     <C>                       <C>
                                                           Stated Amount of the
        Amount of Decrease in    Amount of Increase in     Global Certificate
        Stated Amount of the     Stated Amount of the        Following Such            Signature of
Date     Global Certificate       Global Certificate      Decrease or Increase     Authorized Signatory



</TABLE>
<PAGE>



                                    EXHIBIT C

                INSTRUCTION FROM FORWARD PURCHASE CONTRACT AGENT
                               TO COLLATERAL AGENT

The Bank of New York
101 Barclay Street
New York, New York 10286
Attention:  Corporate Trust Department

Re: Equity Units of American Electric Power Company, Inc. (the "Company")
- -------------------------------------------------------------------------

     We hereby notify you in  accordance  with Section [4.1] [4.2] of the Pledge
Agreement,  dated  as of June 11,  2002,  (the  "Pledge  Agreement")  among  the
Company, you, as Collateral Agent,  Custodial Agent and Securities  Intermediary
and us, as  Forward  Purchase  Contract  Agent and as  attorney-in-fact  for the
holders of [Equity Units] [Stripped Units] from time to time, that the Holder of
Equity Units and  Stripped  Units  listed  below (the  "Holder")  has elected to
substitute [$_____ aggregate  principal amount of Treasury Securities (CUSIP No.
_____________)]  [$_______  aggregate principal amount of Notes] in exchange for
the  related  [Pledged  Notes]  [Pledged  Treasury  Securities]  held  by you in
accordance  with the Pledge  Agreement and has delivered to us a notice  stating
that the  Holder  has  Transferred  [Treasury  Securities]  [Notes]  to you,  as
Collateral Agent. We hereby instruct you, upon receipt of such [Pledged Treasury
Securities]  [Pledged  Notes],  and  upon  the  payment  by such  Holder  of any
applicable fees, to release the [Notes]  [Treasury  Securities]  related to such
[Equity  Units]   [Stripped  Units]  to  us  in  accordance  with  the  Holder's
instructions.  Capitalized  terms  used  herein but not  defined  shall have the
meaning set forth in the Pledge Agreement.

Date:  _____________________

                                      THE BANK OF NEW YORK,
                                      as Forward Purchase Contract Agent

                                      By: _________________________________
                                           Name:
                                           Title:

     Please print name and address of Registered  Holder  electing to substitute
[Treasury   Securities]  [Notes]  for  the  [Pledged  Notes]  [Pledged  Treasury
Securities]:

Name:

Social Security or other Taxpayer
Identification Number, if any:

Address:



<PAGE>
                                    EXHIBIT D

                 INSTRUCTION TO FORWARD PURCHASE CONTRACT AGENT

The Bank of New York,
as Forward Purchase Contract Agent
101 Barclay Street
New York, New York 10286
Attention: Corporate Trust Department
Telecopy:

Re: Equity Units of American Electric Power Company, Inc. (the "Company")
- -------------------------------------------------------------------------

     The  undersigned  Holder  hereby  notifies you that it has delivered to The
Bank  of  New  York,  as  Collateral  Agent,   Custodial  Agent  and  Securities
Intermediary  [$_______ aggregate principal amount of Treasury Securities (CUSIP
No. ______________)]  [$_______ aggregate principal amount of Notes] in exchange
for the  related  [Pledged  Notes]  [Pledged  Treasury  Securities]  held by the
Collateral  Agent,  in  accordance  with  Section  [4.1]  [4.2]  of  the  Pledge
Agreement, dated June 11, 2002 (the "Pledge Agreement"),  among you, the Company
and the Collateral  Agent. The undersigned  Holder has paid the Collateral Agent
all applicable  fees relating to such exchange.  The  undersigned  Holder hereby
instructs  you to instruct the  Collateral  Agent to release to you on behalf of
the undersigned Holder the [Pledged Notes] [Pledged Treasury Securities] related
to such [Equity Units] [Stripped  Units].  Capitalized terms used herein but not
defined shall have the meaning set forth in the Pledge Agreement.

Date:  ___________________          Signature:_________________________________

                                    Signature Guarantee:_______________________

Please print name and address of Registered Holder:

Name:

Social Security or other Taxpayer Identification Number, if any:

Address:



<PAGE>


                                    EXHIBIT E

                            NOTICE TO SETTLE BY CASH

The Bank of New York,
as Forward Purchase Contract Agent
101 Barclay Street
New York, New York 10286
Attention: Corporate Trust Department
Telecopy: (212) 328-8243

Re: Equity Units of American Electric Power Company, Inc. (the "Company")
- -------------------------------------------------------------------------

     The undersigned Holder hereby  irrevocably  notifies you in accordance with
Section 5.4 of the Forward Purchase Contract Agreement dated as of June 11, 2002
among the Company and  yourselves,  as Forward  Purchase  Contract  Agent and as
Attorney-in-Fact  for the Holders of the Forward Purchase  Contracts,  that such
Holder has elected to pay to the Collateral Agent, on or prior to 11:00 a.m. New
York City time,  on the seventh  Business Day  immediately  preceding  the Stock
Purchase  Date,  (in lawful money of the United States by [certified or cashiers
check  or]  wire  transfer,  in  each  case  in  immediately  available  funds),
$_________ as the Purchase Price for the shares of Common Stock issuable to such
Holder by the Company under the related Forward  Purchase  Contract on the Stock
Purchase Date. The  undersigned  Holder hereby  instructs you to notify promptly
the  Collateral  Agent of the  undersigned  Holder's  election to make such cash
settlement  with  respect  to the  Forward  Purchase  Contracts  related to such
Holder's Equity Units.

Dated:_____________                 __________________________________________
                                    Signature

                                    Signature Guarantee:_______________

Signatures must be guaranteed by an "eligible guarantor institution" meeting the
requirements  of  the  Registrar,   which  requirements  include  membership  or
participation in the Security Transfer Agent Medallion Program ("STAMP") or such
other  "signature  guarantee  program" as may be  determined by the Registrar in
addition  to,  or in  substitution  for,  STAMP,  all  in  accordance  with  the
Securities Exchange Act of 1934, as amended.

Please print name and address of Registered Holder:

Social Security or other Taxpayer Identification Number, if any:





</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>6
<FILENAME>x10b.txt
<DESCRIPTION>(B) OPERATING AGREEMENT
<TEXT>

<PAGE>

                                                                   EXHIBIT 10(b)





                              RESTATED AND AMENDED

                               OPERATING AGREEMENT

                                      Among

                         Central Power and Light Company

                       Public Service Company of Oklahoma

                       Southwestern Electric Power Company

                          West Texas Utilities Company

                      Central and South West Services, Inc.

                                 January 1, 1998


<PAGE>

                               OPERATING AGREEMENT
                                TABLE OF CONTENTS
                                                                           Page
ARTICLE I
                                TERM OF AGREEMENT...........................  2

ARTICLE II
                                   DEFINITIONS..............................  2
         2.1      Agent.....................................................  3
         2.2      Agreement.................................................  3
         2.3      Capacity Commitment.......................................  3
         2.4      Capacity Commitment Charge................................  3
         2.5      Central Control Center....................................  3
         2.6      Chief Executive Officer (CEO).............................  3
         2.7      Company...................................................  3
         2.8      Company Capability........................................  3
         2.9      Company Demand............................................  4
         2.10     Company Hourly Capability.................................  4
         2.11     Company Load Responsibility...............................  4
         2.12     Company Operating Capability..............................  5
         2.13     Company Operating Reserve.................................  5
         2.14     Company Peak Demand.......................................  5
         2.15     Day.......................................................  5
         2.16     Decremental Energy Value..................................  5
         2.17     Economic Dispatch.........................................  5
         2.18     Energy....................................................  5
         2.19     Generating Unit...........................................  5
         2.20     Hour......................................................  6
         2.21     Incremental Energy Cost...................................  6
         2.22     Internal Economy Energy...................................  6
         2.23     Joint Resource Plan.......................................  6
         2.24     Joint Unit................................................  6
         2.25     (a)      Margin on Sales..................................  6
         2.25     (b)      Margin on Purchases..............................  6
         2.25     (c)      Margin on Internal Economy Energy................  6
         2.25     (d)      Margin...........................................  7
         2.26     Month.....................................................  7
         2.27     Operating Committee.......................................  7
         2.28     Own Load..................................................  7
         2.29     Parent Company............................................  7
         2.30     Planning Reserve Level....................................  7
         2.31     Pool Energy...............................................  7
         2.32     Power.....................................................  8
         2.33     Prorated Reserve Level....................................  8
         2.34     Reserve Capacity (Company or System)......................  8
         2.35     System....................................................  8
         2.36     System Capability.........................................  8
         2.37     System Demand.............................................  8
         2.38     System Load Responsibility................................  8
         2.39     System Operating Capability...............................  9
         2.40     System Operating Reserve..................................  9
         2.41     System Peak Demand........................................  9
                                        i
<PAGE>

         2.42     Transaction Cost..........................................  9
         2.43     Variable Cost.............................................  9
         2.44     Year......................................................  9

ARTICLE III
                                    OBJECTIVES..............................  9
         3.1      Purpose...................................................  9

ARTICLE IV
                                      AGENT................................. 10
         4.1      Responsibility of the Agent............................... 10
         4.2      Delegation and Acceptance of Authority.................... 10
         4.3      Reporting................................................. 10

ARTICLE V
                                OPERATING COMMITTEE......................... 11
         5.1      Operating Committee....................................... 11

ARTICLE VI
                                    OPERATIONS.............................. 11
         6.1      Planning and Authorization of Production Facilities....... 11
         6.2      Planning Reserve Levels................................... 12
         6.3      Provision to Achieve Planning Reserve Levels.............. 12
         6.4      Capacity Sales and Purchases and Reserve Shortfalls....... 13
         6.5      Energy Exchanges Among the Companies...................... 13
         6.6      Energy Exchange Pricing................................... 13
         6.7      Energy Exchanges with Non-Associated Utilities............ 14
         6.8      Communications and other Facilities....................... 15

ARTICLE VII
                             CENTRAL CONTROL CENTER......................... 15
         7.1      Central Control Center.................................... 15
         7.2      Expenses.................................................. 15

ARTICLE VIII
                                     GENERAL................................ 16
         8.1      Regulatory Authorization.................................. 16
         8.2      Effect on Other Agreements................................ 16
         8.3      Schedules................................................. 16
         8.4      Billings.................................................. 16
         8.5      Waivers................................................... 17
         8.6      Successors and Assigns; No Third Party Beneficiary........ 17
         8.7      Amendment................................................. 18
         8.8      Independent Contractors................................... 18
         8.9      Responsibility and Liability.............................. 18



                                       ii

<PAGE>


SCHEDULES

A  JOINT UNIT
B  COMPANY UNITS THAT ARE NOT JOINT UNITS
C  CAPACITY COMMITMENT CHARGE
D  PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES AMONG THE COMPANIES
E  PAYMENTS AND RECEIPTS FOR INTERNAL ECONOMY ENERGY EXCHANGES AMONG THE
     COMPANIES AND FOR OFF-SYSTEM ENERGY PURCHASES AND SALES
F  DISTRIBUTION OF MARGIN FOR INTERNAL ECONOMY ENERGY EXCHANGES AND FOR OFF-
     SYSTEM ENERGY PURCHASES AND SALES
G  DISTRIBUTION OF OPERATING EXPENSES OF THE CENTRAL CONTROL CENTER
H  CAPACITY COMMITMENT UNITS
I  PLANNING-RESERVE CRITERIA
J  STATEMENT OF PRACTICE REGARDING OFF-SYSTEM ENERGY SALES
K  DISTRIBUTION OF CERTAIN TRANSACTION COSTS








                                       iii


<PAGE>


                              RESTATED AND AMENDED

                               OPERATING AGREEMENT

                                      Among

                         Central Power and Light Company

                       Public Service Company of Oklahoma

                       Southwestern Electric Power Company

                          West Texas Utilities Company

                      Central and South West Services, Inc.



     THIS  RESTATED  AND  AMENDED  OPERATING   AGREEMENT,   hereinafter   called
Agreement,  is made and entered  into as of the 1st day of January,  1998 by and
among Central Power and Light Company,  hereinafter  called CPL;  Public Service
Company  of  Oklahoma,  hereinafter  called  PSO;  Southwestern  Electric  Power
Company,  hereinafter called SWEPCO;  West Texas Utilities Company,  hereinafter
called WTU; and Central and South West Services,  Inc., hereinafter called CSWS;
all of whose common stock is wholly owned by Central and South West Corporation,
and supersedes  the Restated and Amended  Operating  Agreement  dated October 1,
1993.

     WHEREAS,  CPL,  PSO,  SWEPCO,  and WTU  are the  owners  and  operators  of
interconnected  electric generation,  transmission,  and distribution facilities
with which they are engaged in the  business of  generating,  transmitting,  and
selling  electric  Power and Energy to the general  public and to other electric
utilities; and

     WHEREAS,  the  Companies  achieve  economic  benefits  for their  customers
through  operation  as a single  interconnected  system and through  coordinated
planning,  construction,  operation and  maintenance  of their  electric  supply
facilities; and

     WHEREAS, CSWS is qualified to act as Agent for the Companies;

     NOW, THEREFORE, the parties hereto mutually agree as follows:

                                    ARTICLE I

                                TERM OF AGREEMENT

     1.1 This Agreement shall become effective on such date as is established by
the Federal Energy Regulatory Commission. This Agreement shall continue in force
and effect for a period of ten (10) Years from the  effective  date  hereinabove
described,  and continue from Year to Year thereafter until terminated by one or
more of the parties upon three (3) Years written notice to the other parties.

     1.2 This Agreement is intended to cover only the acquisition,  disposition,
planning,  design,  construction,  operation and  maintenance  of the Generating
Units and is not to affect  those  matters that are the subject of orders of the
United  States  Securities  and  Exchange  Commission  authorizing  certain cost
allocation methods for CSWS billings.

                                   ARTICLE II

                                   DEFINITIONS

     For the purposes of this  Agreement  and of Schedules A through K which are
attached hereto and made a part hereof, the following definitions shall apply:

     2.1 Agent for the Companies shall be CSWS.

     2.2  Agreement  shall  be this  Agreement  including  all  attachments  and
schedules applying hereto and any amendments made hereafter.

     2.3 Capacity Commitment shall be generating capacity committed by a Company
to provide  capability  to enable  another  Company to attain  its  Planning  or
Prorated Reserve Level, whichever shall be lower.

     2.4  Capacity  Commitment  Charge  shall be the  charge  made by a  Company
supplying  a  Capacity   Commitment  to  the  Company   receiving  the  Capacity
Commitment.

     2.5 Central  Control Center shall be a center operated by the Agent for the
optimal utilization of System resources for the supply of Power and Energy.

     2.6 Chief Executive  Officer (CEO) shall be the Chief Executive  Officer of
Central and South West Corporation or the CEO's designee.

     2.7  Company  shall be any one of the  Central  and South West  Corporation
operating   companies  and  Companies  shall  be  the  Central  and  South  West
Corporation operating companies collectively.

     2.8 Company Capability shall be:

          (a)  The sum of the Company net plant capability in megawatts; plus

          (b)  The megawatt amount of purchases and exchanges  without reserves,
               under contract from other systems; less

          (c)  The  megawatt  amount of sales and  exchanges  without  reserves,
               under contract to other systems.

     2.9 Company Demand shall be:

          (a)  The  clock-hour   demand  in  megawatts  of  a  Company's  system
               represented by the  simultaneous  hourly input in  megawatt-hours
               from all sources into the system of a Company; less

          (b)  The sum of the simultaneous  hourly output in  megawatt-hours  to
               other   systems   (exclusive   of  any   wholesale   requirements
               obligations of the Company).

     2.10 Company Hourly Capability for a Company shall be:

          (a)  The megawatt  amount of  dependable  capability  of the Company's
               generating units on line, including its shares of Joint Units and
               its shares of units owned jointly with  non-associated  entities,
               during the Hour; plus

          (b)  The  megawatt  amount of  capability  committed to the Company by
               other Companies or non-associated suppliers during the Hour; less

          (c)  The  megawatt  amount of  capability  committed by the Company to
               other  Companies or  non-associated  purchasers  during the Hour;
               less

          (d)  Any capability required to provide operating reserves.

     2.11 Company Load Responsibility shall be as follows:

          (a)  Company Peak Demand; less

          (b)  the difference  between Company Peak Demand and Company Demand at
               the time of System Peak Demand; less

          (c)  The   megawatt-hour   output   of  the   Company   served  on  an
               interruptible basis during the hour of Company Peak Demand; plus

          (d)  The  contractual  amount of sales  and  exchanges  with  reserves
               during the period to other systems; less

          (e)  The  contractual  amount of purchases and exchanges with reserves
               during the period from other systems.

     2.12 Company Operating Capability shall be the dependable net capability in
megawatts of Generating Units of a Company carrying load or ready to take load.

     2.13 Company  Operating  Reserve  shall be the excess of Company  Operating
Capability over Company Demand expressed in megawatts.

     2.14 Company Peak Demand for a period shall be the highest  Company  Demand
for any Hour during the period.

     2.15 Day shall be a calendar day.

     2.16  Decremental  Energy  Value  shall be the cost  that a buying  Company
avoids  by  reducing  the  generation  of  Energy  from  its  Company  Operating
Capability or by reducing its purchase of Energy from others.

     2.17  Economic  Dispatch  shall be the  distribution  of  total  generation
requirements among alternative sources for System economy with due consideration
of incremental  generating costs,  incremental  transmission  losses, and System
security.

     2.18 Energy shall be work and shall be expressed in megawatt-hours (MWH).

     2.19  Generating  Unit shall be an electric  generator,  together  with its
prime mover and all auxiliary and appurtenant  devices and equipment designed to
be operated as a unit for the production of electric Power and Energy. The above
is to include equipment necessary for connection to the transmission system.

     2.20 Hour shall be a clock-hour.

     2.21  Incremental  Energy Cost shall be the  variable  cost which a selling
Company incurs in order to supply Energy for resale.

     2.22  Internal  Economy  Energy  shall be Energy  supplied  and sold by one
Company to another Company,  under Economic  Dispatch,  to meet a portion of the
purchasing Company's Own Load that could otherwise be supplied internally by the
purchasing Company.

     2.23 Joint Resource Plan shall be the formal documented plan developed from
time to time for all future  Generating  Units and other power supply and demand
management resources.

     2.24 Joint Unit shall be any  Generating  Unit jointly owned by two or more
of the Companies.

     2.25 (a) Margin on Sales shall be the difference  between:  (1) the revenue
from  off-System  Energy sales made  pursuant to Section 6.7 and (2) the selling
Companies' Incremental Energy Cost incurred in making such sales.

     2.25 (b) Margin on Purchases shall be the difference between (1) the buying
Companies'  Decremental  Energy Value avoided as a result of  off-System  Energy
purchases  made pursuant to Section 6.7 and (2) payments for  off-System  Energy
purchases made pursuant to Section 6.7.

     2.25 (c) Margin on Internal Economy Energy shall be the difference  between
(1) the buying  Companies'  Decremental  Energy  Value  avoided as the result of
receiving  Internal  Economy  Energy  and (2) the  selling  Companies'  Internal
Economy Energy Cost incurred in supplying Internal Economy Energy.

     2.25  (d)  Margin  for a  given  period  shall  be the  sum of the  amounts
developed in accordance with Sections 2.25 (a), 2.25 (b) and 2.25 (c).

     2.26 Month shall be a calendar Month.

     2.27 Operating Committee shall be the organization  established pursuant to
Section 5.1 and whose duties are more fully set forth therein.

     2.28 Own Load shall be Energy  required to meet Company  Demand plus Energy
associated  with sales or exchanges  with reserves less Energy  associated  with
purchases or exchanges with reserves.

     2.29 Parent Company shall be Central and South West Corporation.

     2.30  Planning  Reserve  Level  shall be the  megawatt  amount of  required
Reserve  Capacity for a Company,  expressed as a  percentage  of its  forecasted
Company Load Responsibility.

     2.31 Pool Energy  shall be the Energy  supplied  and sold by one Company to
another  Company to enable the  purchasing  Company to meet a portion of its Own
Load that such  other  Company  cannot or does not plan to serve  with its other
resources.  There shall be two categories of Pool Energy.  Emergency Pool Energy
shall be the Energy required by a Company that becomes  deficient  because of an
unplanned  occurrence (such as a generator unit trip or a missed load forecast).
Planned Pool Energy shall be the Energy  required by a Company to meet  portions
of its Own Load when it  determines  that (a) it will be short of capacity  when
planning  for future  operations  or (b) such  Energy  can be taken to  economic
advantage.

     2.32  Power  shall be the rate of doing  work  and  shall be  expressed  in
megawatts (MW).

     2.33 Prorated  Reserve  Level shall be a percentage  reserve level for each
Company that when divided by that  Company's  Planning  Reserve  Level gives the
same quotient as that for all other Companies.

     2.34 Reserve Capacity (Company or System) shall be that amount in megawatts
by  which  Company  or  System   Capability   exceeds  Company  or  System  Load
Responsibility.

     2.35 System shall be the coordinated Generating Units of the Companies.

     2.36 System  Capability  shall be the  arithmetical sum in megawatts of the
individual Company Capabilities.

     2.37  System  Demand  shall  be the  arithmetical  sum  of  the  Companies'
clock-hour demand in megawatts represented by:

          (a)  The simultaneous  hourly input in megawatt-hours from all sources
               into the System; less

          (b)  The sum of the simultaneous  hourly outputs in  megawatt-hours to
               other   systems   (exclusive   of  any   wholesale   requirements
               obligations of the Companies).

     2.38 System Load Responsibility shall be as follows:

          (a)  System Peak Demand; less

          (b)  The   megawatt-hour   output  of  the  Companies   served  on  an
               interruptible basis during the Hour of System Peak Demand; plus

          (c)  The  arithmetic  sum  in  megawatts  of  all  of  the  Companies'
               contractual  amount of sales and exchanges  with reserves  during
               the period to other systems; less

          (d)  The arithmetic sum in megawatts of all the Companies' contractual
               amount of purchases and exchanges with reserves during the period
               from other systems.

     2.39 System Operating Capability shall be the arithmetical sum in megawatts
of the individual Company Operating Capabilities.

     2.40  System  Operating  Reserve  shall  be  the  arithmetical  sum  of the
individual Company Operating Reserves, expressed in megawatts.

     2.41 System Peak Demand for a period shall be the highest System Demand for
any hour during the period.

     2.42  Transaction Cost shall be the sum of the charges assessed against any
one or more of the  Companies  for  transmission  services  related to  Internal
Economy Energy exchanges and off-System  Energy purchases and sales,  other than
such charges  allocated  among the  Companies  pursuant to the  Distribution  of
Certain Transaction Costs procedure set forth in Schedule K.

     2.43  Variable  Cost shall be a Company's  incremental  generation  cost or
purchased energy cost.

     2.44 Year shall be a calendar Year.

                                   ARTICLE III

                                   OBJECTIVES

     3.1 Purpose

     The purpose of this Agreement is to provide the  contractual  basis for the
coordinated planning,  construction,  operation and maintenance of the System to
achieve optimal economies, consistent with reliable electric service, reasonable
utilization of natural resources, and environmental requirements.

                                   ARTICLE IV

                                      AGENT

     4.1 Responsibility of the Agent

     The Companies hereby designate CSWS as their Agent for the purpose of:

          (a)  coordinating  the  acquisition,  disposition,  planning,  design,
               construction,  operation and maintenance of the Generating  Units
               of the Companies, including any Joint Units; and

          (b)  supervising the design,  construction,  operation and maintenance
               of the Central Control Center.

     4.2 Delegation and Acceptance of Authority

     The  Companies  hereby  delegate to the Agent and the Agent hereby  accepts
responsibility  and authority for the duties listed in Section 4.1 and elsewhere
in this Agreement.  Except as herein expressly established otherwise,  the Agent
shall perform each of those duties in consultation with the Operating Committee.
The  Agent  shall  also  perform  each of those  duties in  accordance  with the
standards of conduct described in 18 C.F.R. Section 37.4.

     4.3 Reporting

     The Agent shall provide  periodic  summary reports of its activities  under
this  Agreement to the  Companies and shall keep the Companies and the Operating
Committee  currently  informed of  situations  or problems  that may  materially
affect the outcome of these activities.  Furthermore, the Agent agrees to report
to the Companies or to the Operating  Committee in such additional  detail as is
requested regarding specific issues or projects under its supervision as Agent.

                                    ARTICLE V

                               OPERATING COMMITTEE

     5.1 Operating Committee

     The  Operating  Committee  is the  organization  established  to ensure the
coordinated  operation  of the  System  by  making  recommendations  to the  CEO
regarding operations under this Agreement.  The Operating Committee members will
be designated by the CEO and shall include a chairperson and at least one member
from the Agent and from each Company.  Operating Committee decisions shall be by
a majority vote of those present and shall be in the form of  recommendations to
the CEO. However, any member not present may vote by proxy. In any non-unanimous
decision  the  principles  of the  difference  shall be reported to the CEO. The
chairperson shall vote only in case of a tie.

                                   ARTICLE VI

                                   OPERATIONS

     6.1 Planning and Authorization of Production Facilities

          (a)  Each Company shall  forecast the amount of generating  capability
               required to meet its Company Load Responsibility and its Planning
               Reserve Level in future Years.

          (b)  A current Joint Resource Plan will be maintained  that will state
               the current forecasted System Load  Responsibility  including the
               Planning Reserve Level and the required resources.

          (c)  All  Generating  Units  placed in service  after the date of this
               Agreement  shall be in  accordance  with the then  current  Joint
               Resource  Plan.  Joint Units shall be  authorized by the Board of
               Directors  of the Parent  Company  prior to the  commencement  of
               detailed engineering of the units.

          (d)  For the purpose of this Agreement, the Generating Units listed in
               Schedule B are not Joint Units.

          (e)  The  organization  designated by the CEO shall be responsible for
               the staffing, operation and maintenance of each Generating Unit.

     6.2 Planning Reserve Levels

     The Operating  Committee  shall  periodically  review the Planning  Reserve
Level for each Company and recommend any modifications of such to the CEO.

     6.3 Provision to Achieve Planning Reserve Levels

          (a)  Each Company  shall own or have  available  to it under  contract
               such generating  capability and other facilities as are necessary
               to supply  its  Company  Load  Responsibility  plus its  Planning
               Reserve Level.

          (b)  The  Joint  Resource  Plan  shall be  periodically  reviewed  and
               adjusted to provide the Companies their required Planning Reserve
               Levels.  Any  Company  with  Reserve  Capacity  in  excess of its
               Planning Reserve Level for a future Year shall commit such excess
               capacity to Companies with insufficient  Reserve Capacity to meet
               their  Planning  Reserve  Level  during  that Year or any portion
               thereof.  The deficit Companies shall make payments to the excess
               Companies  in  respect  of each  Month of the  Year to which  the
               commitment  applies  in the  amount  of the  Capacity  Commitment
               Charge in  accordance  with  Schedule  C. In the  event  that the
               System  Capability,  including  outside  capacity  purchases,  is
               insufficient  to meet such Planning  Reserve  Levels,  the System
               Capability  shall  be  allocated  to  provide  each  Company  its
               Prorated Reserve Level.

          (c)  The ownership  percentages in future Joint Units are  established
               in  accordance  with  Schedule A, but may be  reallocated  in the
               Joint Resource Plan by recommendation of the Operating  Committee
               and authorization by the CEO.

     6.4 Capacity Sales and Purchases and Reserve Shortfalls

          (a)  The Agent shall  coordinate  and assist the  Companies  in making
               off-System capacity sales and purchases.

          (b)  The  System  Reserve  Capacity  shall be at the  disposal  of any
               Company  requiring such  capacity.  Should the System be short of
               capacity  as a result of an  emergency  and be unable to purchase
               the  deficit,  each  Company  shall  take  such  actions  as  are
               necessary to bring System load and generation into balance.

     6.5 Energy Exchanges Among the Companies

     The Agent shall  schedule the Energy output of System  Capability to obtain
the  lowest  cost of Energy  for  serving  System  Demand  consistent  with each
Company's  operating  and  security  constraints,   including  voltage  control,
stability  loading  of  facilities,  operating  guides  as  recommended  by  the
Operating  Committee  and approved by the CEO, fuel  commitments,  environmental
requirements, and continuity of service to customers.

     6.6 Energy Exchange Pricing

     For the purpose of pricing  Energy  exchange  among the  Companies,  System
resources shall be utilized to serve System requirements in the following order:

          a)   Those Generating Units which are designated not to be operated in
               the order of  lowest  to  highest  Variable  Cost due to  Company
               operating constraints shall be allocated to the Company requiring
               the Generating Unit.

          (b)  The lowest  Variable  Cost  generation of each  Company's  Hourly
               Capability shall first be allocated to serve its Own Load.

          c)   The next lowest Variable Cost portion of each Company's remaining
               Hourly  Capability  shall  be  allocated  to  serve  Pool  Energy
               requirements of Companies under System  Economic  Dispatch.  Pool
               Energy shall be priced in accordance with Schedule D.

          (d)  The next lowest Variable Cost portion of each Company's remaining
               Hourly Capability shall be used to supply Internal Economy Energy
               to Companies under System  Economic  Dispatch.  Internal  Economy
               Energy shall be priced in accordance with Schedule E.

     6.7 Energy Exchanges with Non-Associated Entities

     The Agent  shall  coordinate  and  direct  off-System  purchases  of Energy
necessary to meet System requirements or improve System economy,  after Internal
Economy Energy  transactions have been effected.  The Agent shall coordinate and
direct   off-System   sales  of  Energy  available  after  meeting  all  of  the
requirements  of the System  including the Energy  associated  with  contractual
requirements for off-System  capacity sales. Such off-System Energy purchases or
sales  shall be  implemented  by  decremental  or  incremental  System  Economic
Dispatch as appropriate. Any Margin on off-System Energy sales or purchases made
to improve  System  economy shall be  distributed to the Companies in accordance
with Schedule F. Price  quotations  for such Energy sales shall be determined in
accordance with Schedule J.

     6.8 Communications and other Facilities

     The Companies shall provide  communications and other facilities  necessary
for:

          (a)  The  metering  and  control of the  generating  and  transmission
               facilities;

          (b)  The dispatch of electric Power and Energy; and

          (c)  For such other purposes as may be necessary for optimum operation
               of the System.

                                   ARTICLE VII

                             CENTRAL CONTROL CENTER

     7.1 Central Control Center

     The Agent shall  provide and operate a Central  Control  Center  adequately
equipped and staffed to meet the  requirements  of the Companies for  efficient,
economical and reliable operation as contemplated by this Agreement.

     7.2 Expenses

     All expenses for operation of the Central  Control  Center shall be paid by
the Agent and billed monthly to each Company in accordance with Schedule G.



                                  ARTICLE VIII

                                     GENERAL

     8.1 Regulatory Authorization

     This Agreement is subject to certain regulatory  approvals and each Company
and the Agent shall diligently seek all necessary  regulatory  authorization for
this Agreement.

     8.2 Effect on Other Agreements

     This  Agreement  shall not modify the  obligations of any Company under any
agreement  between  that  Company  and others not parties to this  Agreement  in
effect at the date of this Agreement,  nor shall it modify any agreement between
or among the Companies  under any  transmission  tariff or other agreement filed
with the Federal Energy Regulatory Commission.

     8.3 Schedules

     The basis of  compensation  for the use of facilities and for the Power and
Energy  provided or supplied by a Company to another  Company or Companies under
this Agreement shall be in accordance with arrangements agreed upon from time to
time among the Companies.  Such arrangements  shall be in the form of Schedules,
each of which,  when signed by the parties  thereto and  approved or accepted by
appropriate regulatory authority, shall become a part of this Agreement.

     8.4 Billings

     Bills for services  rendered  hereunder  shall be  calculated in accordance
with  applicable  Schedules,  and shall be issued on or before the tenth working
Day of the Month  following that in which such service was rendered and shall be
payable on or before the twentieth Day of such Month.  After the thirtieth  Day,
interest  shall accrue on any balance due until paid at the latest rate approved
by the  United  States  Securities  and  Exchange  Commission  for  loans  among
Companies in the Central and South West System.  Billings in good faith disputed
and paid shall be deemed to have been paid under protest.


     8.5 Waivers

     Any waiver at any time by a Company of its rights with respect to a default
by any other  Company  under this  Agreement  shall not be deemed a waiver  with
respect to any subsequent  default of similar or different nature,  nor shall it
prejudice its right to deny waiver of similar default to a different Company.

     8.6 Successors and Assigns; No Third Party Beneficiary

     This  Agreement  shall  inure to and be  binding  upon the  successors  and
assigns of the  respective  parties  hereto,  but shall not be assignable by any
party without the written consent of the other parties,  except upon foreclosure
of a mortgage  or deed of trust.  Nothing  expressed  or  mentioned  or to which
reference  is made in this  Agreement  is intended or shall be construed to give
any person or  corporation  other than the parties hereto any legal or equitable
right,  remedy or claim under or in respect of this  Agreement or any  provision
herein  contained,  expressly  or by  reference,  or any Schedule  hereto,  this
Agreement,  any such Schedule and any and all conditions  and provisions  hereof
and thereof being intended to be and being for the sole and exclusive benefit of
the parties hereto, and for the benefit of no other person or corporation.

     8.7 Amendment

     It is contemplated  by the parties that it may be appropriate  from time to
time to change,  amend,  modify or  supplement  this  Agreement or the Schedules
which are attached to this Agreement to reflect  changes in operating  practices
or costs of  operations  or for other  reasons.  This  Agreement may be changed,
amended, modified or supplemented by an instrument in writing executed by all of
the parties.

     8.8 Independent Contractors

     It is agreed among the Companies  that by entering into this  Agreement the
Companies shall not become partners,  but as to each other and to third persons,
the Companies shall remain  independent  contractors in all matters  relating to
this Agreement.

     8.9 Responsibility and Liability

     The  liability of the parties  shall be several,  not joint or  collective.
Each party shall be responsible  only for its  obligations,  and shall be liable
only for its  proportionate  share of the costs and expenses as provided in this
Agreement,  and any liability resulting herefrom. Each party hereto will defend,
indemnify,  and save harmless the other parties  hereto from and against any and
all  liability,  loss,  costs,  damages,  and  expenses,   including  reasonable
attorney's  fees,  caused by or  growing  out of the gross  negligence,  willful
misconduct, or breach of this Agreement by such indemnifying party.



     IN WITNESS WHEREOF, each of the Companies has caused this Agreement and the
attached  Schedules to be signed in its name and on its behalf by its  President
attested by its Secretary, both being duly authorized,  and CSWS has caused this
Agreement and the attached  Schedules to be signed in its name and on its behalf
by its Chief  Executive  Officer  attested  by its  Secretary,  both  being duly
authorized. This Agreement and attached Schedules shall become effective on such
date as is established by the Federal Energy Regulatory Commission.


                                       CENTRAL POWER AND LIGHT COMPANY
Attest


                                       By   /s/
Secretary                                       President



                                       PUBLIC SERVICE COMPANY OF OKLAHOMA
Attest


                                       By  /s/
Secretary                                       President



                                       SOUTHWESTERN ELECTRIC POWER COMPANY
Attest


                                       By   /s/
Secretary                                       President



                                       WEST TEXAS UTILITIES COMPANY
Attest


                                       By   /s/
Secretary                                       President



                                       CENTRAL AND SOUTH WEST SERVICES, INC.
Attest


                                       By   /s/
Secretary                                       Chief Executive Officer




<PAGE>
                                   SCHEDULE A

                                   JOINT UNIT

     9.1 Purpose

     The purpose of this  Schedule  is to provide  the basis for the  Companies'
participation in Joint Units.

     9.2 Ownership

     (a) Every Joint Unit shall be owned by the Companies  participating  in the
Joint Unit as tenants  in common.  Ownership  shares in each Joint Unit shall be
allocated  insofar as  practical  to achieve a  Prorated  Reserve  Level for all
Companies  participating in the unit. The allocation shall be recommended by the
Operating  Committee  and  authorized  by the CEO  prior to the time the unit is
authorized  by the Board of  Directors  of the  Parent  Company.  However,  each
Company  shall own at least  fifty (50)  megawatts  of each  Joint  Unit  unless
otherwise  agreed  to  by  the  Operating  Committee.   Each  Company  shall  be
responsible  for its pro rata share of the costs of construction of the unit and
shall contribute such funds to the Agent as billed.

     (b) When a new Joint Unit is installed at a site already occupied by one or
more existing  Generating  Units the Agent, in  consultation  with the Operating
Committee, shall identify any existing facilities that will be common to the new
Joint Unit and the portion of the common  facilities  to be allocated to the new
Joint Unit. The owners of the new Joint Unit shall  compensate the owners of the
existing common facilities for the use of those common facilities.

     9.3 Contracts

     The  Companies  shall  execute a joint  ownership  agreement for each Joint
Unit, such agreement to set out all of the rights and obligations of the parties
relating to the specific Joint Unit, including the allocation of fuel costs, the
allocation of other  operation  costs and the  allocation of  maintenance  costs
among the owners.


<PAGE>
                                   SCHEDULE B

                     COMPANY UNITS THAT ARE NOT JOINT UNITS

     10.1 Purpose

     The purpose of this Schedule is to list the Generating  Units, to be placed
in service after the date of the original  Operating  Agreement  dated September
28, 1983, which are not Joint Units.

     10.2 Company Units That Are Not Joint Units

     The Company units that are not Joint Units are as follows:

                  South Texas Project Unit Number 1 - CPL

                  South Texas Project Unit Number 2 - CPL

                  Dolet Hills Unit Number 1 - SWEPCO

                  Pirkey Unit Number 1 - SWEPCO




<PAGE>

                                   SCHEDULE C

                           CAPACITY COMMITMENT CHARGE

     11.1 Purpose

     The  purpose  of this  Schedule  is to  establish  the basis  for  Capacity
Commitments  between the  Companies  and the rates for the  Capacity  Commitment
Charge and associated Energy.

     11.2 Basis for Capacity Commitment

     A  committing  Company  shall make  available  to a receiving  Company unit
capacity  consisting  of a  portion  of  the  output  of one  or  more  specific
Generating Units. The receiving Company shall be entitled to receive Energy from
the specified  Generating Unit(s) up to an amount equal to an annual load factor
of sixty (60) percent or such other amount as is mutually agreeable.

     11.3 Provisions for Capacity Commitment Charge

     The monthly Capacity Commitment Charge for each specific Generating Unit(s)
from which capacity is committed  shall be an amount not to exceed the result of
the following formula:

     A = (1/12) (B) (C/D) (E)

     Where:

          A = Monthly  Capacity  Commitment  Charge for the specified unit to be
          due each month regardless of the availability of the specific unit.

          B = 0.1712 (fixed charge rate for the committing Company).

          C = Committing Company's total dollar investment, at original cost, in
          the  specific  Generating  Unit as of December 31 of the year prior to
          the year of the Capacity Commitment.

          D = Rated net dependable capability of the specific Generating Unit in
          megawatts.

          E = Megawatts of capacity committed from the specified unit.

     11.4 Provision for Energy Charge

     The rate for Energy received by a receiving  Company from specified unit(s)
shall be the Variable Cost of Energy  produced from each specified  unit(s) plus
ten (10) percent of such costs or three (3) mills per  kilowatt-hour,  whichever
is less.


<PAGE>

                                   SCHEDULE D

                 PAYMENTS AND RECEIPTS FOR POOL ENERGY EXCHANGES

                               AMONG THE COMPANIES

     12.1 Purpose

     The  purpose  of this  Schedule  is to  provide  the basis for  determining
payments and receipts among the Companies for Pool Energy exchanges.

     12.2 Hourly Calculations

     The payments and receipts of Section 12.3 are  calculated  Hourly,  but are
accumulated and billed Monthly among the Companies

     12.3 Receipts and Payments

     A selling  Company shall receive from a purchasing  Company one hundred and
ten percent  (110%) of the selling  Company's  Incremental  Energy Cost for Pool
Energy sold. A purchasing Company shall pay for Pool Energy received one hundred
and ten percent (110%) of its portion of the aggregate of the selling Companies'
Incremental Cost for Pool Energy. Where Pool Energy is purchased  simultaneously
by more than one Company,  these charges shall be pro rated in proportion to the
megawatt-hours of Pool Energy purchased by each buyer.





<PAGE>

                                   SCHEDULE E

                       PAYMENTS AND RECEIPTS FOR INTERNAL

                ECONOMY ENERGY EXCHANGES AMONG THE COMPANIES AND

                    FOR OFF-SYSTEM ENERGY PURCHASES AND SALES

     13.1 Purpose

     The  purpose  of this  Schedule  is to  provide  the basis for  determining
payments and receipts among the Companies for Internal  Economy Energy exchanges
and for off-System Energy purchases and sales made to improve System economy.

     13.2 Hourly Calculations

     The  payments  of  Section  13.3 and  receipts  of  Section  13.4  shall be
calculated Hourly, but are accumulated and billed Monthly among the Companies.

     13.3 Payments

     A purchasing  Company shall pay its  Decremental  Energy Value for Internal
Economy  Energy  purchased and  off-System  Energy  purchased to improve  System
economy.

     13.4 Receipts

     A selling  Company shall receive its  Incremental  Energy Cost for Internal
Economy Energy sold and off-System Energy sold to improve System economy.




<PAGE>

                                   SCHEDULE F

                       DISTRIBUTION OF MARGIN FOR INTERNAL

                   ECONOMY ENERGY EXCHANGES AND FOR OFF-SYSTEM

                           ENERGY PURCHASES AND SALES

     14.1 Purpose

     The purpose of this  Schedule is to  establish  the basis for  distributing
among the Companies the Margin  resulting from Internal Economy Energy exchanges
and for off-System Energy purchases and sales made to improve System economy.

     14.2 Distribution of Margin

     Any Margin  remaining from Internal Economy Energy exchanges and off-System
Energy  purchases and sales made to improve System  economy after  deducting any
Transaction  Cost  incurred in the period to which the Margin  relates  shall be
distributed to the Companies in proportion to the relative magnitude of the sums
for each  Company of the Energy  generated  or not  generated by such Company in
order to participate in Internal  Economy  Energy  exchanges or such  off-System
purchases or sales.


<PAGE>

                                   SCHEDULE G

                       DISTRIBUTION OF OPERATING EXPENSES

                          OF THE CENTRAL CONTROL CENTER

     15.1 Purpose

     The  purpose of this  Schedule  is to provide a basis for the  distribution
among the Companies of the costs  incurred by the Agent in operating the Central
Control Center.

     15.2 Costs

     Costs for the purpose of this Schedule  shall include all costs incurred in
maintaining  and operating the Central Control Center  including,  among others,
such items as salaries,  wages,  rentals,  the cost of materials  and  supplies,
interest, taxes, depreciation,  transportation, travel expenses, consulting, and
other professional services.

     15.3 Distribution of Costs

     All costs shall be billed by Agent to the  Companies in  proportion  to the
average  of the  maximum  Company  Peak  Demands  experienced  during  the three
previous calendar Years with the following  exception.  In the event the Central
Control  Center  makes a study or  performs  a  special  service  in  which  all
Companies are not thus proportionately  interested,  any resulting cost shall be
distributed to the interested parties in accordance with the standard procedures
of Agent authorized by the United States Securities and Exchange Commission.





<PAGE>

                                   SCHEDULE H

                            CAPACITY COMMITMENT UNITS

     16.1 Purpose

     The purpose of this  Schedule is to identify  the  Generating  Units of the
Companies from which Capacity  Commitments shall be made pursuant to Section 6.3
in accordance with Schedule C.

     16.2 Commitment Units

     Listed  below are the  Generating  Units from  which each of the  Companies
shall  commit  Capacity to other  Companies  pursuant to Section  6.3.  Capacity
Commitments  shall be made from the first listed unit of the committing  Company
unless or to the extent that such unit is not  expected to be  available  during
the commitment  period. In such event,  Capacity  Commitments shall be made from
the second listed unit of the committing Company.

COMPANY       UNIT NAME            RATING(MW)       YEAR INSTALLED

CPL           B. M. Davis #2          341               1976
              Laredo #3               101               1975

PSO           Riverside #2            465               1976
              Riverside #1            457               1974

SWEPCO        Knox Lee #5             344               1974
              Wilkes #3               351               1971

WTU           Fort Phantom #2         204               1977
              Fort Phantom #1         158               1974





<PAGE>

                                   SCHEDULE I

                            PLANNING-RESERVE CRITERIA

     17.1 Purpose

     The purpose of this  Schedule is to identify  the  criteria  which shall be
used by the Companies in determining  their  respective  Planning Reserve Levels
for purposes of determining their respective Capacity Commitment obligations

     17.2 Planning Reserve Criteria

     The Planning  Reserve Level for each of the Companies shall be equal to 15%
of Company Load Responsibility.



<PAGE>

                                   SCHEDULE J

                              STATEMENT OF PRACTICE

                              REGARDING OFF-SYSTEM

                                  ENERGY SALES

     18.1 Purpose

     The  purpose of this  Schedule  is to  identify  the basis upon which price
quotations  for energy sales to a  non-associated  entity made to improve System
economy will be determined when any such  non-associated  entity makes a request
of a Company or the Agent to purchase  System Energy.  The prices for sales made
shall be set by  negotiation  or in accordance  with filed rate schedules of the
Companies and may include standard industry adders.

     18.2 Determination of Energy Price Quotations

     The CSW Central Control Center will predispatch System Energy  requirements
based upon an  estimate of on-line  System  generation  and such  System  Energy
requirements.  Any  request for the  purchase of System  Energy will result in a
price   quotation   based   upon   the   incremental   running   cost   of   the
next-least-costly-to-operate  System  Generating Unit (that will be available to
make the sale  requested  during  the time  period  that is the  subject  of the
request by the  non-associated  entity)  after  System  needs have been met.  In
determining  whether a  Generating  Unit will be  available  to make a requested
sale,  the  matters  listed in  Section  6.5 and the  availability  of  adequate
transmission  capacity on the System and on the systems of other utilities shall
be considered.




<PAGE>

                                   SCHEDULE K

                    DISTRIBUTION OF CERTAIN TRANSACTION COSTS

     19.1 Purpose

     The  purpose of this  Schedule  is to provide a basis for the  distribution
among the  Companies  of certain  charges  assessed by  non-associated  entities
against  one or  more of the  Companies  for  transmission  service  related  to
transactions contemplated by the Agreement.

     19.2 Fixed Transaction Costs

     For purposes of this  Schedule,  Fixed  Transaction  Costs shall consist of
transmission  service charges that are not computed based on specific  schedules
that vary on an  hour-by-hour  basis or that are not computed for specific  firm
transmission  service  reservations  between Companies dependent on the level of
reservation.

     19.3 Distribution of Fixed Transaction Costs

     All Fixed  Transaction Costs shall be billed to the Companies in proportion
to their maximum Company Peak Demands  experienced  during the previous calendar
Year less interruptible loads served during the peak hour.

     19.4 Directly Assigned Transaction Costs

     For purposes of this Schedule,  Directly  Assigned  Transaction Costs shall
consist of transmission service charges due to non-associated  entities that are
not  Fixed  Transaction  Costs and that are  associated  with the  receipt  by a
Company of Pool Energy,  Energy  produced from a Joint Unit,  Energy  associated
with a Capacity Commitment and off-System Energy purchased with reserves to meet
the requirements of the receiving Company.

     19.5 Distribution of Directly Assigned Transaction Costs

     All Directly Assigned Transaction Costs shall be billed to the Companies in
accordance with the following implementation steps:

          1)   Directly   Assigned   Transaction  Costs  due  to  non-associated
               entities shall be paid by the Company  receiving the bill.  Where
               two or more Companies are jointly receiving such Energy for which
               a  consolidated   transmission  service  bill  is  rendered,  the
               involved  Companies  will  be  responsible  for  the  charges  in
               proportion to their megawatt-hour (MWH) share of such Energy.

          2)   Should  a  non-associated  entity  render  a  bill  for  Directly
               Assigned  Transaction  Costs that does not  separately  attribute
               such  costs to  particular  Pool  Energy,  Joint  Unit,  Capacity
               Commitment  or   off-System   Energy   purchased   with  reserves
               transactions,  the terms and conditions of the contracts, tariffs
               or ERCOT practices on which the charges are based will be used to
               determine  which  Companies will be  responsible  for such Energy
               transaction charges.

          3)   When losses are required to be paid in kind, and the  responsible
               Company provides Energy (to the scheduling Company) sufficient to
               cover  the  losses to be  returned,  such  payments  shall not be
               considered  as  Directly  Assigned  Transaction  Costs.  When the
               responsible  Company  chooses to pay the cost associated with the
               scheduling  Company's  returning  the  losses  on  behalf  of the
               System,  such  Directly  Assigned   Transaction  Costs  shall  be
               determined  as the  product of the losses  paid back (in MWH) and
               the scheduling  Company's average monthly fuel cost for the Month
               in which the losses are returned.

          4)   On a calendar  Month basis,  according to  transaction  date, the
               total Directly Assigned Transmission Costs for which each Company
               is responsible and the total Directly Assigned Transmission Costs
               paid by each Company  shall be tabulated.  For a given Month,  an
               adjustment shall be made in an appropriate CSW Money Pool account
               for each Company by an amount equal to the difference between the
               total Directly Assigned Transaction Costs paid by the Company and
               the Directly Assigned  Transaction Costs for which the Company is
               responsible.

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>7
<FILENAME>x10d.txt
<DESCRIPTION>(D) TRANSMISSION COORD AGREEMENT
<TEXT>
<PAGE>

                                                                  EXHIBIT 10(d)

                      TRANSMISSION COORDINATION AGREEMENT


                                     Between

                        Central Power and Light Company,
                          West Texas Utilities Company,
                       Public Service Company of Oklahoma,
                       Southwestern Electric Power Company

                                       and

                      Central and South West Services, Inc.



                           Dated as of January 1, 1997
                         Revised as of October 29, 1999



<PAGE>


                                TABLE OF CONTENTS
                                                                          Page

ARTICLE I

         TERM OF AGREEMENT...................................................2

         1.1      Effective Date.............................................2
                  --------------
         1.2      Periodic Review............................................2
                  ---------------

ARTICLE II

         DEFINITIONS.........................................................3

         2.1      Agreement..................................................3
                  ---------
         2.2      Ancillary Services.........................................3
                  ------------------
         2.3      Company Demand.............................................3
                  --------------
         2.4      Company Peak Demand........................................3
                  -------------------
         2.5      Control Area...............................................3
                  ------------
         2.6      Coordinating Committee.....................................3
                  ----------------------
         2.7      Designated Agent...........................................4
                  ----------------
         2.8      Direct Assignment Facilities...............................4
                  ----------------------------
         2.9      Generating Unit............................................4
                  ---------------
         2.10     Hour.......................................................4
                  ----
         2.11     Month......................................................4
                  -----
         2.12     Network Integration Transmission Service...................4
                  ----------------------------------------
         2.13     Open Access Transmission Tariff............................4
                  -------------------------------
         2.14     Point-to-Point Transmission Service........................4
                  -----------------------------------
         2.15     PUCT.......................................................5
                  ----
         2.16     Scheduling, System Control and Dispatch Service............5
                  -----------------------------------------------
         2.17     Transmission Customer......................................5
                  ---------------------
         2.18     Transmission Provider......................................5
                  ---------------------
         2.19     Transmission Service.......................................5
                  --------------------
         2.20     Transmission System........................................5
                  -------------------
         2.21     Transmission System Operator...............................5
                  ----------------------------

ARTICLE III

         OBJECTIVES..........................................................6

         3.1      Purposes...................................................6
                  --------


ARTICLE IV

         COORDINATING COMMITTEE..............................................7

         4.1      Coordinating Committee.....................................7
         4.2      Responsibilities of the Coordinating Committee.............7
         4.3      Delegation and Acceptance of Authority.....................8
         4.4      Reporting..................................................8
<PAGE>

ARTICLE V

         PLANNING............................................................9

         5.1      Transmission Planning......................................9
                  ---------------------

ARTICLE VI

         TRANSMISSION.......................................................10

         6.1      Delegation to the Transmission System Operator............10
                  ----------------------------------------------
         6.2      Transmission Facilities...................................10
                  -----------------------
         6.3      Direct Assignment Facilities..............................10
                  ----------------------------
         6.4      Transmission Service Revenues.............................10
                  -----------------------------
         6.5      Payment of Costs for Network Use..........................12
                  --------------------------------
         6.6      Payment of Costs for Point-to-Point Transmission Service..13
                  --------------------------------------------------------

ARTICLE VII

         ANCILLARY SERVICES.................................................14

         7.1      Ancillary Services........................................14
                  ------------------

ARTICLE VIII

         GENERAL............................................................15

         8.1      Regulatory Authorization..................................15
                  ------------------------
         8.2      Effect on Other Agreements................................15
                  --------------------------
         8.3      Waivers...................................................15
                  -------
         8.4      Successors and Assigns; No Third Party Beneficiary........15
                  --------------------------------------------------
         8.5      Amendment.................................................16
                  ---------
         8.6      Independent Contractors...................................16
                  -----------------------
         8.7      Responsibility and Liability..............................16
                  ----------------------------

SCHEDULE A

         ALLOCATION OF TRANSMISSION REVENUES................................18

SCHEDULE B

         ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS....................20

SCHEDULE C

         ALLOCATION OF ANCILLARY SERVICE REVENUES...........................22

<PAGE>
                      TRANSMISSION COORDINATION AGREEMENT

                                     Between

                        Central Power and Light Company,
                          West Texas Utilities Company,
                       Public Service Company of Oklahoma,
                       Southwestern Electric Power Company

                                       and

                      Central and South West Services, Inc.


     This TRANSMISSION  COORDINATION AGREEMENT,  hereinafter called "Agreement,"
is made and  entered  into as of the first day of  January,  1997,  by and among
Central Power and Light  Company  (CPL),  West Texas  Utilities  Company  (WTU),
Public  Service  Company of Oklahoma  (PSO),  and  Southwestern  Electric  Power
Company (SWEPCO), hereinafter separately referred to as "Company" and jointly as
"Companies," and Central and South West Services, Inc. (CSWS).

     WHEREAS,   Companies  are  the  owners  and  operators  of   interconnected
generation, transmission and distribution facilities with which they are engaged
in the  business  of  transmitting  and  selling  electric  power to the general
public, to other entities and to other electric utilities; and

     WHEREAS,  Companies  achieve economic  benefits for their customers through
coordinated   planning,   operation  and   maintenance  of  their   transmission
facilities;

     NOW, THEREFORE, the Companies and CSWS mutually agree as follows:



<PAGE>


                                        2

                                    ARTICLE I

                                TERM OF AGREEMENT

     1.1 Effective Date

     This Agreement shall become  effective as of January 1, 1997, or such later
date  as is  established  by the  Federal  Energy  Regulatory  Commission.  This
Agreement  shall  continue in force and effect  until  December  31,  2001,  and
continue from year to year thereafter  until  terminated by written notice given
by any Company to the other Companies and to CSWS.


     1.2 Periodic Review

     This Agreement will be reviewed periodically by the Coordinating Committee,
as defined herein, to determine whether revisions are necessary to meet changing
conditions.  In the event that  revisions are made by the Companies  pursuant to
Section  8.5,  and after  requisite  approval  or  acceptance  for filing by the
appropriate regulatory  authorities,  the Coordinating Committee may thereafter,
for  the  purpose  of  ready  reference  to  a  single  document,   prepare  for
distribution to the Companies an amended document  reflecting all changes in and
additions to this Agreement with notations thereon of the date amended.


<PAGE>
                                        3

                                   ARTICLE II

                                   DEFINITIONS

     For purposes of this Agreement, the following definitions shall apply:

     2.1 Agreement shall mean this Transmission Coordination Agreement including
all  attachments  and  schedules   applying  thereto  and  any  amendments  made
hereafter.

     2.2  Ancillary  Services  shall mean those  services  that are necessary to
support the  transmission  of capacity and energy from  resources to loads while
maintaining  reliable  operation of the  Companies'  transmission  facilities in
accordance  with Good  Utility  Practice,  as that term is  defined  in the Open
Access Transmission Tariff.

     2.3 Company  Demand  shall mean the demand in  megawatts  of all retail and
wholesale  power customers on whose behalf the Company,  by statute,  franchise,
regulatory  requirement,  or contract, has undertaken an obligation to construct
and operate its transmission  system to meet the reliable electric needs of such
customers,  integrated over a period of one hour, plus the losses  incidental to
that service.

     2.4 Company  Peak Demand for a period shall be the highest  Company  Demand
for any hour during the period.

     2.5 Control  Area shall mean an electric  power  system or  combination  of
electric power systems to which a common automatic  generation control scheme is
applied for the purposes specified in the Open Access Transmission Tariff.

     2.6 Coordinating Committee shall mean the organization established pursuant
to  Section  4.1 of this  Agreement  and whose  duties  are more fully set forth
herein.


<PAGE>
                                       4

     2.7  Designated  Agent  shall  mean any  entity  that  performs  actions or
functions on behalf of the Transmission  Provider, an Eligible Customer (as that
term is defined in the Open Access  Transmission  Tariff),  or the  Transmission
Customer required under the Open Access Transmission Tariff.

     2.8 Direct  Assignment  Facilities  shall mean  facilities  or  portions of
facilities that are constructed by the Transmission Provider for the sole use or
benefit of a particular  Transmission Customer requesting service under the Open
Access Transmission Tariff.

     2.9  Generating  Unit shall mean an electric  generator,  together with its
prime mover and all auxiliary and appurtenant  devices and equipment designed to
be operated as a unit for the production of electric capacity and energy.

     2.10 Hour shall mean a clock-hour.

     2.11 Month shall mean a calendar month consisting of the applicable 24-Hour
periods as measured by Central Standard Time.

     2.12 Network Integration  Transmission  Service shall mean the transmission
service provided under Part III of the Open Access Transmission Tariff.

     2.13  Open  Access   Transmission   Tariff   shall  mean  the  Open  Access
Transmission  Tariff  filed with the Federal  Energy  Regulatory  Commission  on
behalf of the Companies as it may be amended from time to time.

     2.14  Point-to-Point  Transmission  Service shall mean the  reservation and
transmission  of capacity and energy on either a firm or non-firm basis from the
points of  receipt to the points of  delivery  under Part II of the Open  Access
Transmission Tariff.


<PAGE>
                                        5


     2.15 PUCT shall mean the Public Utility Commission of Texas.

     2.16 Scheduling, System Control and Dispatch Service shall mean the service
required to schedule the movement of power through,  out of,  within,  or into a
Control Area, as specified in Schedule 1 of the Open Access Transmission Tariff.

     2.17  Transmission  Customer shall mean any Eligible Customer as defined in
the Open Access  Transmission Tariff (or its Designated Agent) that (i) executes
a Service Agreement,  or (ii) requests in writing that the Transmission Provider
file with the Federal Energy Regulatory Commission a proposed unexecuted Service
Agreement to receive  service under the Open Access  Transmission  Tariff.  This
term is  used  in the  Part I  Common  Service  Provisions  of the  Open  Access
Transmission  Tariff to include  customers  receiving  service under Part II and
Part III of the Open Access Transmission Tariff.

     2.18 Transmission  Provider shall mean the Transmission System Operator (or
its Designated Agent).

     2.19 Transmission  Service shall mean Point-to-Point  Transmission  Service
provided  under  Part II of the Open  Access  Transmission  Tariff on a firm and
non-firm basis.

     2.20  Transmission  System shall mean the facilities  owned,  controlled or
operated by the Companies  that are used to provide  transmission  service under
Parts II and III of the Open Access Transmission Tariff.

     2.21  Transmission  System  Operator  shall  mean that part of CSWS that is
charged with monitoring the reliability of the Companies' Transmission System.



<PAGE>
                                        6

                                   ARTICLE III

                                   OBJECTIVES

     3.1 Purposes

     The purposes of this Agreement are (a) to provide the contractual basis for
the coordinated planning and operation of the Companies' transmission facilities
to achieve  optimal  economies,  consistent with reliable  electric  service and
regulatory and environmental  requirements and (b) to provide the means by which
the Companies will allocate  among  themselves the revenue that they receive for
service provided under the Open Access Transmission Tariff. Any revenue received
by a  Company(ies)  from the provision of service under an agreement,  tariff or
rate schedule other than the Open Access Transmission Tariff,  including without
limitation  the Open  Access  Transmission  Tariff  for  Service  Offered by the
Southwest Power Pool  Transmission  Providers,  will be kept by the Company(ies)
that is (are) the party(ies) to such agreement, tariff or rate schedule.


<PAGE>
                                       7


                                   ARTICLE IV

                             COORDINATING COMMITTEE

     4.1 Coordinating Committee

     The  Coordinating  Committee  is the  organization  established  to oversee
planning,  construction,  operation, and maintenance of the Transmission System.
The   Coordinating   Committee   members  shall  include  at  least  one  member
representing  each of the  parties  hereto who is not a member of the  Operating
Committee  established under the CSW Operating Agreement.  The chairperson,  who
shall be the  appointed  by the chief  executive  officer  of the  holder of the
majority  of the  common  stock  of the  Companies,  shall  appoint  the  member
representative(s) of the Companies.  Other than the chairperson,  there shall be
the same  number of members  representing  each  Company.  The  majority  of the
members on the Coordinating Committee shall be representatives of the Companies.
Coordinating  Committee  decisions shall be by a majority vote of those present.
However,  any member not present may vote by proxy.  The chairperson  shall vote
only in case of a tie. No merchant  function  employee of the Companies shall be
appointed to, or serve on, the Coordinating Committee.

     4.2 Responsibilities of the Coordinating Committee

     The Coordinating Committee shall be responsible for overseeing:

          (a) the Companies in the  coordinated  planning of their  transmission
     facilities,  including studies for transmission planning purposes and their
     interaction  with  independent  system  operators and other regional bodies
     that are interested in transmission planning; and



<PAGE>


                                        8

          (b) compliance with the terms of the Open Access  Transmission  Tariff
     and the rules and regulations of the Federal Energy  Regulatory  Commission
     relating thereto.

     4.3 Delegation and Acceptance of Authority

     The  Companies  hereby  delegate  to the  Coordinating  Committee,  and the
Coordinating  Committee  hereby  accepts,  responsibility  and authority for the
duties listed in this Article and elsewhere in this Agreement.

     4.4 Reporting

     The  Coordinating  Committee shall provide  periodic summary reports of its
activities  under this Agreement to the  transmission  and reliability  function
employees  of the  Companies  and shall  keep such  employees  of the  Companies
informed of situations or problems that may materially affect the reliability of
the  Transmission  System.  Furthermore,  the  Coordinating  Committee agrees to
report to the transmission and reliability  function  employees of the Companies
in such additional detail as is requested  regarding specific issues or projects
under its oversight.



<PAGE>
                                        9

                                    ARTICLE V

                                    PLANNING

     5.1 Transmission Planning

     The Companies agree that their respective  transmission facilities shall be
planned  and  developed  on the basis that  their  combined  individual  systems
constitute a  coordinated  transmission  system and that the  objective of their
planning  shall be to maximize the economy,  efficiency  and  reliability of the
Transmission System as a whole. In this connection,  the Coordinating  Committee
will from time to time, as it deems appropriate, direct studies for transmission
planning purposes.



<PAGE>
                                      10

                                   ARTICLE VI

                                  TRANSMISSION

     6.1 Delegation to the Transmission System Operator

     The  Companies  shall  delegate to the  Transmission  System  Operator  the
responsibility  and authority to act as  Transmission  Provider on behalf of the
Companies  for  all  of  the  requirements  and  purposes  of  the  Open  Access
Transmission Tariff.

     6.2 Transmission Facilities

     Each  Company  shall  make its  transmission  facilities  available  to the
Transmission System Operator.

     6.3 Direct Assignment Facilities

     Each  Company  shall make Direct  Assignment  Facilities  available  to the
Transmission  System  Operator  as may  be  required  to  provide  service  to a
particular  Transmission  Customer  requesting  service  under  the Open  Access
Transmission Tariff.

     6.4 Transmission Service Revenues

     (a) The Companies shall share  transmission  service revenues obtained from
the use of the transmission  facilities that comprise the Transmission System in
accordance with Schedule A to this Agreement.  Transmission service revenues are
those revenues received for service provided under the Open Access  Transmission
Tariff.  The Companies' annual  transmission  revenue  requirements are shown on
Schedule B to this Agreement and shall be revised  whenever there is a change to
the annual transmission  revenue requirements in Attachment H to the Open Access
Transmission Tariff or a change to the annual transmission


<PAGE>
                                      11


revenue requirements  underlying the rates set forth in Schedules 7 and 8 to the
Open Access Transmission  Tariff.  Future revisions to the transmission  revenue
requirements  ratios  set  forth in  Schedule  B will be made by the  Companies'
making an  appropriate  filing with the  Commission,  if  required by law.  Such
changes  shall  become  effective  as of the date  accepted  or  approved by the
Commission, subject to refund if the Commission so orders.

     (b) Revenues  received for ERCOT  Regional  Transmission  Service  provided
under Part IV of the Open Access  Transmission Tariff shall be allocated between
CPL and WTU in accordance with matrices prepared by the ERCOT independent system
operator (ISO).

     (c) Revenues  received for Ancillary  Services shall be allocated among the
Companies in accordance  with the revenue ratios set forth in Schedule C. Future
revisions  to the  revenue  ratios  set forth in  Schedule C will be made by the
Companies' making an appropriate filing with the Commission, if required by law.
Such changes  shall become  effective as of the date accepted or approved by the
Commission, subject to refund if the Commission so orders.

     (d) Revenues received for third-party use of Direct  Assignment  Facilities
shall be distributed to the Company(ies) owning such facilities.

     (e) The  distribution  to the  Companies of revenues  received for stranded
costs received from  third-party  customers  under the Open Access  Transmission
Tariff shall be determined on a  case-by-case  basis and shall be filed with the
Commission, if required by law.

     (f)  The  distribution  to the  Companies  of  revenues  received  for  new
transmission  facilities  received  from  third-party  customers  under the Open
Access Transmission Tariff shall be determined on a case-by-case basis and shall
be filed with the Commission, if required by law.

<PAGE>
                                       12

     (g)  Revenues   received  for  studies  performed  for  the  benefit  of  a
Transmission  Customer under Part II or Part III of the Open Access Transmission
Tariff shall be allocated to each CSW  Operating  Company in  proportion  to the
ratio of each CSW Operating Company's number of transmission pole miles, as such
number of  transmission  pole miles is reported in each CSW Operating  Company's
Form 1 annual report,  over the total number of  transmission  pole miles of the
Transmission System.  Revenues received for studies performed for the benefit of
a  Transmission  Customer under Part IV of the Open Access  Transmission  Tariff
shall be  allocated  between CPL and WTU in  proportion  to the ratio of each of
their respective  transmission  pole miles, as such  transmission pole miles are
reported in their Form 1 annual  reports,  over the total number of transmission
pole miles of CPL and WTU combined.


     6.5 Payment of Costs for Network Use

     The  Transmission  System Operator shall bill each of the Companies for the
amount due to the  Transmission  System  Operator in each Month for their use of
Network Integration  Transmission  Service and Ancillary Services under the Open
Access   Transmission  Tariff  on  the  basis  set  forth  in  the  Open  Access
Transmission Tariff.



<PAGE>


                                       13

     6.6 Payment of Costs for Point-to-Point Transmission Service

          (a) The cost of Transmission  Service on the  Transmission  System for
     third-party  off-system  sales by a Company  shall be borne by the  selling
     Company(ies).

          (b) The cost of  Transmission  Service  provided by a third-party  for
     off-system sales by a Company shall be borne by the selling Company(ies).




<PAGE>


                                       14

                                   ARTICLE VII

                               ANCILLARY SERVICES

     7.1 Ancillary Services

          (a) Each Company shall make available  Ancillary  Services as required
     to provide service under the Open Access Transmission Tariff.

          (b) Revenues received for Ancillary Services will be allocated between
     the Companies in accordance with Section 6.4(c) of this Agreement.




<PAGE>


                                       15

                                  ARTICLE VIII

                                     GENERAL

     8.1 Regulatory Authorization

     This Agreement is subject to certain regulatory approvals and the Companies
shall diligently seek all necessary regulatory authorization for this Agreement.

     8.2 Effect on Other Agreements

     This  Agreement  shall not modify the  obligations  of any of the Companies
under any  agreement  between  such  Company  and  others  not  parties  to this
Agreement in effect on the effective date of this Agreement.

     8.3 Waivers

     Any waiver at any time by a Company of its rights with respect to a default
by any other  Company  under this  Agreement  shall not be deemed a waiver  with
respect to any subsequent default of similar or different nature.

     8.4 Successors and Assigns; No Third Party Beneficiary

     This  Agreement  shall  inure to and be  binding  upon the  successors  and
assigns of the respective  Companies,  but shall not be assignable by any of the
Companies  without  the  written  consent of the other  Companies,  except  upon
foreclosure of a mortgage or deed of trust. Nothing expressed or mentioned or to
which  reference is made in this  Agreement is intended or shall be construed to
give any person or  corporation  other than the Companies any legal or equitable
right,  remedy or claim under or in respect of this  Agreement or any  provision
herein  contained,  expressly  or by  reference,  or any schedule  hereto,  this
Agreement, any such schedule


<PAGE>


                                       16

and any and all conditions  and provisions  hereof and thereof being intended to
be and  being  for the sole  exclusive  benefit  of the  Companies,  and for the
benefit of no other person or corporation.

     8.5 Amendment

     It is contemplated by the Companies that it may be appropriate from time to
time to change, amend, modify or supplement this Agreement or the schedules that
are attached to this  Agreement,  to reflect  changes in operating  practices or
costs of operations or for other  reasons.  This Agreement or such schedules may
be  changed,  amended,  modified or  supplemented  by an  instrument  in writing
executed by all of the Companies  subject to any required approval or acceptance
for filing by the appropriate regulatory authorities.

     8.6 Independent Contractors

     By entering into this  Agreement the Companies  shall not become  partners,
and  as to  each  other  and  to  third  persons,  the  Companies  shall  remain
independent contractors in all matters relating to this Agreement.

     8.7 Responsibility and Liability

     The liability of the Companies  shall be several,  not joint or collective.
Each Company shall be responsible only for its obligations,  and shall be liable
only for its  proportionate  share of the costs and expenses as provided in this
Agreement,  and any  liability  resulting  herefrom.  Each  Company will defend,
indemnify, and save harmless the other Companies hereto from and against any and
all  liability,  loss,  costs,  damages,  and  expenses,   including  reasonable
attorney's  fees,  caused by or  growing  out of the gross  negligence,  willful
misconduct, or breach of this Agreement by such indemnifying Company.


<PAGE>
                                       17


     IN WITNESS  WHEREOF,  each Company has caused this Agreement to be executed
and attested by its duly authorized officers.

                                       CENTRAL POWER AND LIGHT COMPANY
Attest

________________________               By:________________________________
Secretary                                       President


                                       WEST TEXAS UTILITIES COMPANY
Attest

________________________               By:________________________________
Secretary                                       President

                                       PUBLIC SERVICE COMPANY OF OKLAHOMA
Attest

________________________               By:________________________________
Secretary                                       President


                                       SOUTHWESTERN ELECTRIC POWER COMPANY
Attest

_________________________              By:________________________________
Secretary                                       President

                                       CENTRAL AND SOUTH WEST SERVICES, INC.
Attest

_________________________              By:________________________________
Secretary                                       President



<PAGE>


                                       18

                                   SCHEDULE A

                       ALLOCATION OF TRANSMISSION REVENUES


     1. Allocation of Transmission Revenues

     The revenue the Transmission  System Operator  receives pursuant to Section
6.4 of the  Agreement for service  provided by the Companies  under Parts II and
III of the  Open  Access  Transmission  Tariff,  other  than  revenues  received
pursuant to Sections 26  (Stranded  Cost  Recovery),  27  (Compensation  for New
Facilities and Redispatch Costs),  and 34.4 (Redispatch  Charge) thereof and for
System and  Facilities  Studies made pursuant to Sections 19  (Additional  Study
Procedures  for  Firm  Point-to-Point  Transmission  Service  Requests)  and  32
(Additional  Study  Procedures  for  Network  Integration  Transmission  Service
Requests),  will be allocated among the Companies based on the ratios determined
in accordance with Schedule B and Schedule C.

     Revenues  related  to studies  performed  for the  benefit of  Transmission
Customers under Part II or Part III of the Open Access  Transmission Tariff will
be  allocated  among the four CSW  Operating  Companies in  proportion  to their
respective  number  of  transmission  pole  miles  on the  Transmission  System.
Revenues related to studies performed for the benefit of Transmission  Customers
under Part IV of the Open Access  Transmission  Tariff will be allocated between
CPL and WTU in proportion to their respective  number of transmission pole miles
on the combined CPL/WTU system. Direct Assignment Facilities will be assigned to
the Companies in  proportion  to the related  costs that each of them  incurred.
Assignment of revenues received from a third

<PAGE>


                                       19

party  related  to  stranded  cost  or  new  transmission  facilities  shall  be
determined on a case-by-case basis.




<PAGE>


                                       20

                                   SCHEDULE B

                 ANNUAL TRANSMISSION REVENUE REQUIREMENTS RATIOS

     From time to time the Coordinating Committee will calculate for each of the
Companies  its  Transmission  Revenue  Requirements  Ratios set forth  below.  A
Company's  Transmission  Revenue  Requirements  Ratio for revenue received under
Part  III of the Open  Access  Transmission  Tariff  shall  be a  fraction,  the
numerator of which is the Company's  transmission  revenue  requirement  that is
used to calculate the Annual Transmission  Revenue Requirements amount set forth
on  Attachment  H to the Open  Access  Transmission  Tariff  (herein  called the
Company  Revenue  Requirement)  and the  denominator  of which is the sum of the
Company Revenue Requirement for all of the Companies.  A Company's  Transmission
Revenue  Requirement Ratio for revenue received under Part II of the Open Access
Transmission Tariff shall be a fraction, the numerator of which is the Company's
transmission  revenue  requirement  that is used to calculate the Annual cost of
service  Transmission Revenue Requirements amount underlying the rates set forth
on Schedules 7 and 8 to the Open Access  Transmission Tariff and the denominator
of  which  is  the  sum of  the  Company  Revenue  Requirements  for  all of the
Companies.

     1.   Allocation  Ratio  for  Revenue  Received  Under  Part III of the Open
          Access Transmission Tariff from a Non-ERCOT Loading Serving Entity

          Revenue Requirement          Revenue Requirement Ratio

CPL          $60,092,806                      33.58595%
PSO          $43,794,213                      24.47665%
SWEPCO       $48,986,232                      27.37848%
WTU          $26,049,174                      14.55892%

TOTAL        $178,922,425                    100.00000%


<PAGE>


                                       21



     2.   Allocation  Ratio for  Revenue  Received  Under  Part-III  of the Open
          Access Transmission Tariff from an ERCOT Load Serving Entity

          Revenue Requirement          Revenue Requirement Ratio

CPL          $ 2,834,098                       2.93693%
PSO          $43,794,213                      45.38323%
SWEPCO       $48,986,232                      50.76364%
WTU          $     884,123                     0.91620%

TOTAL        $96,498,666                     100.00000%


     3.   Allocation Ratio for Revenue Received Under Part II of the Open Access
          Transmission Tariff

          Revenue Requirement          Revenue Requirement Ratio

CPL          $60,092,806                      32.83174%
PSO          $45,727,891                      24.98347%
SWEPCO       $51,149,157                      27.94538%
WTU          $26,062,756                      14.23941%

TOTAL        $183,032,610                    100.00000%


     4.   Allocation Ratio for Revenue Received Under Part II of the Open Access
          Transmission  Tariff When Part II Service Is Taken In Conjunction With
          Part IV Service

          Revenue Requirement          Revenue Requirement Ratio

CPL          $ 2,834,098                       2.81695%
PSO          $45,727,891                      45.45116%
SWEPCO       $51,149,157                      50.83962%
WTU          $   897,705                       0.89227%

TOTAL        $100,608,851                    100.00000%



<PAGE>


                                       22

     5.   Allocation Ratio for Revenue Received Under Part II the of Open Access
          Transmission  Tariff When Part II Service Is Taken In Conjunction With
          the SPP Tariff

          Revenue Requirement          Revenue Requirement Ratio

CPL          $60,092,806                      70.01019%
WTU          $25,741,569                      29.98981%

TOTAL        $85,834,375                     100.00000%


<PAGE>
                                       23

                                   SCHEDULE C

                    ALLOCATION OF ANCILLARY SERVICE REVENUES


     The  revenues  the  Transmission   System  Operator  receives  pursuant  to
Schedules  1  through  6 and  Schedules  9  through  19 under  the  Open  Access
Transmission  Tariff shall be allocated  among the Companies as set forth below.
Future  revisions to the revenue  ratios set forth in Schedule C will be made by
the Companies' making an appropriate filing with the Commission,  if required by
law. Such changes shall become  effective as of the date accepted or approved by
the Commission, subject to refund if the Commission so orders.

     (a)  Revenues received from System Scheduling,  System Control and Dispatch
          Service under Schedule 1 of the Open Access  Transmission  Tariff will
          be allocated among the Companies based on the following ratio:

                  CPL                       31.25%
                  WTU                       11.78%
                  PSO                       25.48%
                  SWEPCO                    31.49%

     (b)  Revenues received from System Reactive Supply and Voltage Control from
          Generation  Sources  Service  under  Schedule  2 of  the  Open  Access
          Transmission Tariff will be allocated among the Companies based on the
          following ratio:

                  CPL                       53.59%
                  WTU                        7.23%
                  PSO                       15.60%
                  SWEPCO                    23.58%


<PAGE>


                                       24

     (c)  Revenues  received  from  System  Regulation  and  Frequency  Response
          Service  under  Schedule  3-A and from System Load  Following  Service
          under Schedule 3-B for load served in the PSO/SWEPCO Control Area will
          be allocated between PSO and SWEPCO based on the following ratio:

                  PSO                       40.00%
                  SWEPCO                    60.00%

          Revenues  received  from  System  Regulation  and  Frequency  Response
          Service  under  Schedule  3-A and from System Load  Following  Service
          under Schedule 3-B for load served in the CPL/WTU Control Area will be
          allocated between CPL and WTU based on the following ratio:

                  CPL                       70.18%
                  WTU                       29.82%

     (d)  Revenues  received for and energy  exchanged as part of System  Energy
          Imbalance  Service  rendered under Schedule 4 will be allocated in the
          same  manner as margin  from off- system  sales and  purchases  as set
          forth in Schedule F to the CSW Operating Agreement, a copy of which is
          attached hereto.



<PAGE>


                                       25


     (e)  Revenues  received from System  Operating  Reserve - Spinning  Reserve
          Service  (SPP) under  Schedule 5 and from System  Operating  Reserve -
          Supplemental  Reserve  Service under Schedule 6 for load served in the
          PSO/SWEPCO Control Area will be allocated between PSO and SWEPCO based
          on the following ratio:

                  PSO                       35.91%
                  SWEPCO                    64.09%

     (f)  Revenues received from System Operating  Reserve - Responsive  Reserve
          Service (ERCOT) under Schedule 5 and from System  Operating  Reserve -
          Supplemental  Reserve  Service under Schedule 6 for load served in the
          CPL/WTU  Control Area will be  allocated  between CPL and WTU based on
          the following ratio:

                  CPL                       68.71%
                  WTU                       31.29%

     (g)  Revenues  received from the provision of the ERCOT Responsive  Reserve
          Service  under  Schedule  9,  ERCOT  Spinning  Reserve  Service  under
          Schedule 10, ERCOT Load  Following  Service  under  Schedule 13, ERCOT
          Generation - Scheduling  Imbalance  Service  under  Schedule 15, ERCOT
          Load - Schedule  Imbalance  Service under Schedule 16, ERCOT Scheduled
          Backup Service under Schedule 17, ERCOT Automatic Backup Service under
          Schedule 18, and ERCOT Emergency  Energy Service under Schedule 19 for
          load served in the CPL/WTU Control Area will be allocated  between CPL
          and WTU based on the following ratio:

                  CPL                       69.22%
                  WTU                       30.78%



<PAGE>
                                      26


     (h)  Revenues  received from the  provision of the ERCOT Static  Scheduling
          Service under Schedule 11 and ERCOT Dynamic  Scheduling  Service under
          Schedule  12 for load  served  in the  CPL/WTU  Control  Area  will be
          allocated between CPL and WTU based on the following ratio:

                  CPL                       72.62%
                  WTU                       27.38%

     (i)  Revenues  received  from the  provision  of the ERCOT Load  Regulation
          Service under Schedule 14 for load served in the CPL/WTU  Control Area
          will be allocated between CPL and WTU based on the following ratio:

                  CPL                       70.53%
                  WTU                       29.47%


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>8
<FILENAME>x10l1c.txt
<DESCRIPTION>(L)(1)(C) AMEND EXCESS BENEFIT PLAN
<TEXT>
<PAGE>

                                                             EXHIBIT 10(l)(1)(C)



                                 FIRST AMENDMENT
                                       TO
                         AMERICAN ELECTRIC POWER SYSTEM
                               EXCESS BENEFIT PLAN
               (As amended and restated effective January 1, 2001)


     American Electric Power Service  Corporation adopts the following amendment
to the  American  Electric  Power System  Excess  Benefit  Plan,  as amended and
restated as of January 1, 2001 (the "Plan").

1.   Section  2.14 of the Plan is  hereby  amended  in its  entirety  to read as
     follows:

          "2.14 `Maximum  Benefit' means the vested  retirement  benefit payable
     from the Retirement  Plan under either the Final Average Pay Formula or the
     Cash Balance Formula, whichever is greater, given the Participant's marital
     status, Beneficiary, credited service and earnings for services rendered to
     the  Company,  to the  extent  such  are  permitted  by the  Code  and  the
     Retirement Plan to be taken into account under either the Final Average Pay
     Formula or the Cash Balance Formula."

2.   Section  2.21 of the Plan is  hereby  amended  in its  entirety  to read as
     follows:

          "2.21 `Unrestricted  Benefit' means the vested retirement benefit that
     would be payable from the  Retirement  Plan under either the Final  Average
     Pay Formula or the Cash Balance  Formula,  whichever is greater,  given the
     Participant's  marital  status,  Beneficiary,  credited  service  and  Plan
     Earnings,   assuming  sections  401(a)(17)  (Compensation  Limit)  and  415
     (Limitation  on  Benefits) of the Code are not  applicable  and taking into
     account any service,  Plan Earnings and other  adjustments  as are provided
     for in an Employment Agreement."

3.   In all other respects, the terms of the Plan are ratified and confirmed.

          IN WITNESS  WHEREOF,  this Amendment has been executed this 5th day of
     March, 2003.

American Electric Power Service Corporation


By:   /s/ Thomas M. Hagan
Title Executive Vice President - Shared Services


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>9
<FILENAME>x10m3a.txt
<DESCRIPTION>(M)(3)(A) KOEPPEL EMPLOY LETTER
<TEXT>

<PAGE>

                                                             EXHIBIT 10(m)(3)(A)
American Electric Power
1 Riverside Plaza
Columbus, OH  43215-2373


Ms. Holly Keller Koeppel
29 Lynwood Avenue
Killara, NSW, AU 2071

June 23, 2000

Dear Holly:

This letter  supercedes  our earlier  letter dated April 13, 2000  regarding our
offer of employment to you as Vice  President-New  Ventures of American Electric
Power Service Corporation. Your primary work location will be Columbus, Ohio and
you will report  directly to me. We will determine a mutually  acceptable  start
date following your acceptance of this offer.

Among other duties that may be assigned,  you will be  responsible  for managing
the activities of AEP's New Ventures  group.  This will include the  development
and application of screening  criteria to assist AEP in decisions  regarding the
commitment of resources in the pursuit of new business  opportunities  developed
by New Ventures.  In addition,  you will be responsible  for the  development of
business plans for new business  opportunities that are pursued by New Ventures.
You will also assume responsibility for certain administrative  functions in AEP
Corporate Development.

Your position will be at an AEP salary grade of 36. Your starting salary will be
$200,000  a year and will be  reviewed  on an  annual  basis.  Subject  to their
specific terms, including Board approval as necessary,  you will be eligible for
AEP's  Management  Incentive  Compensation  Plan (MICP),  effective  upon merger
closing and AEP's  Performance  Share Incentive Plan (PSIP) beginning January 1,
2001. In addition,  you will be eligible to participate in AEP's Long-Term Stock
Option Incentive Plan.

The MICP for your  position  presently  has an annual target of 30% of your base
compensation, 100% of which will be based on overall corporate performance under
the Plan. Actual awards may range from 0% to 200% of target and are paid as soon
as possible, after year-end results are confirmed.

The PSIP for your  position  presently  provides an annual  award of 30% of your
base  compensation  converted  to AEP share units at market  value at the end of
each three-year performance period. Those units are subsequently multiplied from
0% to 200% to establish  actual  awards based on  comparative  three-year  Total
Shareholder  Return.  Dividends are credited during the  performance  period and
converted to equivalent performance share units.

PSIP payments are made annually at the end of each three-year  performance cycle
based on the  market  value of AEP stock at that time.  Payment  can be taken in
cash or stock  once the  stock  ownership  target  for  your  position  has been
achieved.  Your  participation  in PSIP will  begin on  January  1, 2001 with an
initial  award  that will be  comprised  of 1/3 of your  normal  target  for the
1999-2001  performance  cycle,  2/3 of your  normal  target  for  the  2000-2002
performance  cycle,  and the full  award for your  normal  target of 30% for the
2001-2003 performance cycle.

AEP's Long-Term Stock Option  Incentive Plan was approved by shareholders at the
Annual  Meeting  in  April.  Given  this  approval  by the  shareholders,  it is
anticipated  that there will be a stock option  grant during 2000,  but specific
eligibility,  amounts,  and  terms  have not  been  approved  yet by AEP  Senior
Management or the HR Committee of the Board.

This offer of employment is contingent upon the following:

*        successful completion of a pre-employment physical exam
*        verification of academic credentials
*        acceptable reference checks

Therefore,   please  complete  the  enclosed   Application  for  Employment  and
associated documents as soon as possible and return it in the envelope provided.

You will also find enclosed a letter,  which  outlines  those health and welfare
benefits for which you will be eligible  (the  benefit  letter was sent with the
earlier  offer  letter and remains  unchanged).  In  addition to those  benefits
outlined  in the that  letter,  your  pension  when you retire at any time after
vesting will be calculated using your actual AEP years of service at retirement,
plus your years of service  while you were  employed  by CNG, as if you had been
continuously  employed for the combined period,  less any retirement benefit you
are entitled to receive from CNG's retirement plan.

Please feel free to contact me or Tim Harshbarger (624-223-1576) if you have any
questions or concerns.

Sincerely,

/s/ Donald M. Clements, Jr.

Donald M. Clements, Jr.
Executive Vice President

Enclosures
c:       T. G. Harshbarger
         W. R. Beckley
         S.D. Thomas



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>10
<FILENAME>x10m3b.txt
<DESCRIPTION>(M)(3)(B) KOEPPEL RETENTION LETTER
<TEXT>

<PAGE>

                                                             EXHIBIT 10(m)(3)(B)
AEP Resources, Inc.
1 Riverside Plaza
Columbus, OH  43215-2373



Ms. Holly Koeppel AEP Resources, Inc.

April 19, 2001

Dear Holly,

As you  are  aware,  AEP has  recently  revised  its  strategy  relative  to the
long-term ownership and participation in a number of our assets,  joint ventures
and investments. I realize this decision raises questions in your mind regarding
your own future.

I would like to take this  opportunity  to emphasize  the critical  role you are
playing as we seek to evaluate,  restructure and where necessary divest of these
assets,  joint  ventures and  investments;  the need for you to continue in this
role; and the value the company places on your experience and expertise.

In addition,  and to further  emphasize  the desire to retain your  services,  a
retention  plan  has been  developed.  In  consideration  of your  agreement  to
continue your employment in the Corporate  Development  group until December 31,
2002  (or  an  earlier  date   mutually   agreed  to  by  yourself  and  an  AEP
representative),  you will receive a lump sum  retention  payment  equal to nine
months of your annual base salary minus  applicable  withholdings.  This payment
shall be made regardless of whether or not you are thereafter employed by AEP.

You would  forfeit all rights and claims to any  retention  payments  should you
leave  Corporate  Development  voluntarily  prior  to  December  31,  2002 or be
terminated for cause.

If the proposal  contained in this letter is  acceptable  to you, it will become
effective when you sign this letter and return it to me.

Sincerely,

/s/ Donald M. Clements, Jr.

Donald M. Clements, Jr.
President


Agreed:

/s/ Holly K. Koeppel                25 April 2001


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>11
<FILENAME>x10m4.txt
<DESCRIPTION>(M)(4) POWERS EMPLOYMENT AGREEMENT
<TEXT>

<PAGE>

                                                                EXHIBIT 10(m)(4)

                              EMPLOYMENT AGREEMENT

     In  consideration  of the mutual promises and covenants  contained  herein,
this  Employment  Agreement  (the  "Agreement")  is entered  into by and between
American Electric Power Service Corporation,  including any of its parent and/or
subsidiary   companies,   divisions,   organizations,   or  affiliated  entities
(collectively  referred to as "AEP"),  and Robert P. Powers (the  "Employee" and
with AEP sometimes collectively referred to as the "Parties"),  this 29th day of
July, 1998.

                          Section I: Term of Employment

     1.01 AEP  agrees  to  employ  Employee  as  Senior  Vice  President-Nuclear
beginning on July 31, 1998 (hereafter referred to as the "Date of Hire").

                         Section II: Duties of Employee

     2.01 Employee shall report to E. Linn Draper,  Jr. or such other individual
as he may designate.  Employee's duties and responsibilities  shall include, but
are not limited to, the following:  operating  AEP's Cook Nuclear Plant and such
other nuclear generation facilities that AEP may periodically acquire, in a safe
and efficient  manner,  ensuring that operations are in full compliance with all
applicable local, state and federal laws,  regulations  and/or  ordinances;  and
perform other related duties that may be assigned from time to time.

     2.02  During   Employee's   employment  with  AEP,  Employee  shall  devote
Employee's  best  efforts,  loyalty,  and  entire  working  time with AEP to the
performance  of Employee's  duties,  and shall not render  services to, or enter
into an employment, independent contractor,  consultancy, or agency relationship
with, any person, firm,  corporation,  other business entity and/or governmental
body or agency other than AEP without AEP's express, prior and written consent.

                     Section III: Compensation and Benefits

     3.01 As compensation  for services and duties rendered under the Agreement,
Employee  shall  receive  from AEP an annual  salary of  $240,000.00  payable in
accordance with AEP's standard payroll practices and subject to withholdings for
FICA and applicable federal, state and local income taxes.

     3.02 Subject to AEP's right to change,  modify,  amend and/or eliminate any
of the  following,  Employee  shall be entitled to  participate  in AEP's Exempt
Salary  Administration  Program, The Management Incentive Program ("MICP"),  The
Performance Share Incentive Program ("PSIP"),  The Nuclear Performance Incentive
Program  ("NPIP"),  The AEP System  Survivor  Benefit Plan (Split  Dollar),  the
American  Electric Power Excess Benefit Plan, and AEP's savings,  retirement and
employee welfare/benefit programs. Upon such terms and conditions established by
AEP, and subject to AEP's right to change,  modify,  amend and/or  eliminate the
following,  the Employee  shall also be entitled to  additional  executive-level
benefits such as a company car and a country club membership.

     3.03 Employee shall be entitled to ten days of paid vacation and three paid
personal days to be used during 1998, and twenty days of paid vacation and three
paid personal days to be used during each year thereafter.

     3.04  Employee  shall  receive a  $300,000.00  bonus  payment,  subject  to
withholding  for FICA and  applicable  federal,  state and local  income tax, as
follows:  $150,000.00  paid at or around the Date of Hire;  $100,000.00  paid on
January 1, 1999;  and  $50,000.00  on January 1,  2000.  The  Employee  can,  at
Employee's  option,  defer some or all of the  $300,000.00  bonus  payment until
Employee  retires,  in the form of a financial  instrument  that is agreeable to
both AEP and the Employee.  AEP shall not be obligated to pay the bonus payments
that are due and owing to  Employee  on January 1, 1999 and  January 1, 2000 if,
prior   to   those   dates,   AEP   terminates    Employee's    employment   for
performance-related reasons or Employee resigns.

                   Section IV: Supplemental Retirement Benefit

     4.01 The Employee shall be entitled to a Supplemental  Retirement  Benefit.
For pension  calculation  purposes,  employee  shall be credited with  seventeen
years of service in addition to the number of years that the  Employee  actually
works for AEP. The Employee shall be entitled to a retirement benefit calculated
as follows:

     (a)  The retirement benefit the Employee would be entitled to receive as of
          the date of the Employee's termination of employment,  under the terms
          of the American  Electric  Power Excess  Benefit Plan, as amended from
          time to time or any successor thereto, based upon the compensation the
          Employee  received  during  the  term  of this  Employment  Agreement,
          including  earned  MICP  awards  and  excluding  earned  PSIP and NPIP
          awards,  based upon the actual  number of years of service to AEP plus
          seventeen years of credited service;

     (b)  Less the retirement  benefit the Employee would be entitled to receive
          as of the date of the Employee's termination of employment,  under the
          terms of the  American  Electric  Power  System  Retirement  Plan,  as
          amended  from time to time or any  successor  thereto,  based upon the
          compensation the Employee  received during the term of this Employment
          Agreement, excluding earned MICP, PSIP and NPIP awards, for the actual
          years of service to AEP;

     (c)  Less any  retirement  benefit the Employee is entitled to receive from
          all qualified and non-qualified  plans sponsored by any prior employer
          of the Employee. The Employee shall provide the Company with a list of
          such other plans within a reasonable time after Employee's  employment
          terminates.

     4.02 The Employee's election under the terms of the American Electric Power
System Retirement Plan of a 50% Joint and Survivor Annuity or any other optional
form of payment, with the valid consent of the Employee's Spouse where required,
shall be deemed to be the payment  election the  Employee  makes for purposes of
the Supplemental Retirement Benefit.

     4.03 In the  event  the  Agreement  is  terminated  due to the death of the
Employee,   the   Employee's   spouse  shall  be  entitled  to  a   Supplemental
Pre-Retirement  Surviving  Spouse  Annuity  provided  that the  Employee and the
Employee's  spouse were  married  for at least one year prior to the  employee's
death.  The amount of the Supplemental  Pre-Retirement  Surviving Spouse Annuity
shall be equal to the following:

     (a)  The  pre-retirement  surviving  spouse annuity the  Employee's  spouse
          would be entitled to receive under the terms of the American  Electric
          Power System Excess  Benefit  Plan,  based upon the  compensation  the
          Employee  received  from the  Company  prior to his  death,  including
          earned MICP awards and excluding earned PSIP and NPIP awards;

     (b)  Less any surviving  spouse annuity the Employee's  surviving spouse is
          entitled to receive from any qualified or non-qualified plan sponsored
          by any prior employer of the Employee;

     (c)  Less any surviving  spouse annuity the Employee's  surviving spouse is
          entitled to receive from the American Electric Power System Retirement
          Plan.

     4.04 The Supplemental Retirement Benefit or the Supplemental Pre-Retirement
Surviving  Spouse  Annuity  shall be paid out of the  general  assets of AEP and
shall be covered by the American  Electric  Power Service  Corporation  Umbrella
Trust for Executives.  The supplemental  benefits provided by this Agreement are
in lieu of any similar  benefit  provided by the American  Electric Power System
Excess Benefit Plan.

                             Section V: Termination

     5.01  Employee's  employment  with AEP is,  and will be at all  times,  "at
will".  Thus,  AEP or Employee  may  terminate  Employee's  employment  and this
Agreement for any or no reason upon written notice to the other.  In the case of
the Employee, the notice shall be furnished not less than fourteen calendar days
prior  to the  designated  date of  termination.  In the  latter  instance,  AEP
reserves  the  right to  accelerate  Employee's  date of  termination  by paying
Employee two weeks'  salary  calculated  on the basis of the  annualized  amount
indicated in Section 3.01.

     5.02 In the event  that  Employee's  employment  is  terminated  under this
Agreement  by either the  Employee or AEP,  AEP shall no longer be  obligated to
provide Employee with any  compensation  under Section 3.01, but Employee shall,
in  accordance  with the  terms  and  conditions  set forth in each plan then in
effect as  applicable,  be entitled to any amounts to which the  Employee may be
eligible to receive  pursuant to Sections  3.02,  Section  3.03,  Section 4, and
Section 5.01 and in accordance  with the terms and  conditions of each plan then
in effect.

     5.03 In the event  that the  Employee's  position  is  eliminated  due to a
change in AEP's  business  strategy or  organization  not related to  Employee's
performance as the Senior Vice President-Nuclear  prior to Employee reaching age
55, AEP will offer Employee either:

     (a)  a   comparable   position   with   comparable   pay,   benefits,   and
          responsibilities within AEP; or

     (b)  if no such position is available, AEP will continue Employee's pay and
          benefits  for a period  not to  exceed  eighteen  months  (hereinafter
          referred to as the  "Transition  Period") to provide  Employee with an
          opportunity to find  employment  outside of AEP.  Payments  during the
          first twelve months of the Transition Period shall include  Employee's
          normal salary,  benefits,  and Employee's  target MICP,  PSIP and NPIP
          incentive payments at target, prorated for partial portions of a year.
          Payment  during the last six  months of the  Transition  Period  shall
          include Employee's base salary and benefits only. In the event that no
          comparable  position is available  within AEP, the Employee  covenants
          and agrees in good faith to diligently  search for a position  outside
          of AEP.  AEP's  obligations  to compensate  Employee any amount of pay
          and/or  benefits  pursuant  to this  provision  shall  cease as of the
          Employee's effective date of hire with a new employer or at the end of
          the Transition Period, whichever occurs first.

     (c)  For purposes of Section 5.03(a) of this Agreement, a position shall be
          deemed to be comparable if Employee's  total  compensation,  including
          incentives at target,  equal at least 90% of the compensation that the
          Employee received with AEP including incentives at target.

     (d)  If, prior to the  expiration of the  Transition  Period,  the Employee
          accepts  employment  with another  company that is not  comparable (as
          defined in Section 5.03(b) of this  Agreement),  AEP will,  during the
          Transition  Period,  pay the difference  between  Employee's new total
          compensation,  including  incentives  at target,  and the payments the
          Employee  would  have  received  had the  Employee  not  accepted  the
          employment with another company.

         Section VI: Confidential Business Information and Trade Secrets

     6.01 Employee  recognizes that during  Employee's  employment with AEP, the
Employee will have access to and become familiar with confidential,  proprietary
and/or trade secret  information which is owned by AEP and regularly used in its
operation. Employee understands and agrees that AEP's confidential,  proprietary
and/or trade secret  information  derives  independent  economic  value for AEP,
actual or potential,  from not being generally known or readily ascertainable by
other persons and entities who can obtain economic value from such  information,
and  that  AEP  takes  reasonable  efforts  to  maintain  the  secrecy  of  this
information.  Employee agrees that during Employee's employment with AEP, except
as required in the performance of Employee's employment with AEP, or at any time
thereafter,  Employee shall not directly or indirectly  possess,  use,  convert,
misappropriate,  copy or duplicate any  confidential,  proprietary  and/or trade
secret  information,  or communicate,  disclose,  sell, transmit or transfer any
confidential,  proprietary and/or trade secret information to any person,  firm,
partnership, corporation,  proprietorship, or business organization or entity of
any kind or description.

     6.02 Employee  acknowledges  that  confidential,  proprietary  and/or trade
secret  information  is defined to include,  but is not limited to, the whole or
any part of paper copies or paper  documents of any kind,  computer  data bases,
computer e-mail,  computer programs and/or computer memory or storage devices of
any  kind  that  contain,  reflect,  or  relate  to:  (a) the  design,  process,
procedure,  method, technique,  formula, or improvement of any current or future
products or services developed,  manufactured,  owned,  produced,  sold, leased,
distributed  or  provided  by  AEP;  (b)  marketing  plans  and  any  associated
information such as customer names and/or contacts, addresses,  telephone or fax
numbers,  mailing  lists,  and customer,  vendor and supplier  account data; (c)
consulting  reports;  (d)  site  assessments;   (e)  business  plans,  financial
information,  billing information, sales figures, price lists, discounts, or any
financial information;  (f) computer passwords or codes; (g) information or data
relating  to the energy  commodity  market and  related  financial  instruments,
and/or statistical and analytical data,  including  analytical  models,  used to
forecast  changes in the pricing of energy  commodities  or the value of related
financial instruments.

     6.03 Employee  understands and agrees that prior to or immediately upon the
termination  of  Employee's   employment  with  AEP,   whether   voluntarily  or
involuntarily and regardless of the  circumstances  relating to the termination,
Employee  shall deliver and leave with AEP in good order all such  confidential,
proprietary  and/or  trade  secret  information,  in  addition  to any other AEP
property, including computer diskettes, laptops and any related equipment, which
is in Employee's possession and/or control.


                           Section VII: Miscellaneous

     7.01 The  Agreement  shall be binding  upon and inure to the benefit of AEP
and its  successors  and assigns,  and Employee and  Employee's  assigns,  legal
representatives  and heirs.  The  Agreement  shall be  assignable  by AEP to any
successor employer.

     7.02 Nothing herein shall be construed as amending the terms and conditions
of the American  Electric Power System  Retirement  Plan, the American  Electric
Power System Employees Savings Plan, the MICP, PSIP or NPIP.

     7.03 The provisions of the Agreement are severable. If any provision of the
Agreement is found by a court of competent  jurisdiction to be unreasonable  and
invalid,  that  determination  shall not affect the  enforceability of the other
provisions,  which shall be enforced in all  respects to the maximum  benefit of
AEP.

     7.04 The Agreement  shall be governed by and  construed in accordance  with
the laws of the State of Ohio. Employee and AEP agree that AEP has the exclusive
right to decide the forum  appropriate  for any  litigation  that relates to the
validity, interpretation,  performance, enforcement, breach or threatened breach
of the Agreement and/or Employee's job performance,  conduct, and/or termination
from  employment  thereunder.  In the  event  that  AEP  determines  that  it is
appropriate for any of the aforementioned issues relating to the Agreement to be
litigated in a state or federal  court located in the State of Ohio, by entering
into this Agreement Employee expressly agrees to confer personal jurisdiction of
Employee upon the common pleas,  municipal,  and federal  courts of the State of
Ohio. In the event that the Employee  initiates any legal action relating to the
aforementioned  issues,  Employee expressly agrees to bring said legal action in
the Franklin  County Court of Common Pleas,  Franklin  County,  Ohio (subject to
AEP's  right to remove  the  action to  federal  court if allowed by law) or the
United States District Court for the Southern District of Ohio, Eastern Division
in Columbus, Ohio.

     7.05 AEP shall have the right to assign this Agreement to any of its parent
and/or subsidiary  companies,  divisions,  organizations or affiliated  entities
that presently exist or which may be established in the future.

     7.06  The  Agreement  contains  the  entire  understanding  of the  Parties
relating to the subject  matter  hereof,  and AEP and Employee each  acknowledge
that they have made no agreements,  representations  or  warranties,  express or
implied, relating to the subject matter of the Agreement which are not set forth
herein or attached  hereto as an addendum.  No provision of the Agreement may be
changed,  modified  or waived  except by an  agreement  in writing and signed by
Employee and E. Linn Draper, Jr.


/s/ Robert P. Powers


/s/ E. Linn Draper, Jr.
Chairman of the Board, President and Chief Executive Officer,
American Electric Power Service Corporation



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>12
<FILENAME>x10o2.txt
<DESCRIPTION>(O)(2) AMEND SURVIVOR BENEFIT PLAN
<TEXT>

<PAGE>

                                                                EXHIBIT 10(o)(2)

                                 First Amendment
                                     to the
                        AEP System Survivor Benefit plan
               as amended and restated effective January 31, 2000


     This First  Amendment is made to the AEP System  Survivor  Benefit Plan, as
amended (the "Plan"), by American Electric Power Service Corporation, a New York
corporation,  on behalf of itself and any affiliate or subsidiary  participating
in the Plan (collectively, the "Employer").

                                    Recitals

     A.  The Plan was  adopted  effective  January  27,  1998 and most  recently
amended  and  restated   effective  January  31,  2000,  on  January  30,  2000.
Eligibility  for the Plan has generally  been made available to all employees of
the  Employer  who are in or enter  salary  grade 30 or  higher  and such  other
employees  of the  Employer  who are  approved  for  participation  by the Chief
Executive Officer of the Employer.

     B. Section 9.1 of the Plan permits the Employer to amend the Plan from time
to time as may be necessary for  administrative  purposes and legal  compliance,
provided that no amendment reduces the amount of benefit payable with respect to
a Participant  who is eligible to retire or who has retired.  Section 9.2 of the
Plan permits the Employer to terminate  the Plan in whole or in part at any time
in the Employer's sole discretion.

     C. On or about  July 31,  2002,  the  Employer  determined  to  discontinue
offering the Plan to any additional  Employees hired on or after August 1, 2002,
such that such  additional  Employees  hired  into  salary  grades 30 through 38
(other than such  Employees  hired or promoted to salary grade 38 or higher with
an  officer  title  of  SVP or  higher  with  American  Electric  Power  Service
Corporation)  shall instead  become  eligible to  participate  in the group term
coverage  offered  under the  American  Electric  Power System Group Life & AD&D
Insurance Plan.

                                    Amendment

Section 3.1 of the Plan is hereby amended in its entirety to read as follows:

     3.1 Eligibility

          All employees of the Employer who,  within the period January 27, 1997
     through July 31,  2002,  were either (a) in  management  salary grade 30 or
     higher or (b) approved for  participation by the Chief Executive Officer of
     the Employer, and who are currently enrolled in the plan, shall be eligible
     to  participate.  No  additional  employees  of the  Employer  shall become
     eligible to participate after July 31, 2002.

The  Employer  has caused  this  amendment  to be signed by its duly  authorized
officer this 11th day of November, 2002.



                               American Electric Power Service Corporation


                               By    /s/ Armando A. Pena
                               Armando A. Pena
                               Title:  Senior Vice President-Finance, Treasurer
                               and Chief Financial Officer


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>13
<FILENAME>x10q1.txt
<DESCRIPTION>(Q)(1) INCENTIVE COMP DEFERRAL PLAN
<TEXT>

<PAGE>

                                                               EXHIBIT 10(q)(1)

                         AMERICAN ELECTRIC POWER SYSTEM

                      INCENTIVE COMPENSATION DEFERRAL PLAN



                                    ARTICLE I

                           PURPOSE AND EFFECTIVE DATE

     1.1 The American Electric Power System Incentive Compensation Deferral Plan
("Plan") is established to allow Eligible Employees to elect to defer receipt of
all or a portion of their  Incentive  Compensation  until their  termination  of
employment.

     1.2 The effective date of the Plan is January 1, 2001.


                                   ARTICLE II

                                   DEFINITIONS

     2.1 "Account" means the separate memo account established and maintained by
the Company or the  recordkeeper  employed by the Company to record  Participant
deferrals of Incentive  Compensation and to record any related Investment Income
on the Fund or Funds selected by the Participant or Former Participant.

     2.2 "Base  Compensation"  means an  employee's  regular base salary or wage
including any salary or wage reductions made pursuant to sections 125 and 402(e)
of the Code and employee  elective  contributions to the American Electric Power
System Supplemental Retirement Savings Plan.

     2.3 "Code" means the Internal  Revenue Code of 1986 as amended from time to
time.

     2.4  "Committee"  means  employees  of the Company  holding  the  following
offices;  Senior Vice  President  Human  Resources,  Executive  Vice President -
Shared Services, and Executive Vice President - Finance and Analysis.

     2.5  "Company"  means  American  Electric  Power Service  Corporation,  its
subsidiaries and affiliates.

     2.6 "Disability" means the Participant's entitlement to disability benefits
under the terms of the American Electric Power System Disability Plan.

     2.7  "Eligible  Employee"  means any  employee  of the  Company  whose Base
Compensation  for the Plan Year  exceeds  $100,000  or is in salary  grade 26 or
higher.

     2.8 "Former Participant" means a Participant who has terminated  employment
or a Participant who is no longer an Eligible  Employee but who has Funds in the
Plan.

     2.9  "Fund"  means  the  investment  options  made  available  to  Eligible
Employees in the American Electric Power System Retirement Savings Plan or other
funds selected by the Committee.

     2.10 "Incentive Compensation" means incentive compensation paid pursuant to
the terms of annual and long-term  incentive  compensation plans approved by the
Committee for  inclusion in the Plan.  Incentive  Compensation  will not include
Base Compensation,  non-annual bonuses  compensation (such as but not limited to
project bonuses and sign-on bonuses), severance pay, or relocation payments

     2.11  "Investment  Income" means with respect to the Fund or Funds selected
by the Participant or Former  Participant the earning,  gains and losses derived
from the investment of deferred compensation in the Fund or Funds.

     2.12  "Participant"  means an Eligible Employee who elects to defer part or
all of his or her Incentive Compensation.

     2.13 "Plan Year" means the  calendar  year  commencing  each  January  1and
ending each December 31.

     2.14 "Retirement" means a Participant or Former  Participant's  termination
of employment after attaining age 55 and the completion of five years of service
with the Company.


                                   ARTICLE III

                                 ADMINISTRATION

     3.1 The  Committee  shall  (i)  administer  and  interpret  the  terms  and
conditions  of  the  Plan,  (ii)  establish  reasonable  procedures  with  which
Participants must comply to exercise any right established hereunder,  and (iii)
be permitted to delegate its  responsibilities or duties hereunder to any person
or entity.  The rights and duties of the  Participants and all other persons and
entities  claiming an interest  under the Plan are subject to, and  governed by,
such acts of administration,  interpretation,  procedure and delegation taken by
the Committee.

     3.2 The  Committee  may employ  agents,  attorneys,  accountants,  or other
persons and allocate or delegate to them powers,  rights,  and duties all as the
Committee  may  consider  necessary  or  advisable  to  properly  carry  out the
administration of the Plan.

     3.3 The Company shall maintain, or cause to be maintained,  records showing
the individual  balances in each Participant's  Account.  Each Participant shall
receive  quarterly  statements  setting  forth the balance of the  Participant's
Account at the end of the quarter.  The  maintenance of the Account  records and
the distribution of the quarterly  statements may be delegated to a recordkeeper
by either the Company or the Committee.


                                   ARTICLE IV

                                  PARTICIPATION

     4.1 Eligible  Employees shall become Plan Participants by making a deferral
election  on a form  prescribed  by the  Company  to  defer  part  or all of the
Eligible Employee's Incentive Compensation earned during the Plan Year but which
is paid after the end of the Plan Year.


                                    ARTICLE V

                                    DEFERRALS

     5.1 A Participant  shall make a separate  Incentive  Compensation  deferral
election for each Plan Year. If a deferral  election for a Plan Year is not made
within the time period  prescribed  by the  Company,  no portion of the Eligible
Employee's Incentive Compensation for the Plan Year shall be deferred.

     5.2 All deferred  Incentive  Compensation  shall be paid in accordance with
the distribution option selected by the Participant in accordance with the terms
of section 7.3.


                                   ARTICLE VI

                         INVESTMENT OF DEFERRED AMOUNTS

     6.1 All  deferred  incentive  compensation  shall be  invested in the Funds
selected by the  Participant.  A  Participant  may change the selected  Funds by
notifying  the  recordkeeper  retained by the  Company.  Any change in the Funds
selected by the Participant shall be implemented as soon as practicable.

     6.2 A  Participant  or Former  Participant  may elect to transfer  all or a
portion  of the  Funds  to any  other  Fund or  Funds by  giving  notice  to the
recordkeeper.  Transfers  between  Funds may be made in any whole  percentage or
dollar amounts and shall be implemented as soon as possible.

     6.3 The Funds  shall be valued  daily at their fair  market  value and each
Participant's and Former Participant's Account shall be valued daily at its fair
market value. The fair market value shall be calculated by the recordkeeper.

     6.4 The Plan is an unfunded  non-qualified  deferred  compensation plan and
amounts  credited to a  Participant's  or Former  Participant's  Account and the
investment  of the  credited  amounts  in the  Fund  or  Funds  selected  by the
Participant  or Former  Participant  are memo accounts that  represent  general,
unsecured  liabilities  of the Company  payable  exclusively  out of the general
assets of the Company.


                                   ARTICLE VII

                                  DISTRIBUTIONS

     7.1 Upon a Participant's or Former Participant's  termination of employment
with the Company for any reason other than  Retirement,  Disability or death the
Company  shall pay the  Participant  or the Former  Participant  the full amount
credited to the Participant's or Former Participant's Account. The payment shall
be made within 60 days of the Participant's or Former Participant's  termination
of employment.

     7.2 Upon a Participant's or Former Participant's  termination of employment
due to  Retirement,  Disability  or  death  benefits  shall  be paid in the form
elected by the Participant or Former  Participant that is in effect at least one
year prior to the payment or the scheduled payment to the Participant  whichever
is sooner.  The payment form elected by a  Participant  or a Former  Participant
shall  apply  to all  Incentive  Compensation  deferral  elections  made  by the
Participant or the Former Participant.

     7.3 The form of benefit payments shall be one of the following:

          1.   A single  lump sum  distribution  at the  time of  Retirement  or
               Disability or up to five years after Retirement or Disability;

          2.   Annual distributions over not less than two and not more than ten
               years   commencing   one  to  five  years  after   Retirement  or
               Disability;

     7.4  Distributions  to Participants  who are not executive  officers of the
Company shall commence as soon as practical (generally within 60 days) after the
Participant's or Former Participant's  Retirement,  Disability or death unless a
Participant has elected to defer  distributions.  Distributions  to Participants
who are executive  officers of the Company shall commence in January of the year
following the Participant's or Former  Participant's  Retirement,  Disability or
death  unless  a  Participant  has  elected  to  defer  distributions.   If  the
Participant or Former Participant elected to defer distributions for one to five
years,  distributions  shall be made on the  selected  deferral  date except for
balances of $5,000 or less as provided in section 7.5.

     7.5 If a Participant's or Former Participant's Account is $5,000 or less on
the date that such  Participant  or Former  Participant  becomes  eligible for a
distribution due to Retirement, Disability, death or the receipt of a withdrawal
request, the full value of the Account shall be distributed as a lump sum.

     7.6 If an annual distribution is selected,  the amount to be distributed in
any  one-year  shall be  determined  by  dividing  the  Participant's  or Former
Participant's   Account  by  the  number  of  years  remaining  in  the  elected
distribution  period.  The  Participant or Former  Participant  electing  annual
distributions  shall  have the  right to make  changes  in the Fund or Funds the
Account is invested in accordance with section 6.2.

     7.7  Notwithstanding  any other  provision  of this Plan a  Participant  or
Former  Participant  shall be entitled to receive,  upon written  request to the
Committee, a lump sum distribution from his or her Account of an amount equal to
or greater than 25% of the Participant's  Account as of the date of the request.
The date of the  request  shall be the date  the  Committee  or the  Committee's
representative  receives  the  request.  The lump sum  amount  to be paid to the
Participant  shall be subject to a 10% early withdrawal  penalty,  which penalty
shall  reduce  the  amount  to be  distributed  to  the  Participant  or  Former
Participant.  The Participant or Former  Participant shall forfeit the amount of
the 10%  withdrawal  penalty.  The lump sum amount  shall be paid within 60 days
after the Committee receives the withdrawal  request.  Any Participant or Former
Participant  who elects to receive a benefit  under  this  section  shall not be
eligible to participate in future Incentive  Compensation deferrals for the Plan
Year in which the request is made and for two consecutive  Plan Years thereafter
and the  Participant  may not request any  additional  withdrawals  prior to the
Participant's termination of employment.


                                  ARTICLE VIII

                                  BENEFICIARIES

     8.1 Each  Participant  or Former  Participant  shall  have the right at any
time,  to  designate  one or more  persons or an entity as a  beneficiary  (both
primary  or  secondary)  to whom  benefits  under this Plan shall be paid in the
event of a  Participant's  or  Former  Participant's  death  prior  to  complete
distribution of the Account. Each beneficiary  designation shall be in a written
form prescribed by the Committee and shall be effective only when filed with the
Committee during the Participant's or Former Participant's lifetime.

     8.2 If the designated  beneficiaries  predecease the  Participant or Former
Participant,  or if the  Participant or Former  Participant  did not designate a
beneficiary,  or if the beneficiary  designation is not valid,  the value of the
Account shall be distributed to the Participant's or Former Participant's spouse
if then living. If the spouse is not living, then the value of the Account shall
be distributed to the representative of the estate. Distributions to a surviving
spouse,  beneficiary  or  representative  of the estate shall be made as soon as
reasonable  in  accordance  with a  distribution  election made by the surviving
spouse,  beneficiary or representative of the estate. If a distribution election
is not completed  within 90 days of the  Participant's  or Former  Participant's
death, the value of the account shall be distributed in a lump sum.

                                   ARTICLE IX

                            M ISCELLANEOUS PROVISIONS

     9.1 Each  Participant  agrees that as a condition of  participation  in the
Plan,  the Company may withhold  federal,  state and local income taxes,  Social
Security taxes and Medicare taxes from any distribution  hereunder to the extent
that such taxes are then payable.

     9.2 In the event that a Participant  or  beneficiary  is unable to care for
his or her affairs  because of illness or accident,  the Company may direct that
any payment due the Participant or the beneficiary be paid to the duly appointed
legal representative of the Participant or beneficiary,  and any such payment so
made  shall  be a  complete  discharge  of the  liabilities  of the Plan and the
Company.

     9.3 The Company intends to continue the Plan  indefinitely but reserves the
right to modify the Plan from time to time, or to terminate  the Plan  entirely,
provided  that no such  modification  or  termination  shall affect or otherwise
deprive a Participant or beneficiary of any  distributions  to which they may be
entitled under the Plan.

     9.4 Nothing in the Plan shall  interfere with or limit in any way the right
of the Company to terminate any Participant's  employment at any time, or confer
upon a Participant any right to continue in the employ of the Company.

     9.5 The Plan shall be construed and  administered  according to the laws of
the State of Ohio.



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>14
<FILENAME>x10q2.txt
<DESCRIPTION>(Q)(2) AMEND INCENTIVE COMP DEFERRAL PLAN
<TEXT>
<PAGE>

                                                                EXHIBIT 10(q)(2)

                               FIRST AMENDMENT TO
                         AMERICAN ELECTRIC POWER SYSTEM
                      INCENTIVE COMPENSATION DEFERRAL PLAN

     This First Amendment is made by American Electric Power Service Corporation
(the  "Company") to the American  Electric Power System  Incentive  Compensation
Deferral Plan (the "Plan") that was made effective January 1, 2001.

     WHEREAS,  the  Company  reserved  the right to modify the Plan from time to
     time  in a  manner  that  does  not  affect  or  otherwise  deprive  a Plan
     participant or beneficiary of any distributions to which he may be entitled
     under the Plan; and

     WHEREAS, the Company desires to implement a claims procedure under the Plan
     to provide for the efficient  disposition of disputed claims that may arise
     under the terms of the Plan;

     NOW, THEREFORE,  the Company hereby amends the Plan by adding a new Article
X at the end  thereof,  effective  with respect to all claims that may be raised
under the terms of the Plan,  regardless  of whether  such claim may have arisen
before or after the date that this amendment is adopted:

                                    ARTICLE X

                                CLAIMS PROCEDURE

     Section 10.1 The  following  procedures  shall apply with respect to claims
for benefits under the Plan.

          (a) Any  Participant or beneficiary who believes he or she is entitled
     to receive a distribution under the Plan which he or she did not receive or
     that  amounts  credited to his or her Account  are  inaccurate,  may file a
     written  claim  signed  by  the  Participant,   beneficiary  or  authorized
     representative  with  the  Company's  Director-Compensation  and  Executive
     Benefits, specifying the basis for the claim. The Director-Compensation and
     Executive  Benefits  shall  provide a claimant  with written or  electronic
     notification  of its  determination  on the claim within  ninety days after
     such claim was filed; provided,  however, if the  Director-Compensation and
     Executive Benefits determines special circumstances require an extension of
     time for  processing  the claim,  the  claimant  shall  receive  within the
     initial ninety-day period a written notice of the extension for a period of
     up to ninety  days  from the end of the  initial  ninety  day  period.  The
     extension  notice shall  indicate the special  circumstances  requiring the
     extension  and the date by which the Plan  expects  to render  the  benefit
     determination.

          (b) If the  Director-Compensation  and Executive  Benefits  renders an
     adverse benefit  determination  under Section 10.1(a),  the notification to
     the claimant  shall set forth,  in a manner  calculated to be understood by
     the claimant:

               (1)  the specific reasons for the denial of the claim;

               (2)  specific  reference to the provisions of the Plan upon which
                    the denial of the claim was based;

               (3)  a  description  of any  additional  material or  information
                    necessary  for the  claimant  to  perfect  the  claim and an
                    explanation   of  why  such  material  or   information   is
                    necessary, and

               (4)  an explanation of the review procedure  specified in Section
                    10.2,  and the time limits  applicable  to such  procedures,
                    including a  statement  of the  claimant's  right to bring a
                    civil action under section 502(a) of the Employee Retirement
                    Income  Security  Act of  1974,  as  amended,  following  an
                    adverse benefit determination on review.

     Section  10.2 The  following  procedures  shall  apply with  respect to the
review on appeal of an adverse  determination  on a claim for benefits under the
Plan.

          (a) Within  sixty days after the receipt by the claimant of an adverse
     benefit  determination,  the claimant may appeal such denial by filing with
     the  Committee  a written  request  for a review of the  claim.  If such an
     appeal is filed  within  the sixty day  period,  the  Committee,  or a duly
     appointed  representative  of the Committee,  shall conduct a full and fair
     review of such  claim  that takes into  account  all  comments,  documents,
     records and other  information  submitted by the  claimant  relating to the
     claim,  without  regard  to  whether  such  information  was  submitted  or
     considered  in the initial  benefit  determination.  The claimant  shall be
     entitled  to  submit  written  comments,   documents,   records  and  other
     information relating to the claim for benefits and shall be provided,  upon
     request  and free of  charge,  reasonable  access  to,  and  copies  of all
     documents,  records and other information  relevant to the claimant's claim
     for  benefits.  If the  claimant  requests  a hearing  on the claim and the
     Committee  concludes  such a hearing  is  advisable  and  schedules  such a
     hearing,  the claimant shall have the opportunity to present the claimant's
     case in person or by an authorized representative at such hearing.

          (b)  The  claimant  shall  be  notified  of  the  Committee's  benefit
     determination  on review within sixty days after receipt of the  claimant's
     request  for  review,   unless  the  Committee   determines   that  special
     circumstances  require an extension of time for processing  the review.  If
     the Committee determines that such an extension is required, written notice
     of the  extension  shall be furnished  to the  claimant  within the initial
     sixty-day  period.  Any such  extension  shall not exceed a period of sixty
     days  from  the end of the  initial  period.  The  extension  notice  shall
     indicate the special circumstances  requiring the extension and the date by
     which the Committee expects to render the benefit determination.

          (c) The Committee  shall provide a claimant with written or electronic
     notification   of  the  Plan's  benefit   determination   on  review.   The
     determination of the Committee shall be final and binding on all interested
     parties. Any adverse benefit  determination on review shall set forth, in a
     manner calculated to be understood by the claimant:

               (1)  the specific reason(s) for the adverse determination;

               (2)  reference  to the specific  provisions  of the Plan on which
                    the determination was based;

               (3)  a statement  that the claimant is entitled to receive,  upon
                    request and free of charge, reasonable access to, and copies
                    of, all documents, records and other information relevant to
                    the claimant's claim for benefits; and

               (4)  a statement of the claimant's right to bring an action under
                    Section 502(a) of ERISA.


     American Electric Power Service Corporation has caused this First Amendment
to the American Electric Power System Incentive Compensation Deferral Plan to be
signed as of this 6th day of December, 2002.



                                American Electric Power Service Corporation


                                By  /s/ Melinda S. Ackerman
                                    Melinda S. Ackerman, Senior Vice
                                    President, Human Resources


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>15
<FILENAME>x10r.txt
<DESCRIPTION>(R) NUCLEAR PERF LT INCENTIVE COMP PLAN
<TEXT>

<PAGE>

                                                                  EXHIBIT 10(r)

                         AMERICAN ELECTRIC POWER SYSTEM
                               NUCLEAR PERFORMANCE
                       LONG TERM INCENIVE COMPENSATON PLAN

                                    ARTICLE I

                            Establishment and Purpose

     1.1 The Company  hereby  establishes  the  American  Electric  Power System
Nuclear Performance Long Term Incentive Compensation Plan effective as of August
1, 1998.

     1.2 The purpose of the American  Electric Power System Nuclear  Performance
Long Term Incentive  Compensation Plan is to enhance the performance of the D.C.
Cook Nuclear Plant and to reward those employees who efforts are instrumental to
the performance of the D.C. Cook Nuclear Plant.

                                   ARTICLE II

                                   Definitions

     As used herein the  following  words and phrases  shall have the  following
respective meanings unless the context clearly indicates otherwise.

     (a) "AEP  Stock  Unit"  means a phantom  stock  unit  equal to one share of
Common Stock for which no certificates shall be issued, which do not have voting
rights and a bookkeeping record of which shall be maintained by the Company.

     (b) "Award  Certificate"  means a  certificate  setting forth the terms and
provisions applicable to each grant of AEP Stock Units, which shall include, but
shall  not  be  limited  to,  the  number  of AEP  Stock  Units  granted  to the
Participant,  the  Performance  Objectives,  and the  length of the  Performance
Period.

     (c) "Committee" means the individuals  holding the following offices within
the  Company;  Chairman of the Board,  President  and Chief  Executive  Officer;
Executive Vice President-Financial  Services; Executive Vice President-Corporate
Services;   Senior   Vice   President-Nuclear   Generation;   and  Senior   Vice
President-Human Resources.

     (d)  "Common  Stock"  means the common  stock of  American  Electric  Power
Company, Inc., a New York corporation and any successor thereto.

     (e) "Company" means American Electric Power Service Corporation, a New York
corporation, and any of its subsidiaries and affiliates.

     (f) "Disability"  means a total and permanent  disability as defined in the
American Electric Power System Retirement Plan as amended from time to time.

     (g) "Fair Market Value" means the closing sale price of the Common Stock as
published in the Wall Street  Journal  report of the New York Stock  Exchange on
the date in question,  or if the New York Stock Exchange is Closed on such date,
then the first day prior theret6 on which the Common Stock was so traded.

     (h) "Participant" means any full-time employee of the Company, who has been
selected to participate in the Plan for a stipulated Performance Period.

     (i)  "Performance  Objectives"  means the annual  Plan Year  objectives  or
multiple Plan Year  objectives  established  by the Company for the operation of
the D. C. Cook Nuclear Plant

     (j) "Performance  Period" means the Plan Year or Plan Years  established by
the  Company  over  which the  Performance  Objectives  will be  measured.  If a
Performance  Period  is for two or more Plan  Years,  the  attained  Performance
Objectives for each Plan Year within the Performance Period shall be averaged to
determine the attained Performance Objective for the Performance Period.

     (k) "Plan" means the American  Electric  Power System  Nuclear  Performance
Long Term Incentive Compensation Plan.

     (l) "Plan Year" means the calendar year  commencing on January 1 and ending
on December 31.

     (m)  "Retirement"  means a termination of employment  after the Participant
attains age 55 and has completed five years of service.


                                   ARTICLE III

                                 Administration

     3.1 The Committee  shall  administer the Plan. The Committee shall have the
authority to interpret  the Plan and to  prescribe,  amend and rescind rules and
regulations   relating  to  the   administration  of  the  Plan,  and  all  such
interpretation,  rules and  regulation  shall be  conclusive  and binding on all
Participants.

     3.2 The  Committee  may employ  agents,  attorneys,  accountants,  or other
person and  allocate or delegate to them powers,  rights,  and duties all as the
Committee  may  consider  necessary  or  advisable  to  properly  carry  out the
administration of the Plan.

     3.3 If  the  Committee  determines  that  the  occurrence  of  any  merger,
reclassification, consolidation, recapitalization, stock dividend or stock split
requires an  adjustment  in order to preserve  the benefits  intended  under the
Plan,  then the Committee may, in its discretion,  make equitable  proportionate
adjustments in individual AEP Stock Unit grants.


                                    ARTICLE V

                          Eligibility and Participation

     4.1  Eligibility for  participation  in the Plan shall be limited to senior
officers  who,  in  the  opinion  of  the  Committee,   have  the  capacity  for
contributing in a substantial measure to the successful  performance of the D.C.
Cook Nuclear Plant.

     4.2 At the beginning of each Plan Year, the Committee shall identify which,
if any,  Participants shall receive a grant of AEP Stock Units for a Performance
Period that  commences at the start of the Plan Year. At the sole  discretion of
the  Committee an  individual  may become a  Participant  in the Plan after tile
start of a Plan Year or a Performance  Period and shall receive  prorated grants
of AEP Stock  Units.  As soon as  practicable  following  the  selection  of the
Participants,  the  Committee  shall  provide  each  Participant  with an  Award
Certificate.


                                    ARTICLE V

                            Grants of AEP Stock Units

     5.1 Grants of AEP Stock Units:

          (a) AEP Stock Units may be granted to Participants as of the first day
     of each Performance Period;  however,  grants do not necessarily have to be
     made to Participant on an annual basis. The number of AEP Stock Units to be
     granted to each  Participant  shall be  determined  by the Committee in its
     sole discretion.

          (b) If an individual  becomes a  Participant  after the first day of a
     Plan Year or Performance Period, the Committee may grant AEP Stock Units to
     tile Participant as follows:  (i) AEP Stock Units for a Performance  Period
     that ends in tile Plan Year in which tile individual becomes a Participant;
     (ii) AEP Stock  Units for a  Performance  Period that ends in the Plan Year
     immediately  following  the Plan  Year in which  the  individual  becomes a
     Participant;  and (iii) AEP Stock Units for a Performance  Period that ends
     in the second full Plan Year after the  individual  becomes a  Participant.
     The number of AEP Stock  Units  granted  for each such  Performance  Period
     shall be determined by the Committee in its sole discretion.

          (c) The value of the AEP Stock Units granted to a  Participant  at the
     commencement  of a Plan Year or  Performance  Period as provided in section
     5.1(a) or after the  commencement  of a Plan Year or Performance  Period as
     provided in section  5.1(b) shall be calculated on the basis of the average
     of the Fair Market  Value of the Common  Stock for the last 20 trading days
     prior to the start of a Plan Year or Performance Period.

     5.2 During the  Performance  Period,  Participants  will be  credited  with
dividends,  equivalent  in value to those  declared  and paid on  shares  of the
Common Stock,  on all AEP Stock Units granted to them.  These  dividends will be
regarded as having been  reinvested in AEP Stock Units on the date of the Common
Stock dividend payments based on the then Fair Market Value of the Common Stock,
thereby increasing the number of AEP Stock Units Held by the Participant.

     5.3  The  Committee  shall  establish   Performance  Periods  in  its  sole
discretion. The minimum Performance Period shall be for one year and the maximum
Performance Period shall be for three years in length.


                                   ARTICLE VI

                            Determination and Payment

     6.1 The number of AEP Stock Units earned by a Participant for a Performance
Period shall be determined by multiplying  the number of AEP Stock Units held by
the Participant at the end of the Performance  Period by a factor based upon the
Performance Objectives.

     6.2 The payment of earned AEP Stock  Units shall be made in cash.  The cash
payment shall be calculated on the basis of the average of the Fair Market Value
of the Common Stock for the last 20 trading days of the  Performance  Period for
which the AEP Stock Units were earned.

     6.3  At  least  one  year  prior  to  the  end  of  a  Performance  Period,
Participants  may make an election to defer the cash payment of earned ABP Stock
Units for one or more  years.  However,  if the  Participant's  deferral  period
extends beyond the  Participant's  employment  termination date, cash payment of
the earned  AEP Stock  Units must  commence  no later than five years  after the
Participant's termination of employment. Deferred AEP Stock Units shall continue
to be credited with dividends during the deferral period and the dividends shall
be reinvested in additional AEP Stock Units as provided in Section 5.2. The cash
payment of the deferred AEP Stock Units shall be  calculated on the basis of the
average of the Fair  Market  Value of the  Common  Stock for the last 20 trading
days prior to the date the Participant's deferral period terminates.


                                   ARTICLE VII

                            Termination of Employment

     7.1 In the event of a Participant's  termination of employment prior to the
end of a Performance  Period, but after the first six months of such Performance
period,  by  reason  of  the  Participant's  death,   Disability  Retirement  or
involuntary  termination  other then for cause, the Participant will be eligible
to earn prorated AEP Stock Units for each such Performance  Period which has not
yet ended,  determined pursuant to Section 6.1 for such period and the number of
days of participation during such Performance Period.

     7.2 In the event a Participant's  employment is terminated prior to the end
of a Performance Period for reasons other than death, Disability,  Retirement or
involuntary  termination  other than for cause,  all rights to any  unearned AEP
Stock Units under the Nuclear Performance Plan shall be forfeited.

     7.3 In the event a  Participant  dies prior to the complete  payment of the
Participant's  award, the amount owning to the Participant  shall be paid to the
Participant's  spouse if the spouse is then living.  If the  Participant  is not
married at the time of death, the amount owing to the Participant  shall be paid
to the Participant's estate.

     7.4 In the event American Electric Power Company,  Inc., or the Company, or
Indiana  Michigan  Power  Company  sells or otherwise  disposes of the D.C. Cook
Nuclear  Plant and the acquirer of the D.C. Cook Nuclear Plant does not continue
this  Plan,  the Plan shall be deemed to have  terminated  as of the date of the
sale  or  disposition  and the AEP  Stock  Units  awarded  and  credited  to the
Participants  as of the date of sale or  disposition  shall become fully vested.
The  value  of each AEP  Stock  Unit  shall be paid in cash to the  Participants
within 60 days of the date of sale or  disposition  assuming that as of the date
of sale or disposition  the Performance  Measure was attained.  The cash payment
shall be  calculated on the basis of the average of the Fair Market Value of the
Common 8tock for the last 20 trading days immediately  prior to the date of sale
or  disposition.  If the acquirer of the D.C. Cook Nuclear Plant  continues this
Plan, American Electric Power Company,  Inc., or the Company or Indiana Michigan
Power  Company will not be liable or  obligated to make any payments  under this
Plan.


                                  ARTICLE VIII

                            Amendment or Termination

     8.1 The  Committee  shall  have the  right,  authority  and power to alter,
amend, modify, revoke or terminate the Plan.

     8.2 No amendment or  termination  of the Plan shall  directly or indirectly
deprive any current or former  Participant of all or any portion of any benefits
earned up to the date of the amendment or termination of the Plan.


                                   ARTICLE IX

                                Change In Control

     9.1  Notwithstanding  any  provisions  of this Plan to the  contrary,  if a
Change in Control of the Company  occurs,  all AEP Stock Unit grants awarded and
credited to the  Participants  shall be deemed to be fully earned as of the date
of the Change in Control. The determination of the AEP Stock Units shall be made
as of the last day before the Change in  Control.  Payments  of AEP Stock  Units
shall be made in cash within three months after the Change in Control.  The cash
payment shall be calculated on the basis of the average of the Fair Market Value
of the Common Stock for the last 20 trading days immediately proceeding the date
of the Change In Control.

     9.2 For  purposes  of this  Article IX, the term  "Company"  shall mean the
American  Electric  Power  Company,  Inc.,  a  New  York  corporation  and  it's
subsidiaries.  All references to the term Company in other Articles of this Plan
shall have the meaning as provided in Article II(e).

     9.3 A "Change in Control" of the Company  shall be deemed to have  occurred
if (a) any  "person" or "group"  (as such terms are used in  Sections  13(d) and
14(d) of the Securities  Exchange Act of 1934  ("Exchange  Act")),  other than a
trustee or other fiduciary holding  securities under an employee benefit plan of
the Company,  becomes the "beneficial owner" (as defined in Rule l3d-3 under the
Exchange  Act),  directly  or  indirectly,  of more than 25  percent of the then
outstanding voting stock of the Company; (b)during any period of two consecutive
years,  individuals  who at the beginning of such period  constitute  the Board,
together with any new Directors  whose  election or nomination  for election was
approved by a vote of at least  two-thirds of the Directors then still in office
who were either  Directors at the  beginning of the period or whose  election or
nomination  for election  was  previously  so approved;  cease for any reason to
constitute at least a majority of the Board;  or (e) the Company's  shareholders
approve a merger or  consolidation  of the Company  with any other  corporation,
other than a merger or consolidation which would result in the voting securities
of the Company  outstanding  immediately  prior thereto  continuing to represent
(either by remaining outstanding or by being converted into voting securities of
the surviving  entity) at least 75 percent of the total voting power represented
by the voting  securities of the Company or such  surviving  entity  outstanding
immediately after such merger or  consolidation;  or (d) the shareholders of the
Company approve a plan of complete  liquidation of the Company,  or an agreement
for the date or  disposition  by the Company (in one  transaction or a series of
transactions) of all or substantially all of the Company's assets.

     Notwithstanding  the foregoing,  a Change in Control shall not be deemed to
occur as a result of any event  described in (a) or (c) above,  if Directors who
were a majority of the members of the Board prior to such event and who continue
to serve as  Directors  after  such  event  determine  that the event  shall not
constitute a Change in Control

     For purposes of this Section 9.3, "Board" shall mean the Board of Directors
of  American  Electric  Power  Company,  Inc.  and  `"Directors"  shall  mean an
individual who is a member of the Board.


                                    ARTICLE X

                                  Miscellaneous

     10.1  Nothing  in this Plan  shall  interfere  with or limit in any way the
right of the Company to terminate any Participant's  employment at any time, nor
confer upon a Participant any right to continue in the employ of the Company.

     10.2 In the event the Committee  shall find that a Participant is unable to
care for his or her affairs  because of illness or accident,  the  Committee may
direct that any payment due the  Participant be paid to the duly appointed legal
representative  of the  Participant,  and any such  payment  so made  shall be a
complete discharge of the liabilities of the Plan.

     10.3 The Plan shall be construed and administered  according to the laws of
the State of Ohio.





</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>16
<FILENAME>x10s.txt
<DESCRIPTION>(S) NUCLEAR RETENTION PLAN
<TEXT>

<PAGE>

                                                                  EXHIBIT 10(s)

                             NUCLEAR KEY CONTRIBUTOR
                                 RETENTION PLAN


                                    ARTICLE I

                            Establishment and Purpose

     1.1 The Company hereby  establishes the Nuclear Key  Contributor  Retention
Plan effective as of May 1, 2000.

     1.2 The purpose of the Nuclear Key Contributor  Retention Plan is to retain
the services of key employees who are very important to the ongoing  performance
of the Company and of the D. C. Cook Nuclear Plant.


                                   ARTICLE II

                                   Definitions

     As used herein the  following  words and phrases  shall have the  following
respective meanings unless the context clearly indicates otherwise.

          (a)  "Account"  means the  separate  memo account  established  by the
     Company for each Participant.

          (b)  "Award  Letter"  means a  letter  setting  forth  the  terms  and
     conditions applicable to the establishment of a Participant's Account which
     shall  include,  but shall not be  limited  to, the  amount  credited  to a
     Participant's Account and the time period over which the amount credited to
     the Account shall vest.

          (c)  "Cause"  means and shall  include,  but is not  limited  to,  the
     Participant's  theft or destruction of Company property,  the Participant's
     willful  breach or habitual  neglect of the duties that the  Participant is
     required to perform,  or the  Participant's  behavior or actions  which are
     illegal and or unethical.

          (d) "Committee"  means the individuals  holding the following  offices
     within the Company;  Chairman of the Board,  President and Chief  Executive
     Officer;  Executive  Vice  President-Financial   Services;  Executive  Vice
     President-Corporate Services; and Senior Vice President-Human Resources.

          (e)  "Company"  means,  except as provided in Article 11, the American
     Electric Power Service Corporation, a New York corporation,  and any of its
     subsidiaries and affiliates.

          (f)  "Comparable  Job" means a job at the same pay grade with the same
     or equivalent level of responsibility.

          (g) "Disability" means a total and permanent  disability as defined in
     the American  Electric Power System Retirement Plan as amended from time to
     time.

          (h) "Fund" means the investment options made available to participants
     in the Supplemental Savings Plan.

          (i) "Investment Income" means with respect to a Participant's  Account
     the earnings,  gains and losses  derived from the  investment of the amount
     credited to a Participant's Account in a Fund or Funds.

          (j) "Participant" means any full-time employee of the Company, who has
     been selected to participate in the Plan.

          (k) "Plan" means the Nuclear Key Contributor Retention Plan.

          (l)   "Retirement"   means  a  termination  of  employment  after  the
     Participant attains age 55 and has completed five years of service.

          (m)  "Supplemental  Savings  Plan" means the American  Electric  Power
     System  Supplemental  Savings Plan, a non-qualified  deferred  compensation
     plan sponsored by the Company, as amended from time to time.


                                   ARTICLE III

                                 Administration

     3.1 The Committee  shall  administer the Plan. The Committee shall have the
authority to interpret  the Plan and to  prescribe,  amend and rescind rules and
regulations   relating  to  the   administration  of  the  Plan,  and  all  such
interpretation,  rules and  regulation  shall be  conclusive  and binding on all
Participants.

     3.2 The  Committee  may employ  agents,  attorneys,  accountants,  or other
persons and allocate or delegate to them powers,  rights,  and duties all as the
Committee  may  consider  necessary  or  advisable  to  properly  carry  out the
administration of the Plan.


                                   ARTICLE IV

                          Eligibility and Participation

     4.1 Eligibility for participation in the Plan shall be limited to employees
who, in the opinion of the Committee,  have the capacity for  contributing  in a
substantial  measure to the  successful  performance  of the D.C.  Cook  Nuclear
Plant.  At the  sole  discretion  of the  Committee  an  employee  may  become a
Participant in the Plan on or after May 1, 2000.

     4.2  The  Committee  shall  determine  the  amount  to  be  credited  to  a
Participant's  Account  and  the  credited  amount  shall  be  specified  in the
Participant's  Award Letter.  As soon as practicable  following a  Participant's
selection, the Committee shall provide the Participant with an Award Letter.


                                    ARTICLE V

                         Investment of Credited Amounts

     5.1 The  initial  contribution  by the Company to a  Participant's  Account
shall be  invested in the AEP Fixed  Income  Fund and shall  remain in that Fund
until such time that the Participant  elects to invest the initial  contribution
in a different Fund or Funds.  The  Participant may change the selected Funds by
notifying the Company or the recordkeeper retained by the Company. Any change in
the  Funds  selected  by  the  Participant  shall  be  implemented  as  soon  as
practicable.

     5.2 A  Participant  may elect to  transfer  all or a portion  of the amount
credited to the  Participant's  Account from any Fund or Funds to any other Fund
or Funds by giving  notice to the  Company or the  recordkeeper  retained by the
Company.  Transfers  between Funds may be made in any whole percentage or dollar
amounts and shall be implemented as soon as possible.

     5.3 The Funds  shall be valued  daily at their fair  market  value and each
Participant's  Account shall be valued daily at its fair market value.  The fair
market value  calculation  for a  Participant's  Account shall be made after all
Investment Income and Fund transfers for the day are recorded.

     5.4 If a Participant receives a payment of a portion of the amount credited
to the Participant's Account in accordance with sections 7.1 or 7.2, the payment
shall be taken  pro-rata  from  the  Funds  the  Participant's  Account  is then
invested in.

     5.4 The Plan is an unfunded  non-qualified  deferred  compensation plan and
therefore the amounts credited to a Participant's  Account and the Participant's
investment  of the  credited  amounts  in the  Fund  or  Funds  selected  by the
Participant are memo accounts that represent general,  unsecured  liabilities of
the Company payable exclusively out of the general assets of the Company.


                                   ARTICLE VI

                                     Vesting

     6.1 Except as provided in Section 6.2, a  Participant's  Account shall vest
after a set term as specified in the Award Letter.  A  Participant  will forfeit
any unvested portion of the Participant's  Account if the Participant  voluntary
resigns before  Retirement or Disability or if the Participant is terminated for
Cause.

     6.2  The  portion  of the  Participant's  Account  that  is not  vested  in
accordance with Section 6.1 shall become fully vested:

          (a) Upon the Retirement of the Participant,

          (b) Upon the Participant's Disability,

          (c) If the Company ceases or restructures  its nuclear  operations and
     the Participant's position with the Company is terminated, or

          (d)  If  there  is a  change  in  control  of  the  Company's  nuclear
     operations  such  that the  Company  does not have  primary  management  or
     operation responsibility for the D.C. Cook Nuclear Plant, or

          (e) If the  Company  is part of a  consortium  or  joint  venture  the
     purpose of which is to operate several nuclear electric  generation  plants
     and the Company does not have a controlling  interest in the  consortium or
     joint venture, and

          (f) If as a result of a  transaction  described in (c), (b) or (d) the
     Participant's  position  is  terminated  and the  Company  does not offer a
     Comparable Job to the Participant.


                                   ARTICLE VII

                            Determination and Payment

     7.1 The  Participant  shall  receive  a lump sum cash  distribution  of the
vested  portion of the  Participant's  Account within ten days after the vesting
date  specified  in the Award  Letter,  unless the  Participant  elects to defer
payment  of the vested  portion of the  Participant's  Account  as  provided  in
Section 7.2. The lump sum cash payment  shall be  calculated on the basis of the
market value of the Fund or Funds the Participant's Account is invested in as of
the day the Participant's Account becomes vested.

     7.2 Within sixty days of becoming a Participant,  a Participant may make an
election  to defer the cash  payment of the  amounts  credited in the Account as
they become  vested.  The vested  amounts may be deferred for one or more years.
However,  if the Participant's  deferral period extends beyond the Participant's
Retirement date, the payment of the deferred amounts must commence no later than
one year after the Participant's date of Retirement.  Upon the expiration of the
deferral  period,  the  deferred  amounts  shall be paid in a lump sum or over a
period of years,  not to exceed ten years,  as elected by the  Participant.  The
deferred  amounts shall continue to be invested in the Fund or Funds as selected
by the  Participant  as provided in Article V. The cash  payment of the deferred
amounts  shall be  calculated  on the basis of the  market  value of the Fund or
Funds the deferred  amounts are invested in as of the date the deferred  amounts
are to be paid to the Participant.

     7.3 If a Participant  voluntarily  terminates  employment  with the Company
prior to Retirement or Disability or if the  Participant's  employment  with the
Company is  terminated  for Cause,  any election the  Participant  may have made
pursuant to Section 7.2 shall be null and void. Upon a voluntary  termination or
a termination for cause, the vested portion of the  Participant's  account shall
be paid as a lump sum within 10 days of the Participant's termination.


                                  ARTICLE VIII

                                      Death

     8.1 In the event a  Participant  dies prior to the complete  payment of the
Participant's vested Account, the amount owning to the Participant shall be paid
to the Participant's  spouse if the spouse is then living. If the Participant is
not married at the time of death,  the amount owing to the Participant  shall be
paid to the Participant's estate.


                                   Article IX

                             Taxes and Tax Treatment

     9.1 The Company  shall  withhold  federal,  state and local  income  taxes,
Social Security taxes and Medicare Taxes from any distribution  hereunder to the
extent that such taxes are then payable.


                                    ARTICLE X

                            Amendment or Termination

     10.1 The  Committee  shall  have the right,  authority  and power to alter,
amend, modify, revoke or terminate the Plan.

     10.2 No amendment or  termination  of the Plan shall directly or indirectly
deprive any current or former  Participant of all or any portion of any benefits
earned up to the date of the amendment or termination of the Plan.


                                   ARTICLE XI

                                Change in Control

     11.1  Notwithstanding  any  provisions of this Plan to the  contrary,  if a
Change in Control of the Company occurs, all amounts credited to a Participant's
Account and not then vested shall be deemed to be fully vested as of the date of
the  Change in  Control.  Payment of the amount  credited  to the  Participant's
Account  shall be made in cash within  three months after the Change in Control.
The cash payment  shall be  calculated  on the basis of the fair market value of
the Funds the Participant's  Account is invested in as of the date of the Change
in Control.

     11.2 For  purpose of this  Article  XI, the term  "Company"  shall mean the
American  Electric  Power  Company,  Inc.,  a  New  York  corporation  and  it's
subsidiaries.  All references to the term Company in other Articles of this Plan
shall have the meaning as provided in Article II (e).

     11.3 A "Change in Control" of the Company  shall be deemed to have occurred
if (a) any  "person" or "group"  (as such terms are used in  Sections  13(d) and
14(d) of the Securities  Exchange Act of 1934  ("Exchange  Act")),  other than a
trustee or other fiduciary holding  securities under an employee benefit plan of
the Company,  becomes the "beneficial owner" (as defined in Rule 13d-3 under the
Exchange  Act),  directly  or  indirectly,  or more than 25  percent of the then
outstanding  voting  stock  of  the  Company;  (b)  during  any  period  of  two
consecutive  years,  individuals who at the beginning of such period  constitute
the Board,  together with any new  Directors  whose  election or nomination  for
election was approved by a vote of at least  two-thirds  of the  Directors  then
still in office who were  either  Directors  at the  beginning  of the period or
whose election or nomination for election was previously so approved,  cease for
any reason to constitute at least a majority of the Board;  or (c) the Company's
shareholders  approve a merger or  consolidation  of the Company  with any other
corporation,  other than a merger or  consolidation  which  would  result in the
voting  securities  of  the  Company   outstanding   immediately  prior  thereto
continuing to represent  (either by remaining  outstanding or by being converted
into voting securities of the surviving entity) at least 75 percent of the total
voting  power  represented  by the  voting  securities  of the  Company  or such
surviving entity outstanding immediately after such merger or consolidation;  or
(d) the  shareholders of the Company  approve a plan of complete  liquidation of
the Company,  or an agreement for the date or disposition by the Company (in one
transaction  or a series of  transactions)  of all or  substantially  all of the
Company's assets.

     Notwithstanding  the foregoing,  a Change in Control shall not be deemed to
occur as a result of any event  described in (a) or (c) above,  if Directors who
were a majority of the members of the Board prior to such event and who continue
to serve as  Directors  after  such  event  determine  that the event  shall not
constitute a Change in Control.

     For  purposes  of this  Section  11.3,  "Board"  shall  mean  the  Board of
Directors of American Electric Power Company,  Inc. and "Director" shall mean an
individual who is a member of the Board.


                                   ARTICLE XII

                                  Miscellaneous

     12.1  Nothing  in this Plan  shall  interfere  with or limit in any way the
right of the Company to terminate any Participant's  employment at any time, nor
confer upon a Participant any right to continue in the employ of the Company.

     12.2 In the event the Committee  shall find that a Participant is unable to
care for his or her affairs  because of illness or accident,  the  Committee may
direct that any payment due the  Participant be paid to the duly appointed legal
representative  of the  Participant,  and any such  payment  so made  shall be a
complete discharge of the liabilities of the Plan.

     12.3 The Plan shall be construed and administered  according to the laws of
the State of Ohio.



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12
<SEQUENCE>17
<FILENAME>x12aep.txt
<TEXT>
<PAGE>
<TABLE>
                                                                                                  EXHIBIT 12
                     AMERICAN ELECTRIC POWER COMPANY, INC.
         Computation of Consolidated Ratio of Earnings to Fixed Charges
                        (in millions except ratio data)

<CAPTION>
                                                                      Year Ended December 31,
                                                           1998       1999       2000      2001       2002
<S>                                                       <C>        <C>       <C>        <C>        <C>
Fixed Charges:
  Interest on Long-term Debt . . . . . . . . . . . .      $  569     $  618    $  618     $  605     $  642
  Interest on Short-term Debt. . . . . . . . . . . .         134        149       259        148         67
  Miscellaneous Interest Charges . . . . . . . . . .          77         77       161        132        106
  Estimated Interest Element in Lease Rentals. . . .         222        212       223        222        229
  Preferred Stock Dividends. . . . . . . . . . . . .          29         28        32         15         84
        Total Fixed Charges. . . . . . . . . . . . .      $1,031     $1,084    $1,293     $1,122     $1,128

Earnings:
  Income Before Income Taxes . . . . . . . . . . . .      $1,357     $1,333    $  782     $1,463     $  235
  Plus Fixed Charges (as above). . . . . . . . . . .       1,031      1,084     1,293      1,122      1,128
  Less Undistributed Earnings in Equity Investments.          42         46        46         28         12
       Total Earnings. . . . . . . . . . . . . . . .      $2,346     $2,371    $2,029     $2,557     $1,351

Ratio of Earnings to Fixed Charges . . . . . . . . .        2.27       2.18      1.56       2.27       1.19
</TABLE>


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>18
<FILENAME>x13.txt
<DESCRIPTION>2002 ANNUAL REPORT
<TEXT>
                              2002 Annual Reports


                     American Electric Power Company, Inc.
                             AEP Generating Company
                           AEP Texas Central Company
                            AEP Texas North Company
                           Appalachian Power Company
                        Columbus Southern Power Company
                         Indiana Michigan Power Company
                             Kentucky Power Company
                               Ohio Power Company
                       Public Service Company of Oklahoma
                      Southwestern Electric Power Company

                        Audited Financial Statements and
                      Management's Discussion and Analysis





<PAGE>
<TABLE>
<CAPTION>


                                    Contents

                                                                                                       Page
<S>                                                                                                   <C>
Glossary of Terms                                                                                         i

Forward Looking Information                                                                              iv

AEP Common Stock and Dividend Information                                                                 v

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 Operations                                                         A-12
         Consolidated Balance Sheets                                                                   A-13
         Consolidated Statements of Cash Flows                                                         A-15
         Consolidated Statements of Common Shareholders' Equity and
           Comprehensive Income                                                                        A-16
         Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries                          A-17
         Schedule of Consolidated Long-term Debt of Subsidiaries                                       A-18
         Index to Combined Notes to Consolidated Financial Statements                                  A-19
         Independent Auditors' Report                                                                  A-20
         Management's Responsibility                                                                   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 Combined Notes to Financial Statements                                                B-8
         Independent Auditors' Report                                                                   B-9

AEP Texas Central 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
           Comprehensive Income                                                                         C-6
         Consolidated Statements of Retained Earnings                                                   C-7
         Consolidated Balance Sheets                                                                    C-8
         Consolidated Statements of Cash Flows                                                         C-10
         Consolidated Statements of Capitalization                                                     C-11
         Schedule of Long-term Debt                                                                    C-12
         Index to Combined Notes to Consolidated Financial Statements                                  C-13
         Independent Auditors' Report                                                                  C-14

AEP Texas North Company
         Selected Financial Data                                                                        D-1
         Management's Narrative Analysis of Results of Operations                                       D-2
         Statements of Operations and Statements of Comprehensive Income                                D-6
         Statements of Retained Earnings                                                                D-7
         Balance Sheets                                                                                 D-8
         Statements of Cash Flows                                                                      D-10
         Statements of Capitalization                                                                  D-11
         Schedule of Long-term Debt                                                                    D-12
         Index to Combined Notes to Financial Statements                                               D-13
         Independent Auditors' Report                                                                  D-14

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

Columbus Southern Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           F-1
         Management's Narrative Analysis of Results of Operations                                       F-2
         Consolidated Statements of Income and
            Consolidated Statements of Comprehensive Income                                             F-6
         Consolidated Statements of Retained Earnings                                                   F-7
         Consolidated Balance Sheets                                                                    F-8
         Consolidated Statements of Cash Flows                                                         F-10
         Consolidated Statements of Capitalization                                                     F-11
         Schedule of Long-term Debt                                                                    F-12
         Index to Combined Notes to Consolidated Financial Statements                                  F-13
         Independent Auditors' Report                                                                  F-14

Indiana Michigan Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           G-1
         Management's Discussion and Analysis of Results of Operations                                  G-2
         Consolidated Statements of Income and Consolidated Statements of
             Comprehensive Income                                                                       G-7
         Consolidated Statements of Retained Earnings                                                   G-8
         Consolidated Balance Sheets                                                                    G-9
         Consolidated Statements of Cash Flows                                                         G-11
         Consolidated Statements of Capitalization                                                     G-12
         Schedule of Long-term Debt                                                                    G-13
         Index to Combined Notes to Consolidated Financial Statements                                  G-14
         Independent Auditors' Report                                                                  G-15

Kentucky Power Company
         Selected Financial Data                                                                        H-1
         Management's Narrative Analysis of Results of Operations                                       H-2
         Statements of Income, Statements of Comprehensive Income
             and Statements of Retained Earnings                                                        H-6
         Balance Sheets                                                                                 H-7
         Statements of Cash Flows                                                                       H-9
         Statements of Capitalization                                                                  H-10
         Schedule of Long-term Debt                                                                    H-11
         Index to Combined Notes to Financial Statements                                               H-12
         Independent Auditors' Report                                                                  H-13

Ohio Power Company
         Selected Financial Data                                                                        I-1
         Management's Discussion and Analysis of Results of Operations                                  I-2
         Statements of Income and Statements of Comprehensive Income                                    I-7
         Statements of Retained Earnings                                                                I-8
         Balance Sheets                                                                                 I-9
         Statements of Cash Flows                                                                      I-11
         Statements of Capitalization                                                                  I-12
         Schedule of Long-term Debt                                                                    I-13
         Index to Combined Notes to Financial Statements                                               I-14
         Independent Auditors' Report                                                                  I-15

Public Service Company of Oklahoma and Subsidiary
         Selected Consolidated Financial Data                                                           J-1
         Management's Narrative Analysis of Results of Operations                                       J-2
         Consolidated Statements of Income and
            Consolidated Statements of Comprehensive Income                                             J-5
         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 Combined Notes to Consolidated Financial Statements                                  J-12
         Independent Auditors' Report                                                                  J-13

Southwestern Electric Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           K-1
         Management's Discussion and Analysis of Results of Operations                                  K-2
         Consolidated Statements of Income and
            Consolidated Statements of Comprehensive Income                                             K-6
         Consolidated Statements of Retained Earnings                                                   K-7
         Consolidated Balance Sheets                                                                    K-8
         Consolidated Statements of Cash Flows                                                         K-10
         Consolidated Statements of Capitalization                                                     K-11
         Schedule of Long-term Debt                                                                    K-12
         Index to Combined Notes to Consolidated Financial Statements                                  K-13
         Independent Auditors' Report                                                                  K-14

Combined Notes to Financial Statements                                                                  L-1

Registrants' Combined Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters                                                        M-1

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



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

               Term                                Meaning
<S>                                <C>
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 consolidated subsidiaries.
AEP Credit.........................AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East 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 companies.................PSO, SWEPCo, TCC and TNC.
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 (the FERC overturned earlier approvals of this RTO in December 2001).
Amos 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   [legal   name   changed   to   AEP   Texas   Central
                                            Company (TCC) effective December 2002].  See TCC.
CSPCo..............................Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal
                                            name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW 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.
FMB ...............................First Mortgage Bond.
FUCOs..............................Foreign Utility Companies.
GAAP...............................Generally Accepted Accounting Principles.
I&M................................Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR................................Interchange Cost Reconstruction.
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.
MISO...............................Midwest Independent System Operator (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.
MTM................................Mark-to-Market.
MTN................................Medium Term Notes.
MW.................................Megawatt.
MWH................................Megawatthour.
NEIL...............................Nuclear Electric Insurance Limited.
NOx................................Nitrogen oxide.
NOx Rule...........................A final rule issued by Federal EPA which requires NOx reductions in 22 eastern states including
                                            seven of the states in which AEP companies operate.
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, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
                                            TCC and TNC.
REP................................Retail Electric Provider.
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 Types of Regulation.
                                            ---------------------------------------------------------
SFAS 101...........................Statement of Financial Accounting Standards No. 101,
                                            Accounting for the Discontinuance of Application of Statement 71.
                                            ----------------------------------------------------------------
SFAS 133...........................Statement of Financial Accounting Standards No. 133,
                                            Accounting for Derivative Instruments and Hedging Activities.
                                            ------------------------------------------------------------
SNF................................Spent Nuclear Fuel.
SPP................................Southwest Power Pool.
STP................................South Texas Project Nuclear Generating Plant, owned 25.2% by AEP Texas Central 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 TCC.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
                                            Power and Light Company (CPL)].
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.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
                                            Utilities Company (WTU)].
Travis District Court..............State District Court of Travis County, Texas.
TVA ...............................Tennessee Valley Authority.
U.K................................The United Kingdom.
UN.................................Unsecured Note.
VaR................................Value at Risk, a method to quantify risk exposure.
Virginia SCC.......................Virginia State Corporation Commission.
WV.................................West Virginia.
WVPSC..............................Public Service Commission of West Virginia.
WPCo...............................Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................West Texas Utilities Company [legal name changed to AEP Texas North Company  (TNC) effective
                                            December 2002].  See TNC.
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.
</TABLE>


<PAGE>


FORWARD LOOKING INFORMATION



<PAGE>



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

o        Electric load and customer growth.
o        Abnormal weather conditions.
o        Available sources and costs of fuels.
o        Availability of generating capacity.
o        The speed and degree to which competition is introduced to our service
         territories.
o        The ability to recover stranded costs in connection with
         possible/proposed deregulation.
o        New legislation and government regulation.
o        Oversight and/or investigation of the energy sector or its
         participants.
o        The ability of AEP to successfully control its costs.
o        The success of acquiring new business ventures and disposing of
         existing investments that no longer match our corporate profile.
o        International and country-specific developments affecting AEP's foreign
         investments including the disposition of any current foreign
         investments and potential additional foreign investments.
o        The economic climate and growth in AEP's service territory and
         changes in market demand and demographic patterns.
o        Inflationary trends.
o        Electricity and gas market prices.
o        Interest rates.
o        Liquidity in the banking, capital and wholesale power markets.
o        Actions of rating agencies.
o        Changes in technology, including the increased use of distributed
         generation within our transmission and distribution service territory.
o        Other risks and unforeseen events, including wars, the effects of
         terrorism, embargoes and other catastrophic events.



<PAGE>
<TABLE>
<CAPTION>




AEP Common Stock and Dividend Information

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


                                                                     Quarter-end
Quarter Ended                  High                Low              Closing Price                Dividend
- -------------                 ------             -------            -------------                --------
<S>                          <C>                 <C>                  <C>                         <C>
March 2002                    $47.08              $39.70               $46.09                      $0.60
June 2002                      48.80               39.00                40.02                       0.60
September 2002                 40.37               22.74                28.51                       0.60
December 2002                  30.55               15.10                27.33                       0.60

March 2001                    $48.10              $39.25               $47.00                      $0.60
June 2001                      51.20               45.10                46.17                       0.60
September 2001                 48.90               41.50                43.23                       0.60
December 2001                  46.95               39.70                43.53                       0.60


AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2002, AEP had approximately 144,000 shareholders of record. In 2003
management recommended that the Company reduce dividends by approximately 40%
after payment of the March 2003 dividend which was approved by the Company's
Board of Directors at the current level of $0.60 per share.
</TABLE>


<PAGE>


                      AMERICAN ELECTRIC POWER COMPANY, INC.
                            AND SUBSIDIARY COMPANIES

<PAGE>
<TABLE>
<CAPTION>



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31,                                      2002           2001            2000            1999            1998
- -----------------------                                      ----           ----            ----            ----            ----
<S>                                                        <C>             <C>             <C>             <C>             <C>
OPERATIONS STATEMENTS DATA (in millions):
Total Revenues                                             $14,555         $12,767         $11,113         $10,019         $14,080
Operating Income                                             1,263           2,182           1,774           2,061           2,046
Income Before Discontinued  Operations, Extraordinary
Items  and Cumulative Effect                                    21             917             180             869             859
Discontinued Operations Income (Loss)                         (190)             86             122             117             116
Extraordinary Losses                                          -                (50)            (35)            (14)           -
Cumulative Effect of
  Accounting Change Gain (Loss)                               (350)             18            -               -               -
Net Income (Loss)                                             (519)            971             267             972             975

December 31,                                                 2002           2001            2000            1999            1998
- ------------                                                 ----           ----            ----            ----            ----
BALANCE SHEET DATA (in millions):
Property, Plant and Equipment                              $37,857         $37,414         $34,895         $33,930         $32,400
Accumulated Depreciation
  and Amortization                                          16,173          15,310          14,899          14,266          13,374
                                                           -------         -------         -------         -------         -------
Net Property,
  Plant and Equipment                                      $21,684         $22,104         $19,996         $19,664         $19,026
                                                           =======         =======         =======         =======         =======

Total Assets                                               $34,741         $39,297         $46,633        $35,296          $33,418

Common Shareholders' Equity                                  7,064           8,229           8,054          8,673            8,452

Cumulative Preferred Stocks
  of Subsidiaries*                                             145             156             161            182              350

Trust Preferred Securities                                     321             321             334            335              335

Long-term Debt*                                             10,496           9,505           8,980          9,471            9,215

Obligations Under Capital Leases*                              228             451             614            610              539


Year Ended December 31,                                      2002             2001            2000           1999           1998
- -----------------------                                      ----             ----            ----           ----           ----
COMMON STOCK DATA:
Earnings per Common Share:
Before Discontinued Operations, Extraordinary
Items and Cumulative Effect                               $  0.06         $ 2.85            $ 0.56         $ 2.71            $2.70
Discontinued Operations                                     (0.57)          0.26              0.38           0.36             0.36
Extraordinary Losses                                          -            (0.16)            (0.11)         (0.04)             -
Cumulative Effect of
  Accounting Change                                         (1.06)          0.06               -              -                -
                                                          -------         ------            ------         ------            -----

Earnings (Loss) Per Share                                 $ (1.57)        $ 3.01            $ 0.83         $ 3.03            $3.06
                                                          =======         ======            ======         ======            =====

Average Number of Shares
  Outstanding (in millions)                                   332            322               322            321              318
Market Price Range:
                    High                                  $ 48.80         $51.20         $48-15/16       $48-3/16         $53-5/16
                    Low                                     15.10          39.25          25-15/16        30-9/16          42-1/16

Year-end Market Price                                       27.33          43.53            46-1/2         32-1/8          47-1/16

Cash Dividends on Common**                                $  2.40          $2.40             $2.40          $2.40            $2.40
Dividend Payout Ratio**                                   (152.9)%         79.7%            289.2%          79.2%            78.4%
Book Value per Share                                       $20.85         $25.54            $25.01         $26.96           $26.46

*Including portion due within one year.  Long-term Debt includes Equity Unit Senior Notes.

**Based on AEP historical dividend rate. See "Common Stock and Dividend
Information" (on page V) regarding the potential reduction of future dividends.

</TABLE>

<PAGE>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations


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

We have a vast portfolio of assets including:
o        38,000  megawatts of generating  capacity,  the largest  complement
         of generation  in the U.S.,  the majority of which has a
         significant cost advantage in our market areas
o        4,000 megawatts of generating capacity in the U.K., a country which is
         currently experiencing excess generation capacity
o        38,000 miles of transmission lines, the backbone of the electric
         interconnection grid in the Eastern U.S.
o        186,000 miles of distribution lines that support delivery of
         electricity to our customers' premises
o        Substantial coal transportation assets (7,000 railcars, 1,800 barges,
         37 tug boats and two coal handling terminals with 20 million tons of
         annual capacity)
o        6,400 miles of gas pipelines in Louisiana and Texas with 128 Bcf of
         gas storage facilities

Business Strategy

We plan to focus on utility operations in the U.S. We continue to participate in
wholesale electricity and natural gas markets. Weakness in these markets after
the collapse of Enron and other companies caused us to re-examine and realign
our strategy to direct our attention to our utility markets. We have reduced
trading to focus predominantly in markets where we have assets. We plan to
obtain maximum value for our assets by selling excess output and procuring
economical energy using commercial expertise gained from our extensive
experience in the wholesale business.

Through our utility operations focus, we intend to be the energy and low cost
generation provider of choice. We have ample generation to meet our customers'
needs. We have a cost advantage resulting from AEP's long tradition of
designing, building and operating efficient power plants and delivery networks.
Our customers continue to show top quartile level of satisfaction. We provide
safe and reliable sources of energy.

Our business provides a vital requirement of our economy and affords an
opportunity for a fair return to our shareholders. Our business provides the
opportunity for a predictable stream of cash flows and earnings, allowing us to
pay a competitive dividend to investors.

We are addressing many challenges in our unregulated business. We have already
substantially reduced our trading activities. We have written down the value of
several investments to reflect deterioration in market conditions. We are
evaluating our portfolio and plan to sell assets that are no longer core to our
business strategy. We are also in discussion with our regulators to determine if
the legal separation of certain operating company subsidiaries into regulated
and unregulated segments can be avoided. We believe that the expected benefits
from legal separation are no longer compelling. Transition rules for Michigan
and Virginia do not require legal separation. Deregulation is no longer an
expectation in the foreseeable future in the other states where we operate.

Our strategy for the core business of utility operations is to:
o        Maintain moderate but steady earnings growth
o        Maximize value of transmission assets and protect our revenue stream
         in an RTO membership environment
o        Continue process improvement to maintain distribution service quality
         while, at the same time, further enhancing financial performance
o        Optimize generation assets through increased availability and sale of
         excess capacity
o        Manage the regulatory process to maximize retention of earnings
         improvement while providing fair and reasonable rates to our
         customers

We remain very focused on credit quality and liquidity as discussed in greater
detail later in this report.

We are committed to continually evaluating the need to reallocate resources to
areas with greater potential, to match investments with our strategy and to pare
investments that do not produce sufficient return and sustainable shareholder
value. Any investment dispositions could affect future results of operations,
cash flows and possibly financial condition.

2002 Overview

2002 was a year of rapid and dramatic change for the energy industry, including
AEP, as the wholesale energy market quickly shrank and many of its participants
exited or significantly limited future trading activity. Investors lost
confidence in corporate America and the economy stalled. Investors' demand for
stability, predictable cash flows, earnings, and financial strength have
replaced their demand for rapid growth.

Our wholesale business did not perform well. We had significant losses in
options trading in the first half of the year and new investments performed well
below our expectations.

We focused on financial strength by:
o        Issuing approximately $1 billion in common stock and equity units
o        Retiring debt of  approximately $3 billion  through the sale of two f
         oreign retail utility  companies in the U.K. (SEEBOARD) and
         Australia (CitiPower)
o        Establishing a cash liquidity reserve of $1 billion at year-end

See Financing Activity in Management's Discussion and Analysis of Financial
Condition, Accounting Policies and Other Matters in section M for an overview of
all changes to capital structure.

We also focused on:
o        Implementing an enterprise-wide risk management system
o        Completing a cost reduction initiative which we expect to result in
         sustainable net annual savings of more than $200 million beginning
         in 2003
o        Eliminating or reducing future capital requirements associated with
         non-core assets

We have redirected our business strategy by:
o        Scaling back trading activities to focus principally on supporting
         our core assets
o        Selling our Texas retail business o Proposing the sale of a significant
         portion of the Texas unregulated generation assets

Outlook for 2003

We remain focused on the fundamental earnings power of our utility operations,
and we are committed to strengthening our balance sheet. Our strategy for
achieving these goals is well planned:
o        First, we will continue to identify opportunities to reduce our
         operations and maintenance expense.
o        Second, we will find opportunities to reduce capital expenditures.
o        Third, management recommended a 40% reduction in the common stock
         dividend beginning in the second quarter to a quarterly rate of $0.35
         per share. This will result in annual cash savings of approximately
         $340 million and should improve our retained earnings as well as create
         free cash flow to improve liquidity and pay-down outstanding debt.
o        Fourth, we plan to evaluate and, where appropriate, dispose of non-core
         assets. Proceeds from these sales will be used to reduce debt.
o        Fifth, we will continue to evaluate the potential for issuing
         additional equity to further strengthen our balance sheet and maintain
         credit quality.

We remain committed to being a low cost provider of electricity, to serving our
customers with excellence and to providing an attractive return to investors. We
will therefore focus on producing the best possible results from our utility
operations enhanced by a commercial group that ensures maximum value from our
assets.

Although we aim for excellent results from operations there are challenges and
certain risks. We discuss these matters in detail in the Notes to Financial
Statements and in Management's Discussion and Analysis of Financial Condition,
Accounting Policies and Other Matters. We will work diligently to resolve these
matters by finding workable solutions that balance the interests of our
customers, our employees and our investors.

Results of Operations

In 2002, AEP's principal operating business segments and their major activities
were:
   o  Wholesale:
        o  Generation of electricity for sale to retail and wholesale customers
        o  Gas pipeline and storage services
        o  Marketing and trading of electricity, gas, coal and other
           commodities
        o  Coal mining, bulk commodity barging operations and other energy
         supply related businesses
   o   Energy Delivery
        o  Domestic electricity trans-mission
        o  Domestic electricity distri-bution
   o   Other Investments
        o  Energy Services

Net Income

Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
decreased $896 million or 98% to $21 million in 2002 from $917 million in 2001.
The Company recognized impairments on under-performing assets and recorded
losses in value of $854 million (net of tax) (see Note 13). The losses in the
fourth quarter 2002 were generally caused by the extended decline in domestic
and international wholesale energy markets and in telecommunications. In 2002,
the Company's Net Loss was $519 million or a loss of $1.57 per share including
the fourth quarter losses, losses on sales of SEEBOARD and CitiPower, and a loss
for transitional goodwill impairment related to SEEBOARD and CitiPower that
resulted from the adoption of SFAS 142 (see Note 3).

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

Our wholesale business has been affected by a slowing economy. Wholesale energy
margins and energy use by industrial customers declined in 2002 and 2001.
Earnings from our wholesale business, which includes generation, increased in
2001 largely as a result of the successful return to service of the Cook Plant
in June 2000 and by acquisitions of HPL and MEMCO.

Our energy delivery business, which consists of domestic electricity
transmission and distribution services, contributed to the increase in earnings
by controlling operating and maintenance expenses and by increasing revenues in
2002 and 2001.

Capital costs decreased due primarily to interest paid to the IRS in 2000 on a
COLI deduction disallowance and continuing declines in short-term market
interest rate conditions since early 2001.

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

Revenues Increase

AEP's total revenues increased 14% in 2002 and 15% in 2001. The following table
shows the components of revenues:

                                 For The Year Ended
                                    December 31
                                --------------------
                                2002    2001    2000
                                   (in millions)
WHOLESALE:
  Residential                 $ 3,713  $ 3,553 $ 3,511
  Commercial                    2,156    2,328   2,249
  Industrial                    1,903    2,388   2,444
  Other Retail
   Customers                      385      419     414

  Electricity
    Marketing (net)             2,227      802   1,073
  Unrealized MTM
    Income-Electric               136      210      38
  Other                         1,397      632     837
  Less: Transmission and
   Distribution Revenues
   Assigned to Energy
   Delivery*                   (3,551)  (3,356) (3,174)
                               ------  ------- -------
  Wholesale
   Electric                     8,366    6,976   7,392
                               ------  ------- -------

  Gas Marketing (net)           3,021    2,274     310
  Unrealized MTM Income
   (Loss)-Gas                    (399)      47     132
                              -------  ------- -------
  Wholesale Gas                 2,622    2,321     442
                              -------  ------- -------
TOTAL WHOLESALE                10,988    9,297   7,834
                              -------  ------- -------

DOMESTIC ELECTRICITY
 DELIVERY:
  Transmission                    922    1,029   1,009
  Distribution                  2,629    2,327   2,165
                              -------  ------- -------

TOTAL DOMESTIC
 ELECTRICITY
 DELIVERY                       3,551    3,356   3,174
                              -------  ------- -------

OTHER
  INVESTMENTS                      16      114     105
                              -------  ------- -------

TOTAL REVENUES                $14,555  $12,767 $11,113
                              =======  ======= =======

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

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

The increase in 2002 in wholesale revenues resulted from a 27% increase in
trading volume associated with Wholesale Electricity which was offset by a
continuing decrease in gross margins which began in the fourth quarter of 2001,
and an increase in residential sales as a result of favorable weather conditions
in the third quarter 2002. In addition Other Wholesale electric revenues
increased due to the mid-year 2001 acquisition of barging and coal mining
operations as well as the recognition of revenues for generation projects
completed for third parties. The increase in 2002 Wholesale Gas revenues
resulted from a full year of HPL operations compared to a partial year from our
acquisition date in July 2001, offset by a decrease in the results from
financial trading and MTM unrealized losses. Other Investments revenue decreased
in 2002 due to the elimination of factoring of accounts receivable of an
unaffiliated utility.

Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward trading contracts as revenues and purchases under forward
trading contracts as purchased energy expenses. Effective July 1, 2002, we
reclassified such forward trading revenues and purchases on a net basis, as
permitted by EITF 98-10 (see Note 1).

Kilowatthour sales to industrial customers decreased by 10% in 2002 and by 5% in
2001. This decrease was due to the economic slow down which began in late 2001.
Sales to residential customers rose 5% due to weather related demand in 2002.
The economic slow down reduced demand and wholesale prices especially in the
latter part of 2001.

Operating Expenses Increase

Changes in the components of operating expenses were as follows:

                               Increase (Decrease)
                               From Previous Year
                                2002         2001
                                ----         ----
                                  (in millions)
                           Amount     %      Amount     %
                           ------     -      ------     -
Fuel and Purchased
 Energy:
  Electricity              $  959   43.7    $(1,275) (36.7)
  Gas                         404   14.7      2,339  570.5
Maintenance and
 Other Operation              303    8.2        228    6.5
Non-recoverable
 Merger Costs                 (11) (52.4)      (182) (89.7)
Asset Impairments             867   N.M.       -     -
Depreciation and
 Amortization                 134   10.8        152   13.9
Taxes Other Than
 Income Taxes                  51    7.6        (16)  (2.3)
                           ------            ------
      Total                $2,707   25.6     $1,246   13.3
                           ======            ======

The increase in Fuel and Purchased Energy expense was primarily attributable to
an increase in power generation. Net generation increased 6% for Eastern plants
due to increased demand for electricity and a reduction in planned power plant
maintenance outages for various plants as compared to 2001. The return to
service of the Cook Plant's two nuclear generating units in June 2000 and
December 2000 accounted for the increase in nuclear generation. The increase in
Gas expense was primarily due to a full year of HPL operations compared to a
partial year from our acquisition date in July 2001.

The increase in Maintenance and Other Operation expense in 2002 is primarily due
to recognizing a full year's expense for the businesses acquired during 2001
including MEMCO (a barging line), Quaker Coal, two power plants in the U.K. and
HPL. In addition, increased administrative costs for the implementation of
customer choice in Texas contributed to the increase. The increase was offset in
part by a reduction in trading incentive compensation and the effect of planned
boiler plant maintenance at various plants in 2001 and less refueling outages
for STP in 2002 than 2001.

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

With the consummation of the merger with CSW, certain deferred merger costs were
expensed in 2000. The merger costs charged to expense included transaction and
transition costs not allocable to and recoverable from ratepayers under
regulatory commission approved settlement agreements to share net merger
savings. As expected, merger costs declined in 2001 and 2002 after the merger
was consummated.

In 2002 AEP recorded pre-tax impairments of assets (including Goodwill) and
investments totaling $1.4 billion (consisting of approximately, $866.6 million
related to asset impairments, $321.1 million related to investment value losses,
and $238.7 million related to discontinued operations) that reflected downturns
in energy trading markets, projected long-term decreases in electricity prices,
and other factors. These impairments exclude the transitional impairment loss
from adoption of SFAS142 (see Note 2). The categories of impairments included:

                 2002 Pre-Tax Estimated Loss
                         (in millions)

Asset Impairments
  Held for Sale            $  483.1
Asset Impairments
  Held and Used               651.4
Investment Value
  Losses                      291.9
                           --------

       Total               $1,426.4
                           ========

Additional market deterioration associated with our non-core wholesale
investments, including our U.K. operations, could have an adverse impact on our
future results of operations and cash flows. Significant long-term changes in
external market conditions could lead to additional write-offs and potential
divestitures of our wholesale investments, including, but not limited to, our
U.K. operations.

The rise in Depreciation and Amortization expense in 2002 resulted from the
amortization of Texas generation related Regulatory Assets that were securitized
in early 2002, businesses acquired in 2001 and additional production plant
placed into service.

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

Taxes Other Than Income Taxes increased in 2002 due to a full year of state
excise taxes which replaced the state gross receipts tax in Ohio and increased
local franchise taxes in Texas partly offset by the effect of Texas one-time
2001 assessments and decreased gross Texas receipts taxes due to deregulation.

Interest, Preferred Stock Dividends, Minority Interest

The decrease in Interest in 2002 was primarily due to a reduction in short-term
interest rates and lower outstanding balances of short-term debt and the
refinancing of long-term debt at favorable interest rates offset in part by an
increased amount of long-term debt outstanding.

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

Minority Interest in Finance Subsidiary increased substantially in 2002 because
the distributions to minority interest were in effect for the entire year. In
2001 we issued a preferred member interest to finance the acquisition of HPL and
paid a preferred return of $13 million to the preferred member interest. The
minority interest was only in effect during the last four months of 2001.

Other Income/Other Expenses

Other Income increased by $110 million or 33% in 2002 due to the sale of AEP'S
retail electric providers in Texas and due to non-operational revenue (see Note
1). Other Expenses increased $134 million or 72% in 2002 due to non-operational
expenses (see Note 1).

Other Income increased $240 million in 2001. This increase was primarily caused
by an increase in equity earnings due to acquisitions of $63 million and a $73
million gain from the sale of a generating plant (see Note 1). Other Expenses
increased by $110 million or 143% in 2001 due to costs to exit air
transportation, fiber optic and Datapult businesses (see Note 1).

Income Taxes

The decrease in total Income Taxes in 2002 was due to a decrease in pre-tax book
income offset by the tax effects of the sale of foreign operations.

Although pre-tax book income increased considerably in 2001, Income Taxes
decreased due to the effect of recording in 2000 prior year federal income taxes
as a result of the disallowance of COLI interest deductions by the IRS and
nondeductible merger related costs in 2000.

Extraordinary Losses and Cumulative Effect

The loss for transitional goodwill impairment related to SEEBOARD and CitiPower
resulted from the adoption of SFAS 142 (see Notes 2 and 3) and has been reported
as a Cumulative Effect of Accounting Change on January 1, 2002.

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

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

Discontinued Operations

The operations shown below were discontinued or held for sale in 2002 (See Note
12). Results of operations including impairment losses, net of tax, of these
businesses have been reclassified:

Company             2002           2001          2000
- -------             ----           ----          ----
                              (in millions)
SEEBOARD           $  96          $ 88           $ 99
CitiPower           (123)           (6)            17
Pushan                (7)            4              7
Eastex              (156)           -              (1)
                   -----          ----           ----
                   $(190)         $ 86           $122
                   =====          ====           ====


Reclassification

Balance sheet amounts have been restated to reflect our change in accounting
policy regarding certain assets and liabilities related to forward physical and
financial transactions (see "Reclassification" discussion Note 1.) Based upon
AEP's legal rights of offset, physical and financial contracts were netted in
2002 and 2001 amounts and financial contracts were netted in 2000 and 1999
amounts. Related assets and liabilities were not netted in 1998 amounts as the
impact is not material.



<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Operations
- -------------------------------------
(in millions - except per share amounts)
                                                                                                 Year Ended December 31,
                                                                                               --------------------------
                                                                                           2002           2001           2000
                                                                                           ----           ----           ----
<S>                                                                                      <C>            <C>            <C>
REVENUES:
  Wholesale Electricity                                                                  $ 8,366        $ 6,976        $ 7,392
  Wholesale Gas                                                                            2,622          2,321            442
  Domestic Electricity Delivery                                                            3,551          3,356          3,174
  Other Investment                                                                            16            114            105
                                                                                         -------        -------        -------
               TOTAL REVENUES                                                             14,555         12,767         11,113
                                                                                         -------        -------        -------

EXPENSES:
  Fuel and Purchased Energy:
   Electricity                                                                             3,154          2,195          3,470
   Gas                                                                                     3,153          2,749            410
                                                                                         -------        -------        -------
     TOTAL FUEL AND PURCHASED ENERGY                                                       6,307          4,944          3,880
  Maintenance and Other Operation                                                          4,013          3,710          3,482
  Non-recoverable Merger Costs                                                                10             21            203
  Asset Impairments                                                                          867           -              -
  Depreciation and Amortization                                                            1,377          1,243          1,091
  Taxes Other Than Income Taxes                                                              718            667            683
                                                                                         -------        -------        -------

               TOTAL EXPENSES                                                             13,292         10,585          9,339
                                                                                         -------        -------        -------

OPERATING INCOME                                                                           1,263          2,182          1,774

OTHER INCOME                                                                                 445            335             95

LESS: INVESTMENT VALUE AND OTHER IMPAIRMENT LOSSES                                           321           -              -

LESS: OTHER EXPENSES                                                                         321            187             77

LESS: INTEREST                                                                               785            844            999
      PREFERRED STOCK DIVIDEND REQUIREMENTS OF
       SUBSIDIARIES                                                                           11             10             11
      MINORITY INTEREST IN FINANCE SUBSIDIARY                                                 35             13           -
                                                                                         -------        -------        -------

INCOME BEFORE INCOME TAXES                                                                   235          1,463            782
INCOME TAXES                                                                                 214            546            602
                                                                                         -------        -------        -------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS
  AND CUMULATIVE EFFECT                                                                       21            917            180
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX)                                          (190)            86            122
EXTRAORDINARY LOSSES (NET OF TAX):
  DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION                                    -               (48)           (35)
  LOSS ON REACQUIRED DEBT                                                                   -                (2)          -

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX)                                         (350)            18           -
                                                                                         -------        -------        -------

NET INCOME (LOSS)                                                                        $  (519)       $   971        $   267
                                                                                         =======        =======        =======

AVERAGE NUMBER OF SHARES OUTSTANDING                                                         332            322            322
                                                                                             ===            ===            ===

EARNINGS (LOSS) PER SHARE:
  Income Before Discontinued Operations, Extraordinary Items
     and Cumulative Effect of Accounting Change                                           $ 0.06         $ 2.85         $ 0.56
  Discontinued Operations                                                                  (0.57)          0.26           0.38
  Extraordinary Losses                                                                       -            (0.16)         (0.11)
  Cumulative Effect of Accounting Change                                                   (1.06)          0.06            -
                                                                                          ------         ------         ------

  Earnings (Loss) Per Share (Basic and Diluted)                                           $(1.57)        $ 3.01         $ 0.83
                                                                                          ======         ======         ======

CASH DIVIDENDS PAID PER SHARE                                                              $2.40          $2.40          $2.40
                                                                                           =====          =====          =====

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
- ---------------------------
(in millions - except share data)
                                                                                                           December 31,
                                                                                                           -----------
                                                                                                   2002                 2001
                                                                                                   ----                 ----
<S>                                                                                              <C>                  <C>
ASSETS
CURRENT ASSETS:
  Cash and Cash Equivalents                                                                      $ 1,213              $   224
  Accounts Receivable:
    Customers                                                                                        466                  343
    Miscellaneous                                                                                  1,394                1,365
    Allowance for Uncollectible Accounts                                                            (119)                 (69)
  Fuel, Materials and Supplies                                                                     1,166                1,037
  Energy Trading and Derivative Contracts                                                          1,046                2,125
  Other                                                                                              935                  639
                                                                                                 -------              -------

          TOTAL CURRENT ASSETS                                                                     6,101                5,664
                                                                                                 -------              -------

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
    Production                                                                                    17,031               17,054
    Transmission                                                                                   5,882                5,764
    Distribution                                                                                   9,573                9,309
  Other (including gas and coal mining assets
    and nuclear fuel)                                                                              3,965                4,272
  Construction Work in Progress                                                                    1,406                1,015
                                                                                                 -------              -------
           Total Property, Plant and Equipment                                                    37,857               37,414
  Accumulated Depreciation and Amortization                                                       16,173               15,310
                                                                                                 -------              -------

          NET PROPERTY, PLANT AND EQUIPMENT                                                       21,684               22,104
                                                                                                 -------              -------

REGULATORY ASSETS                                                                                  2,688                3,162
                                                                                                 -------              -------

SECURITIZED TRANSITION ASSETS                                                                        735                 -
                                                                                                 -------              -------

INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS                                                       283                  633
                                                                                                 -------              -------

ASSETS HELD FOR SALE                                                                                 247                  721
                                                                                                 -------              -------

ASSETS OF DISCONTINUED OPERATIONS                                                                   -                   3,954
                                                                                                 -------              -------

GOODWILL                                                                                             396                  392
                                                                                                 -------              -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                    824                  795
                                                                                                 -------              -------

OTHER ASSETS                                                                                       1,783                1,872
                                                                                                 -------              -------

            TOTAL ASSETS                                                                         $34,741              $39,297
                                                                                                 =======              =======

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
                                                                                                          December 31,
                                                                                                          -----------
                                                                                                   2002                2001
                                                                                                   ----                ----
<S>                                                                                              <C>                 <C>
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts Payable                                                                               $ 2,042             $ 1,914
  Short-term Debt                                                                                  3,164               4,011
  Long-term Debt Due Within One Year*                                                              1,633               1,095
  Energy Trading and Derivative Contracts                                                          1,147               1,877
  Other                                                                                            1,804               1,924
                                                                                                 -------             -------

          TOTAL CURRENT LIABILITIES                                                                9,790              10,821
                                                                                                 -------             -------

LONG-TERM DEBT*                                                                                    8,487               8,410
                                                                                                 -------             -------

EQUITY UNIT SENIOR NOTES                                                                             376                -
                                                                                                 -------             -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                    484                 603
                                                                                                 -------             -------

DEFERRED INCOME TAXES                                                                              3,916               4,500
                                                                                                 -------             -------

DEFERRED INVESTMENT TAX CREDITS                                                                      455                 491
                                                                                                 -------             -------

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                          765                 819
                                                                                                 -------             -------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2                                          185                 194
                                                                                                 -------             -------

OTHER NONCURRENT LIABILITIES                                                                       1,903               1,334
                                                                                                 -------             -------

LIABILITIES HELD FOR SALE                                                                             91                  87
                                                                                                 -------             -------

LIABILITIES OF DISCONTINUED OPERATIONS                                                              -                  2,582
                                                                                                 -------             -------

COMMITMENTS AND CONTINGENCIES (Note 9)

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE
  PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
  SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
  SUBSIDIARIES                                                                                       321                 321
                                                                                                 -------             -------

MINORITY INTEREST IN FINANCE SUBSIDIARY                                                              759                 750
                                                                                                 -------             -------

CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*                                                          145                 156
                                                                                                 -------             -------

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                                  2002          2001
                                  ----          ----
    Shares Authorized. . . . .600,000,000   600,000,000
    Shares Issued. . . . . . .347,835,212   331,234,997
    (8,999,992 shares were held in treasury
     at December 31, 2002 and 2001)                                                                2,261               2,153
  Paid-in Capital                                                                                  3,413               2,906
  Accumulated Other Comprehensive Income (Loss)                                                     (609)               (126)
  Retained Earnings                                                                                1,999               3,296
                                                                                                 -------             -------
          TOTAL COMMON SHAREHOLDERS' EQUITY                                                        7,064               8,229
                                                                                                 -------             -------

            TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                           $34,741             $39,297
                                                                                                 =======             =======

*See Accompanying Schedules.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                     Consolidated Statements of Cash Flows
                                 (in millions)
                             Year Ended December 31,
                                                                                                ---------------------------
                                                                                            2002           2001              2000
                                                                                            ----           ----              ----
<S>                                                                                        <C>            <C>              <C>
OPERATING ACTIVITIES:
  Net Income (Loss)                                                                        $ (519)        $   971          $   267
  Plus:  Discontinued Operations                                                              540             (86)            (122)
                                                                                           ------         -------           ------
  Net Income from Continuing Operations                                                        21             885              145
  Adjustments for Noncash Items:
    Asset Impairments, Investment Value and Other Impairments                               1,188            -                -
    Depreciation and Amortization                                                           1,403           1,277            1,152
    Deferred Investment Tax Credits                                                           (31)            (29)             (36)
    Deferred Income Taxes                                                                     (66)            157             (190)
    Amortization of Operating Expenses and Carrying Charges                                    40              40               48
    Cumulative Effect of Accounting Change                                                   -                (18)            -
    Equity Earnings of Yorkshire Electricity Group plc                                       -               -                 (44)
    Extraordinary Loss                                                                       -                 50               35
    Deferred Costs Under Fuel Clause Mechanisms                                               (31)            340             (449)
    Mark-to-Market of Energy Trading Contracts                                                263            (257)            (170)
    Miscellaneous Accrued Expenses                                                             30            (384)             217
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                                (152)          1,766           (1,530)
    Fuel, Materials and Supplies                                                             (127)            (78)             149
    Accrued Revenues                                                                         (283)             35              (71)
    Accounts Payable                                                                           52            (478)           1,292
    Taxes Accrued                                                                            (216)           (147)             171
  Payment of Disputed Tax and Interest Related to COLI                                       -                 -               319
  Change in Other Assets                                                                     (177)           (239)            (283)
  Change in Other Liabilities                                                                (237)           (161)             386
                                                                                           ------         -------          -------
        Net Cash Flows From Operating Activities                                            1,677           2,759            1,141
                                                                                           ------         -------          -------
INVESTING ACTIVITIES:
  Construction Expenditures                                                                (1,722)         (1,654)          (1,468)
  Purchase of Gas Pipe Line                                                                  -               (727)            -
  Purchase of U.K. Generation                                                                -               (943)            -
  Purchase of Coal Company                                                                   -               (101)            -
  Purchase of Barging Operations                                                             -               (266)            -
  Purchase of Wind Generation                                                                -               (175)            -
  Proceeds from Sale of Retail Electric Providers                                             146            -                -
  Proceeds from Sale of Foreign Investments                                                 1,117             383             -
  Proceeds from Sale of U.S. Generation                                                      -                265             -
  Other                                                                                        37             (42)             (18)
                                                                                           ------         -------          -------
        Net Cash Flows Used For Investing Activities                                         (422)         (3,260)          (1,486)
                                                                                           ------         -------          -------
FINANCING ACTIVITIES:
  Issuance of Common Stock                                                                    656              11               14
  Issuance of Minority Interest                                                              -                744             -
  Issuance of Long-term Debt                                                                2,893           2,863              878
  Issuance of Equity Unit Senior Notes                                                        334            -                -
  Retirement of Cumulative Preferred Stock                                                    (10)             (5)             (21)
  Retirement of Long-term Debt                                                             (2,514)         (1,570)          (1,303)
  Change in Short-term Debt (net)                                                            (829)           (790)           1,328
  Dividends Paid on Common Stock                                                             (793)           (773)            (805)
  Dividends on Minority Interest in Subsidiary                                               -                 (5)            -
                                                                                           ------         -------          -------
        Net Cash Flows From (Used for) Financing Activities                                  (263)            475               91
                                                                                           ------         -------          -------
Effect of Exchange Rate Changes on Cash                                                        (3)             (1)              30
                                                                                           ------         -------          -------
Net Increase (Decrease) in Cash and Cash Equivalents                                          989             (27)            (224)
Cash and Cash Equivalents from Continuing Operations -  Beginning of Period                   224             251              475
                                                                                           ------         -------          -------
Cash and Cash Equivalents from Continuing Operations -  End of  Period                     $1,213         $   224          $   251
                                                                                           ======         =======          =======
Net Increase (Decrease) in Cash and Cash Equivalents from
  Discontinued Operations                                                                  $ (100)        $    17          $   (17)
Cash and Cash Equivalents from Discontinued Operations -  Beginning of Period                 108              91              108
                                                                                           ------         -------          -------
Cash and Cash Equivalents from Discontinued Operations -  End of Period                    $    8         $   108          $    91
                                                                                           ======         =======          =======

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


</TABLE>

<PAGE>
<TABLE>
<CAPTION>



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   Capital   Earnings   Income (Loss)       Total
                                            ------  ------   -------   --------   -------------       -----

<S>                                         <C>    <C>      <C>       <C>           <C>            <C>
DECEMBER 31, 1999                           331    $2,149   $2,898    $3,630         $  (4)           $8,673
Issuances                                    -          3       11      -                -                14
Cash Dividends Declared                      -       -        -         (805)            -              (805)
Other                                        -       -           6        (2)            -                 4
                                                                                                      ------
                                                                                                       7,886
Comprehensive 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
Issuances                                    -          1        9      -              -                  10
Cash Dividends Declared                      -       -        -         (773)          -                (773)
Other                                        -       -         (18)        8           -                 (10)
                                                                                                      ------
                                                                                                       7,281
Comprehensive 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                           331    $2,153   $2,906    $3,296          $(126)          $8,229

Issuances                                    17       108      568      -              -                 676
Cash Dividends Declared                      -       -        -         (793)          -                (793)
Other                                        -       -         (61)       15           -                 (46)
                                                                                                      ------
                                                                                                        (163)
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment    -       -        -         -               117              117
  Unrealized Gain (Loss) on
   Hedged Derivatives                                                                   (13)             (13)
  Minimum Pension Liability                  -       -        -         -              (585)            (585)
  Unrealized Loss on Securities Available
   For Sale                                                                              (2)              (2)
 Net Income (Loss)                           -       -        -         (519)                           (519)
                                                                                                      ------
   Total Comprehensive Income                                                                         (1,002)
                                            ---    ------   ------    ------          -----           ------

DECEMBER 31, 2002                           348    $2,261   $3,413    $1,999          $(609)          $7,064
                                            ===    ======   ======    ======          =====           ======

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries

                                                                 December 31, 2002
                                                                 -----------------
                                         Call
                                       Price per             Shares              Shares       Amount (In
                                        Share(a)          Authorized(b)       Outstanding(f)  Millions)
                                      --------------------------------------------------------------------
<S>                                    <C>                  <C>                 <C>            <C>
Not Subject to Mandatory Redemption:
  4.00% - 5.00%                        $102-$110            1,525,903           608,150        $ 61
                                                                                               ----

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                      (d)                1,950,000           333,100          33
  6.02% - 6-7/8% (c)                     $100               1,650,000           513,450          51
                                                                                               ----
    Total Subject to Mandatory
      Redemptio(C)(c) 84

Total Preferred Stock                                                                          $145
                                                                                               ====


</TABLE>

<TABLE>
<CAPTION>

                                                                 December 31, 2001
                                                                 -----------------
                                         Call
                                       Price per             Shares               Shares       Amount (In
                                        Share(a)          Authorized(b)        Outstanding(f)  Millions)
                                      --------------------------------------------------------------------
<S>                                    <C>                  <C>                 <C>            <C>
Not Subject to Mandatory Redemption:
  4.00% - 5.00%                        $102-$110            1,525,903           614,608        $ 61
                                                                                               ----

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                       (d)               1,950,000           333,100          33
  6.02% - 6-7/8% (c)                     $100               1,650,000           513,450          52
  7% (e)                                  (e)                 250,000           100,000          10
                                                                                               ----
    Total Subject to Mandatory
      Redemption (c)                                                                             95
                                                                                               ----

Total Preferred Stock                                                                          $156
                                                                                               ====


</TABLE>


NOTES TO SCHEDULE OF CONSOLIDATED 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 involuntary liquidation preference is
       $100 per share for all outstanding shares.
(b)    As of December 31, 2002 the subsidiaries had 13,749,202, 22,200,000 and
       7,713,501 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.
(d)    Not callable prior to 2003, after that the call price is $100 per share
       plus accrued dividends. (e) With sinking fund. (f) The number of shares
       of preferred stock redeemed is 106,458 shares in 2002, 50,000 shares
       in 2001 and 209,563 shares in 2000.


<PAGE>
<TABLE>
<CAPTION>


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, 2002       2002            2001         2002          2001
                              -----------------       ----            ----         ----          ----
                                                                                      (in millions)
                                                                                      -------------
<S>                                  <C>          <C>              <C>            <C>           <C>
FIRST MORTGAGE BONDS (a)
  2002-2004                          6.87%        6.00%-7.85%      6.00%-7.85%    $   648       $ 1,246
  2005-2008                          6.90%        6.20%-8%         6.20%-8%           463           699
  2022-2025                          7.66%        6.875%-8.7%      6-7/8%-8.80%       773           850

INSTALLMENT PURCHASE CONTRACTS (b)
  2002-2009                          4.62%        3.75%-7.70%      1.80%-7.70%        396           446
  2011-2030                          5.83%        1.35%-8.20%      1.55%-8.20%      1,284         1,234

NOTES PAYABLE (c)
  2002-2021                          5.54%        3.732%-9.60%     4.048%-9.60%       520           217

SENIOR UNSECURED NOTES
  2002-2005                          5.53%        2.12%-7.45%      2.31%-7.45%      1,834         1,910
  2006-2012                          5.91%        4.31%-6.91%      6.125%-6.91%     2,295         1,727
  2032-2038                          6.64%        6.00%-7-3/8%     7.20%-7-3/8%       690           340

JUNIOR DEBENTURES
  2025-2038                          7.90%        7.60%-8.72%      7.60%-8.72%        205           618

SECURITIZATION BONDS
  2003-2016                          5.40%        3.54%-6.25%           -             797           -

OTHER LONG-TERM DEBT (d)                                                              247           258

Unamortized Discount (net)                                                            (32)          (40)
                                                                                  -------       -------
Total Long-term Debt
  Outstanding                                                                      10,120         9,505
Less Portion Due Within One Year                                                    1,633         1,095
                                                                                  -------       -------
Long-term Portion                                                                 $ 8,487       $ 8,410
                                                                                  =======       =======

EQUITY UNIT SENIOR NOTES
  2007                               5.75%        5.75%                 -         $   376       $  -
                                                                                  =======       =======

</TABLE>

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 agreements 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 9 of the Notes to Consolidated Financial
Statements) and financing obligation under sale lease back agreements.

Long-term debt outstanding at December 31, 2002 (includes Equity Unit Senior
Notes) is payable as follows:


                   (in millions)

     2003                             $ 1,633
     2004                                 824
     2005                                 993
     2006                               1,611
     2007                               1,081
     Later Years                        4,386
                                      -------
                                       10,528
     Unamortized Discount                  32
                                      -------
     Total                            $10,496




<PAGE>


AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Combined Notes to Consolidated Financial Statements

The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.

                                                            Combined
                                                            Footnote
                                                            Reference
                                                            ---------

Significant Accounting Policies                              Note  1

Extraordinary Items and Cumulative Effect                    Note  2

Goodwill and Other Intangible Assets                         Note  3

Merger                                                       Note  4

Nuclear Plant Restart                                        Note  5

Rate Matters                                                 Note  6

Effects of Regulation                                        Note  7

Customer Choice and Industry Restructuring                   Note  8

Commitments and Contingencies                                Note  9

Guarantees                                                   Note 10

Sustained Earnings Improvement Initiative                    Note 11

Acquisitions, Dispositions and Discontinued Operations       Note 12

Asset Impairments and Investment Value Losses                Note 13

Benefit Plans                                                Note 14

Stock-Based Compensation                                     Note 15

Business Segments                                            Note 16

Risk Management, Financial Instruments And Derivatives       Note 17

Income Taxes                                                 Note 18

Basic and Diluted Earnings Per Share                         Note 19

Supplementary Information                                    Note 20

Power and Distribution Projects                              Note 21

Leases                                                       Note 22

Lines of Credit and Sale of Receivables                      Note 23

Unaudited Quarterly Financial Information                    Note 24

Trust Preferred Securities                                   Note 25

Minority Interest in Finance Subsidiary                      Note 26

Equity Units                                                 Note 27

Subsequent Events (Unaudited)                                Note 30


<PAGE>


INDEPENDENT AUDITORS' REPORT



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

We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001,
and the related consolidated statements of operations, cash flows and common
shareholders' equity and comprehensive income, for each of the three years in
the period ended December 31, 2002. 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, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.

As discussed in Note 13 to the consolidated financial statements, the Company
recorded certain impairments of goodwill, long-lived assets and other
investments in the fourth quarter of 2002.


/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003


<PAGE>


MANAGEMENT'S RESPONSIBILITY

The management of American Electric Power Company, Inc. has prepared the
financial statements and schedules herein and 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 accounting principles generally accepted in the
United States of America, 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 previous 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.


<PAGE>




                             AEP GENERATING COMPANY


<PAGE>
<TABLE>
<CAPTION>



AEP GENERATING COMPANY
Selected Financial Data
- -----------------------
                                                                                    Year Ended December 31,
                                                                                    ----------------------
                                                             2002            2001            2000            1999            1998
                                                             ----            ----            ----            ----            ----
                                                                                         (in thousands)
<S>                                                        <C>             <C>             <C>             <C>             <C>
INCOME STATEMENTS DATA:

  Operating Revenues                                       $213,281        $227,548        $228,516        $217,189        $224,146
  Operating Expenses                                        207,152         220,571         220,092         211,849         215,415
                                                           --------        --------        --------        --------        --------
  Operating Income                                            6,129           6,977           8,424           5,340           8,731
  Nonoperating Items, Net                                     3,681           3,484           3,429           3,659           3,364
  Interest Charges                                            2,258           2,586           3,869           2,804           3,149
                                                           --------        --------        --------        --------        --------
  Net Income                                               $  7,552        $  7,875        $  7,984        $  6,195        $  8,946
                                                           ========        ========        ========        ========        ========

                                                                                          December 31,
                                                                                          -----------
                                                             2002            2001            2000            1999            1998
                                                             ----            ----            ----            ----            ----
                                                                                        (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant                                   $652,213        $648,254        $642,302        $640,093        $636,460
  Accumulated Depreciation                                  358,174         337,151         315,566         295,065         277,855
                                                           --------        --------        --------        --------        --------
  Net Electric Utility Plant                               $294,039        $311,103        $326,736        $345,028        $358,605
                                                           ========        ========        ========        ========        ========

  Total Assets                                             $349,729        $361,341        $374,602        $398,640        $403,892
                                                           ========        ========        ========        ========        ========

  Common Stock and Paid-in Capital                         $ 24,434        $ 24,434        $ 24,434        $ 30,235        $ 36,235
  Retained Earnings                                          18,163          13,761           9,722           3,673           2,770
                                                           --------        --------        --------        --------        --------
  Total Common Shareholder's Equity                        $ 42,597        $ 38,195        $ 34,156        $ 33,908        $ 39,005
                                                           ========        ========        ========        ========        ========

  Long-term Debt (a)                                       $ 44,802        $ 44,793        $ 44,808        $ 44,800        $ 44,792
                                                           ========        ========        ========        ========        ========

  Total Capitalization
   And Liabilities                                         $349,729        $361,341        $374,602        $398,640        $403,892
                                                           ========        ========        ========        ========        ========

(a) Including portion due within one year.

</TABLE>

<PAGE>




AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------


AEP Generating Company is engaged in the generation and wholesale sale of
electric power to two affiliates under long-term agreements.

Operating Revenues are derived from the sale of Rockport Plant energy and
capacity to two affiliated companies, I&M and KPCo, pursuant to FERC approved
long-term unit power agreements. Under the terms of its unit power agreement,
I&M will purchase all of AEGCo's Rockport capacity unless it is sold to other
utilities. A unit power agreement between AEGCo and KPCo expires in 2004. The
KPCo unit power agreement extends until December 31, 2009 for Rockport Plant
Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes operative. The
unit power agreements provide for recovery of costs including a FERC approved
rate of return on common equity and a return on other capital net of temporary
cash investments. Under terms of the unit power agreements, AEGCo accumulates
all expenses monthly and prepares the bills for its affiliates. In the month the
expenses are incurred, AEGCo recognizes the billing revenues and establishes a
receivable from the affiliated companies.

Results of Operations

Net Income decreased $323,000 or 4% as a result of limits on recovery of return
on capital related to operating and in-service ratios of the Rockport Plant.

Operating Revenues Decrease
- ---------------------------

The decrease in Operating Revenues of $14,267,000 or 6% reflects a decrease in
recoverable expenses, primarily fuel.


Operating Expenses Decrease
- ---------------------------

Operating Expenses decreased 6% as follows:

                                            Increase
                                           (Decrease)
(dollars in thousands)                 From Previous Year
- ---------------------                  ------------------
                                          Amount     %
                                          ------     -
Fuel                                   $(13,723)    (13)
Other Operation                           1,899      17
Maintenance                                 565       6
Depreciation                                137       1
Taxes Other Than Income Taxes              (976)    (23)
Income Taxes                             (1,321)    (46)
                                       --------
        Total                          $(13,419)     (6)
                                       ========


The decrease in Fuel expense reflects a decrease in generation and lower average
fuel costs.

Other Operation expense increased due to increased costs for employee benefits
and property insurance.

The increase in Maintenance expense can be attributed to shorter duration of
maintenance outages for boiler inspection and repair in 2001.

Taxes Other Than Income Taxes decreased due to a decrease in Indiana real and
personal property taxes reflecting a favorable change in the law which lowered
the tax for Rockport Plant.

The decrease in Income Taxes attributable to operations is primarily due to a
decrease in pre-tax operating income and a change in estimate for state income
tax accruals.





<PAGE>
<TABLE>
<CAPTION>


AEP GENERATING COMPANY
Statements of Income
- --------------------
                                                                                                 Year Ended December 31,
                                                                                     -----------------------------------------
                                                                                       2002             2001             2000
                                                                                       ----             ----             ----
                                                                                                   (in thousands)
<S>                                                                                  <C>             <C>              <C>
OPERATING REVENUES                                                                   $213,281        $227,548         $228,516
                                                                                     --------        --------         --------

OPERATING EXPENSES:
  Fuel                                                                                 89,105         102,828          102,978
  Rent - Rockport Plant Unit 2                                                         68,283          68,283           68,283
  Other Operation                                                                      12,924          11,025           10,295
  Maintenance                                                                           9,418           8,853            9,616
  Depreciation                                                                         22,560          22,423           22,162
  Taxes Other Than Income Taxes                                                         3,281           4,257            3,854
  Income Taxes                                                                          1,581           2,902            2,904
                                                                                     --------        --------         --------

            TOTAL OPERATING EXPENSES                                                  207,152         220,571          220,092
                                                                                     --------        --------         --------

OPERATING INCOME                                                                        6,129           6,977            8,424

NONOPERATING INCOME                                                                       343              30                6

NONOPERATING EXPENSES                                                                     198              16               17

NONOPERATING INCOME TAX CREDITS                                                         3,536           3,470            3,440

INTEREST CHARGES                                                                        2,258           2,586            3,869
                                                                                     --------        --------         --------

NET INCOME                                                                           $  7,552        $  7,875         $  7,984
                                                                                     ========        ========         ========


Statements of Retained Earnings

                                                                                               Year Ended December 31,
                                                                                      ----------------------------------------
                                                                                       2002             2001             2000
                                                                                       ----             ----             ----
                                                                                                   (in thousands)

RETAINED EARNINGS JANUARY 1                                                           $13,761         $ 9,722           $3,673

NET INCOME                                                                              7,552           7,875            7,984

CASH DIVIDENDS DECLARED                                                                 3,150           3,836            1,935
                                                                                      -------         -------           ------

RETAINED EARNINGS DECEMBER 31                                                         $18,163         $13,761           $9,722
                                                                                      =======         =======           ======

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



AEP GENERATING COMPANY
Balance Sheets
- --------------
                                                                                                          December 31,
                                                                                                 -----------------------------
                                                                                                    2002                2001
                                                                                                    ----                ----
                                                                                                         (in thousands)
<S>                                                                                               <C>                 <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                                                      $637,095            $638,297
  General                                                                                            4,728               3,012
  Construction Work in Progress                                                                     10,390               6,945
                                                                                                  --------            --------
          Total Electric Utility Plant                                                             652,213             648,254

  Accumulated Depreciation                                                                         358,174             337,151
                                                                                                  --------             -------

          NET ELECTRIC UTILITY PLANT                                                               294,039             311,103
                                                                                                  --------             -------

OTHER PROPERTY AND INVESTMENTS                                                                         119                 119
                                                                                                  --------            --------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                           -                    983
  Accounts Receivable:
   Affiliated Companies                                                                             18,454              22,344
   Miscellaneous                                                                                      -                    147
  Fuel                                                                                              20,260              15,243
  Materials and Supplies                                                                             4,913               4,480
  Prepayments                                                                                         -                    244
                                                                                                  --------            --------

          TOTAL CURRENT ASSETS                                                                      43,627              43,441
                                                                                                  --------            --------

REGULATORY ASSETS                                                                                    4,970               5,207
                                                                                                  --------            --------

DEFERRED CHARGES                                                                                     6,974               1,471
                                                                                                  --------            --------

                    TOTAL ASSETS                                                                  $349,729            $361,341
                                                                                                  ========            ========


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

</TABLE>



<PAGE>
<TABLE>
<CAPTION>


AEP GENERATING COMPANY
                                                                                                                December 31,
                                                                                                                -----------
                                                                                                         2002                2001
                                                                                                         ----                ----
                                                                                                               (in thousands)
<S>                                                                                                    <C>                 <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares                                                          $  1,000            $  1,000
  Paid-in Capital                                                                                        23,434              23,434
  Retained Earnings                                                                                      18,163              13,761
                                                                                                       --------            --------
    Total Common Shareholder's Equity                                                                    42,597              38,195
  Long-term Debt                                                                                         44,802              44,793
                                                                                                       --------            --------


          TOTAL CAPITALIZATION                                                                           87,399              82,988
                                                                                                       --------            --------

OTHER NONCURRENT LIABILITIES                                                                                301                  76
                                                                                                       --------            --------

CURRENT LIABILITIES:
  Advances from Affiliates                                                                               28,034              32,049
  Accounts Payable:
    General                                                                                                  26               7,582
    Affiliated Companies                                                                                 15,907               1,654
  Taxes Accrued                                                                                           2,327               4,777
  Rent Accrued - Rockport Plant Unit 2                                                                    4,963               4,963
  Other                                                                                                   1,111               3,481
                                                                                                       --------            --------

          TOTAL CURRENT LIABILITIES                                                                      52,368              54,506
                                                                                                       --------            --------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2                                             111,046             116,617
                                                                                                       --------            --------

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits                                                                        52,943              56,304
  Amounts Due to Customers for Income Taxes                                                              16,670              22,725
                                                                                                       --------            --------

          TOTAL REGULATORY LIABILITIES                                                                   69,613              79,029
                                                                                                       --------            --------

DEFERRED INCOME TAXES                                                                                    29,002              27,975
                                                                                                       --------            --------

DEFERRED CREDITS                                                                                           -                    150
                                                                                                       --------            --------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                               $349,729            $361,341
                                                                                                       ========            ========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



AEP GENERATING COMPANY
Statements of Cash Flows
- ------------------------
                                                                                                Year Ended December 31,
                                                                                     -------------------------------------------
                                                                                        2002             2001             2000
                                                                                        ----             ----             ----
                                                                                                   (in thousands)
<S>                                                                                  <C>              <C>              <C>
OPERATING ACTIVITIES:
  Net Income                                                                         $  7,552         $  7,875         $  7,984
  Adjustments for Noncash Items:
    Depreciation                                                                       22,560           22,423           22,162
    Deferred Income Taxes                                                              (5,028)          (6,224)          (5,842)
    Deferred Investment Tax Credits                                                    (3,361)          (3,414)          (3,396)
    Amortization of Deferred Gain on Sale and
      Leaseback - Rockport Plant Unit 2                                                (5,571)          (5,571)          (5,571)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable                                                                 4,037            1,224            1,392
    Fuel, Materials and Supplies                                                       (5,450)          (4,738)           6,486
    Accounts Payable                                                                    6,697           (4,597)         (13,157)
    Taxes Accrued                                                                      (2,450)            (216)             708
  Other Assets                                                                         (5,211)            (569)           1,636
  Other Liabilities                                                                    (2,295)          (1,244)            (404)
                                                                                     --------         --------         --------
            Net Cash Flows From Operating Activities                                   11,480            4,949           11,998
                                                                                     --------         --------         --------

INVESTING ACTIVITIES - Construction Expenditures                                       (5,298)          (6,868)          (5,190)
                                                                                     --------         --------         --------

FINANCING ACTIVITIES:
  Return of Capital to Parent Company                                                    -                -              (5,801)
  Change in Short-term Debt (net)                                                        -                -             (24,700)
  Change in Advances From Affiliates (net)                                             (4,015)           3,981           28,068
  Dividends Paid                                                                       (3,150)          (3,836)          (1,935)
                                                                                     --------         --------         --------
            Net Cash Flows From (Used For)
              Financing Activities                                                     (7,165)             145           (4,368)
                                                                                     --------         --------         --------

Net Increase (Decrease) in Cash and Cash Equivalents                                     (983)          (1,774)           2,440
Cash and Cash Equivalents January 1                                                       983            2,757              317
                                                                                     --------         --------         --------
Cash and Cash Equivalents December 31                                                $   -            $    983         $  2,757
                                                                                     ========         ========         ========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $2,019,000, $1,509,000 and
$3,531,000 and for income taxes was $7,884,000, $8,597,000 and $6,820,000 in
2002, 2001 and 2000, respectively.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>




AEP GENERATING COMPANY
Statements of Capitalization
- ----------------------------
                                                                                                              December 31,
                                                                                                              -----------
                                                                                                         2002             2001
                                                                                                         ----             ----
                                                                                                            (in thousands)
<S>                                                                                                    <C>               <C>
COMMON STOCK EQUITY (a)                                                                                $42,597           $38,195
                                                                                                       -------           -------

LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
 Series   Due Date
 1995 A,  2025 (c)                                                                                      22,500           22,500
 1995 B,  2025 (c)                                                                                      22,500           22,500
Unamortized Discount                                                                                      (198)            (207)
                                                                                                       -------          -------
  TOTAL LONG-TERM DEBT                                                                                  44,802           44,793
                                                                                                       -------          -------

TOTAL CAPITALIZATION                                                                                   $87,399          $82,988
                                                                                                       =======          =======

(a) In 2000, AEGCo returned capital to AEP in the amounts of $5.8 million. There
were no other material transactions affecting Common Stock and Paid-in Capital
in 2002, 2001 and 2000. (b) Installment purchase contracts were entered into in
connection with the issuance of pollution control revenue bonds by the City of
Rockport, Indiana. The terms of the installment purchase contracts require AEGCo
to pay amounts sufficient to enable the payment of interest and principal on the
related pollution control revenue bonds issued to refinance the construction
costs of pollution control facilities at the Rockport Plant.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001,
AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during 2001 and
averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a term rate of
4.05% for five years ending July 12, 2006.

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

</TABLE>



<PAGE>


AEP GENERATING COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------
The notes to AEGCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to AEGCo. The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference
                                                          ---------

Significant Accounting Policies                            Note  1

Effects of Regulation                                      Note  7

Commitments and Contingencies                              Note  9

Guarantees                                                 Note 10

Sustained Earnings Improvement Initiative                  Note 11

Business Segments                                          Note 16

Risk Management, Financial Instruments and Derivatives     Note 17

Income Taxes                                               Note 18

Leases                                                     Note 22

Lines of Credit and Sale of Receivables                    Note 23

Unaudited Quarterly Financial Information                  Note 24

Related Party Transactions                                 Note 29



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholder and Board of Directors
of AEP Generating Company:

We have audited the accompanying balance sheets and statements of capitalization
of AEP Generating Company as of December 31, 2002 and 2001, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2002. 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 financial statements present fairly, in all material
respects, the financial position of AEP Generating Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003


<PAGE>




AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
                                                                            Year Ended December 31,
                                                                            ----------------------
                                            2002                2001                2000             1999                  1998
                                            ----                ----                ----             ----                  ----
                                                                                 (in thousands)
<S>                                      <C>                <C>                 <C>                <C>                 <C>
INCOME STATEMENTS DATA:
  Operating Revenues                     $1,690,493         $1,738,837          $1,770,402         $1,482,475          $1,406,117
  Operating Expenses                      1,296,760          1,443,106           1,463,304          1,188,490           1,123,330
                                          ---------          ---------           ---------          ---------           ---------
  Operating Income                          393,733            295,731             307,098            293,985             282,787
  Nonoperating Items, Net                     8,079              5,324               7,235              8,113                 760
  Interest Charges                          125,871            116,268             124,766            114,380             122,036
                                            -------          ---------             -------            -------           ---------
  Income Before
   Extraordinary Item                       275,941            184,787             189,567            187,718             161,511
  Extraordinary Loss                           -                (2,509)               -                (5,517)               -
                                          ---------          ---------           ---------           --------           ---------
  Net Income                                275,941            182,278             189,567            182,201             161,511
  Preferred Stock
   Dividend
   Requirements                                 241                242                 241              6,931               6,901
  Gain (Loss) on
   Reacquired Preferred
   Stock                                          4               -                   -               (2,763)                -
                                          ---------          ---------           ---------           --------            --------

  Earnings Applicable
   To Common Stock                         $275,704           $182,036            $189,326           $172,507            $154,610
                                           ========           ========            ========           ========            ========

                                                                           Year Ended December 31,
                                                                           ----------------------
                                            2002               2001                2000                 1999                1998
                                            ----               ----                ----                 ----                ----
                                                                            (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                                 $5,625,736         $5,769,707          $5,592,444         $5,511,894          $5,336,191
  Accumulated
   Depreciation
   And Amortization                       2,405,492           2,446,027          2,297,189          2,247,225           2,072,686
                                          ---------          ----------          ---------          ---------           ---------
  Net Electric Utility
   Plant                                 $3,220,244           $3,323,68         $3,295,255         $3,264,669          $3,263,505
                                         ==========          ==========         ==========         ==========          ==========
  Total Assets                           $5,356,438          $4,893,030         $5,467,701         $4,847,857          $4,735,656
                                         ==========          ==========         ==========         ==========          ==========

  Common Stock and
   Paid-in Capital                         $187,898          $  573,903           $573,904           $573,904            $573,904
  Accumulated Other
   Comprehensive
   Income (Loss)                            (73,160)               -                  -                  -                   -
  Retained Earnings                         986,396             826,197            792,219            758,894             734,387
                                           -------          ----------            -------            -------             -------
  Total Common
   Shareholder's Equity                  $1,101,134          $1,400,100         $1,366,123         $1,332,798          $1,308,291
                                         ==========          ==========         ==========         ==========          ==========
  Preferred Stock                           $ 5,942          $    5,952            $ 5,951            $ 5,951            $163,188
                                            =======          ==========            =======            =======            ========

  CPL - Obligated,
   Mandatorily
   Redeemable Preferred
   Securities of
   Subsidiary Trust
   Holding Solely
   Junior Subordinated
   Debentures of CPL
                                           $136,250           $ 136,250           $148,500           $150,000            $150,000
                                           ========           =========           ========           ========            ========

  Long-term Debt (a)                     $1,438,565          $1,253,768         $1,454,559         $1,454,541          $1,350,706
                                         ==========          ==========         ==========         ==========          ==========

  Total Capitalization
   And Liabilities                       $5,356,438          $4,893,030         $5,467,701         $4,847,857          $4,735,656
                                         ==========          ==========         ==========         ==========          ==========

(a) Including portion due within one year.
</TABLE>


<PAGE>

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------


AEP Texas Central Company (TCC), formerly known as Central Power and Light
Company (CPL), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in southern Texas. TCC also
sells electric power at wholesale to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to its affiliated retail electric
provider (REP) in Texas.

Wholesale power marketing activities are conducted on TCC's behalf by AEPSC.
TCC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TCC submitted a plan for separation that was subsequently approved by the
PUCT. TCC has functionally separated its generation from its transmission and
distribution operations and AEP formed a separate affiliated REP. Pending
regulatory approval, TCC anticipates legally separating its generation from its
transmission and distribution operations (see Note 8). The affiliated REP, a
separate legal entity that was an AEP subsidiary (not owned by or consolidated
with TCC) was sold in December 2002 (see Note 12).

Since the affiliated REP is the electricity supplier to retail customers in the
ERCOT area, TCC sells its generation to the affiliated REP and other market
participants and provides transmission and distribution services to retail
customers of the REPs in the TCC service territory. As a result of the formation
of the affiliated REP, effective January 1, 2002, TCC no longer supplies
electricity directly to retail customers. The implementation of REPs as
suppliers to retail customers has caused a significant shift in TCC's sales as
described below under "Results of Operations."

In December 2002, AEP sold the affiliated REP to an unrelated third party who
assumed the obligations of the affiliated REP under the Texas Restructuring
Legislation (see Note 12). Prior to the sale during 2002 sales to the affiliated
REP were classified as Sales to AEP Affiliates. Subsequent to the sale,
transactions with the REP were classified as Wholesale Electricity or Energy
Delivery.

Results of Operations
- ---------------------

In 2002, Net Income increased $94 million or 51% primarily due to $262 million
of revenues associated with recognition of stranded costs in Texas offset in
part by losses associated with the commencement of customer choice in Texas
which resulted in the loss of customers and reduced prices (see Note 8). In
2001, Income Before Extraordinary Item decreased $5 million or 3%, primarily
resulting from a settlement of Texas municipal franchise fees and increased
Maintenance expenses.

Changes in Operating Revenues
- -----------------------------

                            Increase (Decrease)
                            From Previous Year
                           (dollars in millions)
                          ---------------------
                           2002              2001
                          Amount     %      Amount     %
                          ------     -      ------     -

Wholesale
  Electricity*         $(1,096.4)   (90)    $(29.9)    (2)
Energy  Delivery*           81.4     17       (5.6)    (1)
Sales to AEP
 Affiliates                966.7    N.M.       4.0     11
                         --------           ------
   Total                 $ (48.3)    (3)    $(31.5)    (2)
                         =======            ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

N.M. = Not Meaningful

In 2002, Wholesale Electricity revenues decreased as a result of the elimination
of TCC's retail electricity sales in the ERCOT region as of January 1, 2002 and
a decrease in wholesale power marketing margins offset in part by the
interchange cost reconstruction (ICR) adjustments (see Note 6). In 2001, the
decrease in Wholesale Electricity revenues was primarily attributable to
unfavorable wholesale power marketing and trading conditions.

In 2002, Sales to AEP Affiliates revenue increased primarily due to increased
revenues from the newly created affiliated REP. Although TCC sold electricity to
the affiliated REP instead of directly to retail customers, total revenues
decreased due to lower prices for power sold to the affiliated REP.

Additionally, delivery charges provided to the affiliated REP in 2002 are
classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were
classified as Energy Delivery revenue. Revenues for 2002 included $262 million
of revenues, associated with recognition of stranded costs in Texas (see Note
8). Energy Delivery revenue also included revenues received for securitized
assets beginning in 2002 (see Note 8).

Changes in Operating Expenses
- -----------------------------


                       Increase (Decrease)
                       From Previous Year
                      (dollars in millions)
                      ---------------------

                          2002               2001
                   Amount        %      Amount     %
                   ------        -      ------     -


Fuel              $(246.2)      (50)    $(58.8)   (11)
Purchased
 Power:
 Wholesale
 Electricity
                       83.5      65      (16.2)   (11)
AEP Affiliates        (35.3)    (60)      26.0     80
Other
Operation             (17.1)     (5)       1.7      1
Maintenance            (7.8)    (11)      10.7     18
Depreciation
 And
 Amortization
                       45.8      27      (10.4)    (6)
Taxes Other
 Than
 Income
 Taxes
                        4.6       5       14.4     19
Income
Taxes                  26.1      23       12.4     12
                    -------             ------
   Total            $(146.4)    (10)    $(20.2)    (1)
                    =======             ======



In 2002, the decrease in Fuel expense was due to a decrease in the average unit
cost of fuel and decreased generation. The decrease in Fuel expense in 2001 was
primarily due to a reduction in the average cost of fuel primarily from a
decline in natural gas prices. TCC used natural gas as fuel for 32% of its
generation in 2002. The nature of the natural gas market is such that both
long-term and short-term contracts are generally based on the current spot
market price. Changes in natural gas prices affect TCC's fuel expense; however,
they generally did not impact results of operations in 2001 and 2000 due to fuel
recovery mechanisms, which are no longer in place beginning with deregulation in
2002.

In 2002, the increase in Wholesale Electricity Purchased Power expense is due to
higher MWH purchases from the market where we could purchase power at prices
lower than our cost to produce. ICR adjustments also had the effect of
increasing Wholesale Electricity Purchased Power expense and decreasing AEP
Affiliates Purchased Power expense in 2002 (see Note 6).

In 2001, Purchased Power increased overall largely due to higher natural gas
prices. Although gas prices declined in 2001, they were higher during the first
half of 2001 when TCC was making most of its purchases.

In 2002, Other Operation expense decreased due primarily to the elimination of
factoring of accounts receivable and lower ERCOT transmission related expenses.

In 2002, Maintenance expense decreased due to two scheduled "18 month interval"
refueling outages for STP during 2001 that increased Maintenance expense above
the 2002 and 2000 levels. Also contributing to the decrease in 2002, and the
increase in 2001, was an increase in Maintenance expense for scheduled major
overhauls of four power plants in 2001.

In 2002, the increase in Depreciation and Amortization is attributable to the
amortization of regulatory assets that were securitized in the first quarter of
2002, offset by the elimination of excess earnings expense in 2002 under Texas
Restructuring Legislation (see Note 8).

In 2002, the increase in Taxes Other Than Income Taxes resulted primarily from
higher local franchise taxes, offset by one-time 2001 assessments and decreased
gross receipts tax, due to deregulation. In 2001, Taxes Other Than Income Taxes
increased due primarily to an increase in franchise related taxes, including a
settlement of disputed franchise fees, and a new tax levied by the PUCT, the
Texas System Benefit Fund Assessment.

In 2002, the increase in Income Taxes is due to an increase in pre-tax income
offset by changes in timing between book/tax accounting differences in state
income taxes. In 2001 the increase in Income Tax expense is primarily due to
adjustments associated with prior year tax returns and an increase in pre-tax
book income.

Other Changes
- -------------

In 2002, Nonoperating Income and Nonoperating Expenses increased significantly
as a result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties, offset in part by decreased
interest income. The revenues associated with the energy related construction
projects included in Nonoperating Income increased $34 million and $15 million
in 2002 and 2001. The expenses associated with these projects included in
Nonoperating Expenses increased $32 million and $14 million in 2002 and 2001.

In 2002, Nonoperating Income Tax Expense increased due to increases in pre-tax
non-operating income.

In 2002, Interest Charges increased primarily due to higher levels of
outstanding debt (see TCC's schedule of Long-term Debt and Consolidated
Statements of Capitalization for further information). In 2001, the decrease in
interest charges was attributable to lower average interest rates associated
with short-term and long-term debt.

Extraordinary Loss
- ------------------

The extraordinary loss on reacquired debt recorded in 2001 was the result of
reacquisition of installment purchase contracts for Matagorda County, Navigation
District, Texas.


Impairment
- ----------

As a result of TCC's recent ability to purchase electricity at a significantly
lower price than its current cost to generate electricity, TCC proposed in
September 2002 to "inactivate" various, high-cost gas fired generating
facilities. In the third quarter 2002, TCC recorded an impairment charge of
approximately $95.6 million (pre-tax) related to these plants and recorded
approximately $4.0 million (pre-tax) for severance charges. Both of these
charges were deferred and recorded in Regulatory Assets Designated for or
Subject to Securitization, to be included as a stranded cost in the Texas 2004
true-up proceeding (see Note 8). In the fourth quarter 2002 an additional
pre-tax charge of $21.6 million was recorded related to additional plant
impairments, fuel inventory and materials and supplies, and an additional $1.5
million pre-tax charge was recorded related to severance charges (see Note 13)
related to the "inactivated" plants. The entire $23.1 million was also deferred
and recorded in Regulatory Assets Designated for or Subject to Securitization.





<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
                                                                                               Year Ended December 31,
                                                                                 -------------------------------------------------
                                                                                       2002              2001              2000
                                                                                       ----              ----              ----
                                                                                                    (in thousands)
<S>                                                                              <C>                 <C>                <C>
OPERATING REVENUES:
  Wholesale Electricity                                                          $  127,502          $1,223,893         $1,253,836
  Energy Delivery                                                                   554,547             473,182            478,814
  Sales to AEP Affiliates                                                         1,008,444              41,762             37,752
                                                                                 ----------          ----------         ----------
     TOTAL OPERATING REVENUES                                                     1,690,493           1,738,837          1,770,402
                                                                                 ----------          ----------         ----------

OPERATING EXPENSES:
  Fuel                                                                              245,834             492,057            550,903
  Purchased Power:
    Wholesale Electricity                                                           211,358             127,816            144,021
    AEP Affiliates                                                                   23,406              58,641             32,591
  Other Operation                                                                   304,094             321,227            319,539
  Maintenance                                                                        63,392              71,212             60,528
  Depreciation and Amortization                                                     214,162             168,341            178,786
  Taxes Other Than Income Taxes                                                      95,500              90,916             76,477
  Income Taxes                                                                      139,014             112,896            100,459
                                                                                 ----------          ----------         ----------
    TOTAL OPERATING EXPENSES                                                      1,296,760           1,443,106          1,463,304
                                                                                 ----------          ----------         ----------

OPERATING INCOME                                                                    393,733             295,731            307,098

NONOPERATING INCOME                                                                  53,141              22,552              5,830

NONOPERATING EXPENSES                                                                41,910              17,626              3,668

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                              3,152                (398)            (5,073)

INTEREST CHARGES                                                                    125,871             116,268            124,766
                                                                                 ----------          ----------         ----------

INCOME BEFORE EXTRAORDINARY ITEM                                                    275,941             184,787            189,567

EXTRAORDINARY LOSS ON REACQUIRED DEBT (Net of Tax of $1,351,000 for 2001)              -                 (2,509)              -
                                                                                 ----------          ----------         ----------

NET INCOME                                                                          275,941             182,278            189,567

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                   241                 242                241

GAIN ON REACQUIRED PREFERRED STOCK                                                        4                -                  -
                                                                                 ----------          ----------         ----------

EARNINGS APPLICABLE TO COMMON STOCK                                              $  275,704          $  182,036         $  189,326
                                                                                 ==========          ==========         ==========


Consolidated Statements of Comprehensive Income
- -----------------------------------------------
                                                                                                Year Ended December 31,
                                                                                 ------------------------------------------------
                                                                                   2002                 2001               2000
                                                                                   ----                 ----               ----
                                                                                                   (in thousands)
NET INCOME                                                                         $275,941           $182,278            $189,567
OTHER COMPREHENSIVE INCOME (LOSS):
  Cash Flow Power Hedges                                                                (36)              -                   -
  Minimum Pension Liability                                                         (73,124)              -                   -
                                                                                   --------           --------            --------
COMPREHENSIVE INCOME                                                               $202,781           $182,278            $189,567
                                                                                   ========           ========            ========

The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.

</TABLE>

<PAGE>
<TABLE>
<CAPTION>

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------

                                                                                           Year Ended December 31,
                                                                              ---------------------------------------------
                                                                                2002              2001               2000
                                                                                ----              ----               ----
                                                                                             (in thousands)
<S>                                                                           <C>               <C>                <C>
BEGINNING OF PERIOD                                                           $826,197          $792,219           $758,894
NET INCOME                                                                     275,941           182,278            189,567

DEDUCTIONS (ADDITIONS):
  Capital Stock Gains                                                               (4)             -                  -
  Cash Dividends Declared:
    Common Stock                                                               115,505           148,057            156,000
    Preferred Stock                                                                241               242                241
  Other                                                                           -                    1                  1
                                                                              --------          --------           --------


BALANCE AT END OF PERIOD                                                      $986,396          $826,197           $792,219
                                                                              ========          ========           ========

The common stock of TCC is owned by a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------
                                                                                                            December 31,
                                                                                                            -----------
                                                                                                     2002                 2001
                                                                                                     ----                 ----
                                                                                                           (in thousands)
<S>                                                                                               <C>                 <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                                                      $2,903,942          $3,169,421
  Transmission                                                                                       698,964             663,655
  Distribution                                                                                     1,296,731           1,279,037
  General                                                                                            258,386             241,137
  Construction Work in Progress                                                                      200,947             169,075
  Nuclear Fuel                                                                                       266,766             247,382
                                                                                                     -------             -------
          Total Electric Utility Plant                                                             5,625,736           5,769,707
  Accumulated Depreciation and Amortization                                                        2,405,492           2,446,027
                                                                                                   ---------           ---------
          NET ELECTRIC UTILITY PLANT                                                               3,220,244           3,323,680
                                                                                                   ---------           ---------

OTHER PROPERTY AND INVESTMENTS                                                                         3,977              47,950
                                                                                                       -----              ------

SECURITIZED TRANSITION ASSETS                                                                        734,591                -
                                                                                                     -------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                      4,392              28,039
                                                                                                       -----              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                           85,420              10,909
  Accounts Receivable:
   General                                                                                           113,543              38,459
   Affiliated Companies                                                                              121,324               6,249
   Allowance for Uncollectible Accounts                                                                 (346)               (186)
  Fuel Inventory                                                                                      32,563              38,690
  Materials and Supplies                                                                              51,593              55,475
  Accrued Utility Revenues                                                                            27,150                -
  Energy Trading and Derivative Contracts                                                             22,493              34,480
  Prepayments and Other Current Assets                                                                 2,133               2,742
                                                                                                       -----               -----
          TOTAL CURRENT ASSETS                                                                       455,873             186,818
                                                                                                     -------             -------

REGULATORY ASSETS                                                                                    458,552             226,812
                                                                                                     -------             -------

REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION                                        336,444             959,294
                                                                                                     -------             -------

NUCLEAR DECOMMISSIONING TRUST FUND                                                                    98,474              98,600
                                                                                                      ------              ------

DEFERRED CHARGES                                                                                      43,891              21,837
                                                                                                      ------              ------

                    TOTAL ASSETS                                                                  $5,356,438          $4,893,030
                                                                                                  ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES

                                                                                                                December 31,
                                                                                                                -----------
                                                                                                        2002                  2001
                                                                                                        ----                  ----
                                                                                                               (in thousands)
<S>                                                                                                  <C>                  <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
    Outstanding - 2,211,678 Shares at December 31, 2002 6,755,535 Shares at
    December 31, 2001                                                                                $   55,292           $  168,888
  Paid-in Capital                                                                                       132,606              405,015
  Accumulated Other Comprehensive Income (Loss)                                                         (73,160)                -
  Retained Earnings                                                                                     986,396              826,197
                                                                                                      ---------            ---------
    Total Common Shareholder's Equity                                                                 1,101,134            1,400,100
  Preferred Stock                                                                                         5,942                5,952
  CPL - Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely
   Junior Subordinated Debentures of CPL                                                                136,250              136,250

Long-term Debt                                                                                        1,209,434              988,768
                                                                                                      ---------              -------
          TOTAL CAPITALIZATION                                                                        2,452,760            2,531,070
                                                                                                      ---------            ---------

OTHER NONCURRENT LIABILITIES                                                                             74,572               10,905
                                                                                                      ---------            ---------

CURRENT LIABILITIES:
  Short-term Debt - Affiliates                                                                          650,000                 -
  Long-term Debt Due Within One Year                                                                    229,131              265,000
  Advances from Affiliates (net)                                                                        126,711              354,277
  Accounts Payable - General                                                                             72,199               65,307
  Accounts Payable - Affiliated Companies                                                                36,242               49,301
  Customer Deposits                                                                                         666               26,744
  Taxes Accrued                                                                                          24,791               83,512
  Interest Accrued                                                                                       51,205               23,715
  Energy Trading and Derivative Contracts                                                                19,811               40,987
  Other                                                                                                  36,698               18,076
                                                                                                         ------               ------

          TOTAL CURRENT LIABILITIES                                                                   1,247,454              926,919
                                                                                                      ---------              -------

DEFERRED INCOME TAXES                                                                                 1,261,252            1,163,795
                                                                                                      ---------            ---------

DEFERRED INVESTMENT TAX CREDITS                                                                         117,686              122,892
                                                                                                        -------              -------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                         1,713               17,675
                                                                                                          -----               ------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                             201,001              119,774
                                                                                                        -------              -------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                             $5,356,438           $4,893,030
                                                                                                     ==========           ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
                                                                                                  Year Ended December 31,
                                                                                       -------------------------------------------
                                                                                       2002               2001               2000
                                                                                       ----               ----               ----
                                                                                                    (in thousands)
<S>                                                                                   <C>               <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                                                          $275,941          $182,278          $189,567
  Adjustments to Reconcile Net Income to Net Cash Flows from Operating
   Activities:
    Depreciation and Amortization                                                      214,162           168,341           178,786
    Extraordinary Loss on Reacquired Debt                                                 -                2,509              -
    Deferred Income Taxes                                                              113,655           (72,568)           16,263
    Deferred Investment Tax Credits                                                     (5,206)           (5,208)           (5,207)
    Mark-toMarket Energy Trading and Derivative Contracts                               (1,558)          (12,048)            8,191
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                         (189,999)           52,862           (32,902)
    Fuel, Materials and Supplies                                                        (4,899)          (18,215)            8,680
    Interest Accrued                                                                    27,490            (2,502)           11,494
    Accrued Utility Revenues                                                           (27,150)             -                 -
    Accounts Payable                                                                    (6,167)          (55,311)           45,873
    Taxes Accrued                                                                      (58,721)           27,986            14,405
  Fuel Recovery                                                                         16,455           179,866           (96,872)
  Transmission Coordination Agreement Settlement                                          -                 -               15,519
  Texas Wholesale Clawback (see Note 7)                                               (262,000)             -                 -
  Change in Other Assets                                                                  (534)           10,767               589
  Change in Other Liabilities                                                           56,024            11,163            12,243
                                                                                      --------          --------          --------
            Net Cash Flows From Operating Activities                                   147,493           469,920           366,629
                                                                                      --------          --------          --------

INVESTING ACTIVITIES:
  Construction Expenditures                                                           (151,645)         (193,732)         (199,484)
  Proceeds From Sales of Property and Other                                                143              (354)             -
                                                                                      --------          --------          --------
            Net Cash Flows Used For Investing
             Activities                                                               (151,502)         (194,086)         (199,484)
                                                                                      --------          --------          --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                                           797,335           260,162           149,248
  Change in Short-term Debt Affiliate (Net)                                            650,000              -                 -
  Retirement of Common Stock                                                          (386,005)             -                 -
  Retirement of Preferred Stock                                                             (6)             -                 -
  Retirement of Long-term Debt                                                        (639,492)         (475,606)         (151,440)
  Change in Advances from Affiliates (net)                                            (227,566)           84,565           (52,446)
  Special Deposit for Reacquisition of Long-term Debt                                     -                 -               50,000
  Dividends Paid on Common Stock                                                      (115,505)         (148,057)         (156,000)
  Dividends Paid on Cumulative Preferred Stock                                            (241)             (242)             (249)
                                                                                      --------          --------          --------
            Net Cash Flows From (Used For)
             Financing Activities                                                       78,520          (279,178)         (160,887)
                                                                                      --------          --------          --------

Net Increase (Decrease) in Cash and Cash     Equivalents
                                                                                        74,511            (3,344)            6,258
Cash and Cash Equivalents January 1                                                     10,909            14,253             7,995
                                                                                      --------          --------          --------
Cash and Cash Equivalents December 31                                                 $ 85,420          $ 10,909          $ 14,253
                                                                                      ========          ========          ========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $93,120,000, $109,835,000 and $110,010,000 and
for income taxes was $95,600,000, $161,529,000 and $48,141,000 in 2002, 2001 and
2000,respectively.

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>

AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------
                                                                                       December 31,
                                                                                        -----------
                                                                                   2002             2001
                                                                                   ----             ----
                                                                                      (in thousands)
<S>                                                                            <C>               <C>
COMMON SHAREHOLDER'S EQUITY (a)                                                $1,101,134        $1,400,100
                                                                               ----------        ----------

PREFERRED STOCK - 3,035,000 authorized shares, $100 par value

Not Subject to Mandatory Redemption:

            Call Price                                           Shares
           December 31,      Number of Shares Redeemed        Outstanding
Series         2002            Year Ended December 31,     December 31, 2002
- ------     ------------     ----------------------------   -----------------
                              2002      2001      2000
                              ----      ----      ----

4.00%        $105.75          100        -         -           41,938               4,194             4,204
4.20%         103.75           -         -         -           17,476               1,748             1,748
                                                                               ----------        ----------
  Total Preferred Stock                                                             5,942             5,952
                                                                               ----------        ----------

TRUST PREFERRED SECURITIES:

 TCC-obligated, mandatorily redeemable preferred
 securities of subsidiary trust holding solely
 Junior Subordinated Debentures of TCC, 8.00%,
 due April 30, 2037                                                               136,250           136,250
                                                                               ----------        ----------

LONG-TERM (See Schedule of Long-term Debt):

First Mortgage Bonds                                                              152,353           614,200
Securitization Bonds  (a)                                                         796,635              -
Installment Purchase Contracts                                                    489,577           489,568
Senior Unsecured Notes                                                               -              150,000
Less Portion Due Within One year                                                 (229,131)         (265,000)
                                                                               ----------        ----------

Long-term Debt Excluding Portion Due Within One Year                            1,209,434           988,768
                                                                               ----------        ----------

     TOTAL CAPITALIZATION                                                      $2,452,760        $2,531,070
                                                                               ==========        ==========

(a) In February 2002, TCC issued securitization bonds.  $386 million of the proceeds was used to retire 4,543,857 shares of
common stock.

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

</TABLE>

<PAGE>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------


First mortgage bonds outstanding were as follows:

                                         December 31,
                                       2002       2001
                                       ----       ----
                                       (in thousands)
% Rate Due
7.25  2004 - October 1              $ 27,400  $100,000
7.50  2002 - December 1                    -   115,000
6-7/8 2003 - February 1               16,418    49,200
7-1/8 2008 - February 1               18,581    75,000
7.50  2023 - April 1                  17,996    75,000
6-5/8 2005 - July 1                   71,958   200,000
                                    --------  --------
  Total                             $152,353  $614,200
                                    ========  ========

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.

Securitization Bonds outstanding were as follows:

                              December 31,
                           ------------------
        Final               2002       2001
                            ----       ----
       Payment   Maturity   (in thousands)
Rate    Date       Date
- ----  ---------  ------------
3.54  1/15/2005  1/15/2007  $128,950  $ -
5.01  1/15/2008  1/15/2010   154,507    -
5.56  1/15/2010  1/15/2012   107,094    -
5.96  7/15/2013  7/15/2015   214,927    -
6.25  1/15/2016  1/15/2017   191,857    -
Unamortized Discount            (700)   -
                            --------  -----
            Total           $796,635  $ -
                            ========  =====

In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of
TCC, issued $797 million of Securitization Bonds, Series 2002-1. The
Securitization Bonds mature at different times through 2017 and have a weighted
average interest rate of 5.4 percent.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:


                                      December 31,
                                    2002        2001
                                    ----        ----
                                    (in thousands)
% Rate Due
Matagorda County
 Navigation District,
 Texas:
6.00  2028    - July 1           $120,265   $120,265
6-1/8 2030    - May 1              60,000     60,000
3.75  2030(a) - May 1             111,700    111,700
4.00  2030(a) - May 1              50,000     50,000
4.55  2029(a) - Nov 1             100,635    100,635

Guadalupe-Blanco
 River Authority
 District, Texas:
(b)  2015 - November 1             40,890     40,890

Red River Authority
 District, Texas:
6.00  2020 - June 1                 6,330      6,330
Unamortized Discount                 (243)      (252)
                                 --------   --------
  Total                          $489,577   $489,568
                                 ========   ========

(a)Installment Purchase Contract provides for bonds to be tendered in 2003 for
3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these
installment purchase contracts have been classified for payments in those years.
(b) A floating interest rate is determined monthly. The rate on December 31,
2002 was 1.7%.

Under the terms of the installment purchase contracts, TCC is required to pay
amounts sufficient to enable the payment of interest on and the principal (at
stated maturities and upon mandatory redemptions) of related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior unsecured notes outstanding were as follows:

                                          December 31,
                                       2002        2001
                                       ----        ----
                                     (in thousands)
% Rate Due

2002 - February 22 (c)                $ -     $150,000
                                      ------  --------
  Total                               $ -     $150,000
                                      ======  ========

(c) A floating interest rate is determined monthly. The rate on December 31,
2001 was 2.56%.



At December 31, 2002, future annual long-term debt payments are as follows:

                                            Amount
                                            ------
                                        (in thousands)
2003                                       $229,131
2004                                         75,951
2005                                        121,937
2006                                        152,900
2007                                         52,729
Later Years                                 806,860
                                         ----------
  Total Principal Amount                  1,439,508
Unamortized Discount                           (943)
                                         ----------
    Total                                $1,438,565

See Note 25 for discussion of the Trust Preferred Securities issued by a wholly
owned statutory business trust of TCC.


<PAGE>


AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------

The notes to TCC's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to TCC. 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  4

Rate Matters                                              Note  6

Effects of Regulation                                     Note  7

Customer Choice and Industry Restructuring                Note  8

Commitments and Contingencies                             Note  9

Guarantees                                                Note 10

Sustained Earnings Improvement Initiative                 Note 11

Acquisitions, Dispositions and Discontinued Operations    Note 12

Asset Impairment and Investment Value Losses              Note 13

Benefit Plans                                             Note 14

Business Segments                                         Note 16

Risk Management, Financial Instruments and Derivatives    Note 17

Income Taxes                                              Note 18

Leases                                                    Note 22

Lines of Credit and Sale of Receivables                   Note 23

Unaudited Quarterly Financial Information                 Note 24

Trust Preferred Securities                                Note 25

Jointly Owned Electric Utility Plant                      Note 28

Related Party Transactions                                Note 29




<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors
of AEP Texas Central Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of AEP Texas Central Company and subsidiaries as of
December 31, 2002 and 2001, 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, 2002. 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 AEP Texas Central Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003



<PAGE>

                             AEP TEXAS NORTH COMPANY
<TABLE>
<CAPTION>

AEP TEXAS NORTH COMPANY
Selected Financial Data
- -----------------------

                                                                               Year Ended December 31,
                                                                              ------------------------
                                                2002                2001              2000              1999              1998
                                                ----                ----              ----              ----              ----
                                                                                   (in thousands)
<S>                                         <C>                   <C>               <C>              <C>                <C>
INCOME STATEMENTS DATA:
  Operating Revenues                        $  450,740            $556,458          $571,064         $445,709           $424,953
  Operating Expenses                           442,869             523,068           518,723          391,910            365,677
                                            ----------            --------          --------         --------           --------
  Operating Income                               7,871              33,390            52,341           53,799             59,276
  Nonoperating Items, Net                         (703)              2,195            (1,675)           2,488              2,712
  Interest Charges                              20,845              23,275            23,216           24,420             24,263
                                            ----------            --------          --------         --------           --------
  Income (Loss) Before
   Extraordinary Item                          (13,677)             12,310            27,450           31,867             37,725
  Extraordinary Loss                              -                    -                -              (5,461)              -
                                            ----------            --------          --------         --------           --------
  Net Income (Loss)                            (13,677)             12,310            27,450           26,406             37,725
  Preferred Stock
   Dividend Requirements                           104                 104               104              104                104
                                            ----------            --------          --------         --------           --------
  Earnings (Loss) Applicable to
   Common Stock                             $  (13,781)           $ 12,206          $ 27,346         $ 26,302           $ 37,621
                                            ==========            ========          ========         ========           ========



                                                                                   December 31,
                                                                                   -----------
                                              2002                2001               2000               1999             1998
                                              ----                ----               ----               ----             ----
                                                                                  (in thousands)
BALANCE SHEETS DATA:
  Electric Utility Plant                    $1,201,747          $1,260,872        $1,229,339       $1,182,544         $1,146,582
  Accumulated
   Depreciation and
   Amortization                                521,792             546,162           515,041          495,847            473,503
                                            ----------          ----------        ----------       ----------         ----------
  Net Electric Utility
   Plant                                      $679,955            $714,710          $714,298         $686,697           $673,079
                                              ========            ========          ========         ========           ========

  Total Assets                                $877,175          $  864,875        $1,087,504         $861,205           $819,446
                                              ========          ==========        ==========         ========           ========

  Common Stock and
   Paid-in Capital                            $139,565            $139,565          $139,565         $139,565           $139,565
  Accumulated Other Comprehensive
    Income (Loss)                              (30,763)               -                 -                -                  -
  Retained Earnings                             71,942             105,970           122,588          113,242            114,940
                                             ---------          ----------        ----------       ----------         ----------
  Total Common
   Shareholder's Equity                       $180,744            $245,535          $262,153         $252,807           $254,505
                                              ========            ========          ========         ========           ========

  Cumulative Preferred Stock:
   Not Subject to
    Mandatory Redemption                        $2,367             $ 2,367           $ 2,367          $ 2,367            $ 2,368
                                                ======             =======           =======          =======            =======
  Long-term Debt (a)                          $132,500            $255,967          $255,843         $303,686           $303,518
                                              ========            ========          ========         ========           ========

  Total Capitalization
   And Liabilities                            $877,175          $  864,875        $1,087,504         $861,205           $819,446
                                              ========          ==========        ==========         ========           ========

(a) Including portion due within one year.

</TABLE>


<PAGE>


AEP TEXAS NORTH COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------


AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. TNC
also sells electric power at wholesale to other utilities, municipalities, rural
electric cooperatives and beginning in 2002 to its affiliated retail electric
provider (REP) in Texas.

Wholesale power marketing activities are conducted on TNC's behalf by AEPSC.
TNC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in
both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the
majority of its operations being in the ERCOT territory.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TNC submitted a plan for separation that was subsequently approved by the
PUCT. TNC has functionally separated its generation from its transmission and
distribution operations and AEP formed a separate affiliated REP. Pending
regulatory approval, TNC anticipates legally separating its generation from its
transmission and distribution operations (see Note 8). The affiliated REP, a
separate legal entity that was an AEP subsidiary (not owned by or consolidated
with TNC) was sold in December 2002 (see Note 12).

Since the affiliated REP is the electricity supplier to retail customers in the
ERCOT area, TNC sells its generation to the affiliated REP and other market
participants and provides transmission and distribution services to retail
customers of the REPs in the TNC service territory. As a result of the formation
of the affiliated REP, effective January 1, 2002, TNC no longer supplies
electricity directly to retail customers. The implementation of REPs as
suppliers to retail customers has caused a significant shift in TNC's sales as
described below under "Results of Operations."

In December 2002, AEP sold the affiliated REP to an unrelated third party, who
assumed the obligations of the affiliated REP under the Texas Restructuring
Legislation (see Note 12). Prior to the sale, during 2002, sales to the
affiliated REP were classified as Sales to AEP Affiliates. Subsequent to the
sale, transactions with the REP will be classified as Wholesale Electricity or
Energy Delivery.

Results of Operations
- ---------------------

In 2002, Net Income decreased $26.0 million or 211% primarily due to a $38.1
million long-lived asset impairment charge ($24.8 million net of tax) related to
the inactivation of inefficient gas fired plants (see Note 13) and a $4.7
million impairment charge ($3.1 million net of tax) related to the abandonment
of a wind-powered generation facility (see Note 13).

Changes in Operating Revenues
- -----------------------------

   Increase (Decrease) From Previous Year
   --------------------------------------

                               (in millions)       %

Wholesale  Electricity*          $(231.7)        (63)
Energy Delivery*                   (95.7)        (57)
Sales to AEP
 Affiliates                        221.7         N.M.
                                 -------
   Total                         $(105.7)        (19)
                                 =======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

N.M. =  Not Meaningful

Wholesale Electricity revenues decreased as a result of the elimination of TNC's
retail electricity sales in the ERCOT region as of January 1, 2002 and a
decrease in wholesale power marketing margins, partially offset by the ICR
adjustments (see Note 6).

Sales to AEP Affiliates increased primarily due to increased revenues from the
newly created affiliated REP. Although TNC sold electricity to the affiliated
REP instead of directly to retail customers in the ERCOT region, total revenues
decreased due to lower prices for power sold to the affiliated REP.

Additionally, delivery charges provided to the affiliated REP in 2002 are
classified as Sales to AEP Affiliates in 2002, whereas in 2001 they were
classified as Energy Delivery revenue.

Changes in Operating Expenses
- -----------------------------

   Increase (Decrease) From Previous Year
   --------------------------------------

                                (in millions)      %


Fuel                               $(76.7)        (43)
Purchased Power:
 Wholesale Electricity               10.0          14
 AEP Affiliates                     (19.1)        (34)
Other Operation                      (6.3)         (6)
Asset Impairments                    42.9         N.M.
Maintenance                           -            -
Depreciation and
 Amortization                        (7.1)        (14)
Taxes Other
 Than Income Taxes                   (5.8)        (21)
Income Taxes                        (18.1)        N.M.
                                    -----
   Total                           $(80.2)        (15)
                                   ======

N.M. = Not Meaningful

Fuel expense decreased due to a decrease in the average unit cost of fuel and
decreased generation required due to decreased energy sales. TNC used natural
gas as fuel for 42% of its generation in 2002. The nature of the natural gas
market is such that both long-term and short-term contracts are generally based
on the current spot market price. Changes in natural gas prices affect TNC's
fuel expense; however, they generally did not impact results of operations in
2001 due to fuel recovery mechanisms, which are no longer in place beginning
with deregulation in 2002.

The net decline in total Purchased Power expense in 2002 was mainly due to both
reduced MWHs purchased and reduced prices, partially offset by ICR adjustments
(see Note 6).

Other Operation expense decreased slightly in 2002 due to lower factoring and
transmission expenses, offset in part by a $1.4 million write-down of material
and supply inventory associated with the impaired plants.

As a result of TNC's recent ability to purchase electricity at a significantly
lower price than its current cost to generate electricity, TNC proposed in
September 2002 to "inactivate" various, high-cost gas fired generating
facilities. TNC recorded an impairment charge in the third quarter 2002 of
approximately $34.2 million related to these plants, which was recorded in Asset
Impairments expense. In the fourth quarter 2002, an additional asset impairments
charge of $3.9 million was also recorded in connection with these plants, along
with a $4.7 million charge for a wind-powered generation facility (see Note 13).
Additionally, a $1.2 million charge associated with fuel inventory (recorded in
Fuel) and a $1.4 million charge associated with materials and supplies (recorded
in Other Operations) was recorded in the fourth quarter of 2002 related to the
"inactivated" plants.

Depreciation and Amortization expense decreased due to the elimination in 2002
of excess earnings expense under Texas Restructuring Legislation and the
elimination of regulatory asset amortization that ended in 2001.

The decrease in Taxes Other Than Income Taxes is primarily a result of one time
2001 assessments and a decrease in the gross receipts tax due to deregulation.

The decrease in Income Taxes is primarily a result of a decrease in pre-tax
income resulting from the impairment of various generating facilities.


Other Changes

Nonoperating Income and Nonoperating Expenses increased significantly as a
result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties, offset in part by decreased
interest income. The revenues associated with the aforementioned energy related
construction projects included in Nonoperating Income increased $45.5 million in
2002. The expenses associated with these projects included in Nonoperating
Expenses increased $43.0 million in 2002.

Interest Charges declined primarily due to lower interest rates.


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS NORTH COMPANY
Statements of Operations
- ------------------------

                                                                                             Year Ended December 31,
                                                                             -------------------------------------------------------
                                                                                  2002                2001              2000
                                                                                  ----                ----              ----
                                                                                                 (in thousands)
<S>                                                                             <C>                 <C>               <C>
OPERATING REVENUES:
  Wholesale Electricity                                                         $136,962            $368,741          $376,206
  Energy Delivery                                                                 73,353             169,036           176,204
  Sales to AEP Affiliates                                                        240,425              18,681            18,654
                                                                                --------            --------          --------
            TOTAL OPERATING REVENUES                                             450,740             556,458           571,064
                                                                                --------            --------          --------

OPERATING EXPENSES:
  Fuel                                                                           100,466             177,140           183,154
  Purchased Power:
    Wholesale Electricity                                                         80,391              70,395            68,080
    AEP Affiliates                                                                37,582              56,656            57,773
  Other Operation                                                                104,960             111,248            93,078
  Asset Impairments                                                               42,898                -                 -
  Maintenance                                                                     22,295              22,343            21,241
  Depreciation and Amortization                                                   43,620              50,705            55,172
  Taxes Other Than Income Taxes                                                   22,471              28,319            25,321
  Income Tax Expense (Credit)                                                    (11,814)              6,262            14,904
                                                                                --------            --------          --------
            TOTAL OPERATING EXPENSES                                             442,869             523,068           518,723
                                                                                --------            --------          --------

OPERATING INCOME                                                                   7,871              33,390            52,341

NONOPERATING INCOME                                                               53,763              12,199             9,530

NONOPERATING EXPENSES                                                             54,755              10,695            12,664

NONOPERATING INCOME TAX CREDIT                                                      (289)               (691)           (1,459)

INTEREST CHARGES                                                                  20,845              23,275            23,216
                                                                                --------            --------          --------

NET INCOME (LOSS)                                                                (13,677)             12,310            27,450

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                104                 104               104
                                                                                --------            --------          --------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                                      $(13,781)           $ 12,206          $ 27,346
                                                                                ========            ========          ========


Statements of Comprehensive Income

                                                                                             Year Ended December  31,
                                                                                ----------------------------------------------
                                                                                  2002                2001               2000
                                                                                  ----                ----               ----

NET INCOME (LOSS)                                                               $(13,677)            $12,310           $27,450

OTHER COMPREHENSIVE INCOME (LOSS):
  Cash Flow Power Hedges                                                             (15)               -                 -
  Minimum Pension Liability                                                      (30,748)               -                 -
                                                                                --------             -------           -------
COMPREHENSIVE INCOME (LOSS)                                                     $(44,440)            $12,310           $27,450
                                                                                ========             =======           =======


The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>

AEP TEXAS NORTH COMPANY
Statements of Retained Earnings
- -------------------------------

                                                                                         Year Ended December  31,
                                                                            ----------------------------------------------
                                                                             2002                 2001              2000
                                                                             ----                 ----              ----
                                                                                             (in thousands)
<S>                                                                         <C>                 <C>               <C>
BEGINNING OF PERIOD                                                         $105,970            $122,588          $113,242

NET INCOME (LOSS)                                                            (13,677)             12,310            27,450

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                                              20,247              28,824            18,000
    Preferred Stock                                                              104                 104               104
                                                                            --------            --------          --------

BALANCE AT END OF PERIOD                                                    $ 71,942            $105,970          $122,588
                                                                            ========            ========          ========

The common stock of TNC is owned by a wholly owned subsidiary of AEP. See notes
to Financial Statements beginning on page L-1.

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS NORTH COMPANY
Balance Sheets
- --------------

                                                                                                                December 31,
                                                                                                         2002               2001
                                                                                                         ----               ----
                                                                                                              (in thousands)
<S>                                                                                                  <C>                 <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                                                         $  353,087          $  443,508
  Transmission                                                                                          254,483             250,023
  Distribution                                                                                          445,486             431,969
  General                                                                                               111,679             112,797
  Construction Work in Progress                                                                          37,012              22,575
                                                                                                     ----------          ----------
          Total Electric Utility Plant                                                                1,201,747           1,260,872
  Accumulated Depreciation and Amortization                                                             521,792             546,162
                                                                                                     ----------          ----------
          NET ELECTRIC UTILITY PLANT                                                                    679,955             714,710
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                            1,213              24,933
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                         2,248               8,327
                                                                                                     ----------          ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                               1,219               2,454
  Accounts Receivable:
   Customers                                                                                             62,660              18,720
   Affiliated Companies                                                                                  43,632               8,656
   Allowance for Uncollectible Accounts                                                                  (5,041)               (196)
  Fuel Inventory                                                                                         12,677               8,307
  Materials and Supplies                                                                                  9,574              11,190
  Accrued Utility Revenues                                                                                6,829                -
  Energy Trading and Derivative Contracts                                                                 4,130              10,240
  Prepayments and Other                                                                                   1,070                 966
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          136,750              60,337
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                        45,097              54,122
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         11,912               2,446
                                                                                                     ----------          ----------

                    TOTAL ASSETS                                                                     $  877,175          $  864,875
                                                                                                     ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS NORTH COMPANY

                                                                                                                December 31,
                                                                                                          2002               2001
                                                                                                          ----               ----
                                                                                                              (in thousands)
<S>                                                                                                    <C>                  <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 7,800,000 Shares
    Outstanding - 5,488,560 Shares                                                                     $137,214             $137,214
  Paid-in Capital                                                                                         2,351                2,351
  Accumulated Other Comprehensive Income (Loss)                                                         (30,763)                -
  Retained Earnings                                                                                      71,942              105,970
                                                                                                       --------             --------
    Total Common Shareholder's Equity                                                                   180,744              245,535
  Cumulative Preferred Stock
    Not Subject to Mandatory Redemption                                                                   2,367                2,367
  Long-term Debt                                                                                        132,500              220,967
                                                                                                       --------             --------
          TOTAL CAPITALIZATION                                                                          315,611              468,869
                                                                                                       --------             --------

OTHER NONCURRENT LIABILITIES                                                                             28,861                6,296
                                                                                                       --------             --------

CURRENT LIABILITIES:
  Short-term Debt - Affiliates                                                                          125,000                 -
  Long-term Debt Due Within One Year                                                                       -                  35,000
  Advances from Affiliates                                                                               80,407               50,448
  Accounts Payable - General                                                                             32,714               33,782
  Accounts Payable - Affiliated Companies                                                                76,217               11,388
  Customer Deposits                                                                                         117                4,191
  Taxes Accrued                                                                                           3,697               17,358
  Interest Accrued                                                                                        2,776                4,762
  Energy Trading and Derivative Contracts                                                                 3,801               12,402
  Other                                                                                                  17,414                9,824
                                                                                                       --------             --------
          TOTAL CURRENT LIABILITIES                                                                     342,143              179,155
                                                                                                       --------             --------

DEFERRED INCOME TAXES                                                                                   117,521              145,049
                                                                                                       --------             --------

DEFERRED INVESTMENT TAX CREDITS                                                                          21,510               22,781
                                                                                                       --------             --------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                           557                5,250
                                                                                                       --------             --------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                              50,972               37,475
                                                                                                       --------             --------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                               $877,175             $864,875
                                                                                                       ========             ========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                            AEP TEXAS NORTH COMPANY
                            Statements of Cash Flows
                            ------------------------

                                                                                                 Year Ended December 31,
                                                                                    ----------------------------------------------
                                                                                      2002               2001              2000
                                                                                      ----               ----              ----
                                                                                                    (in thousands)
<S>                                                                                   <C>               <C>               <C>
OPERATING ACTIVITIES:
  Net Income (Loss)                                                                   $(13,677)         $ 12,310          $ 27,450
  Adjustments to Reconcile Net Income to Net Cash Flows From Operating
   Activities:
    Depreciation and Amortization                                                       43,620            50,705            55,172
    Writedown of Utility Assets                                                         38,154              -
    Writedown of Wind Farm Assets                                                        4,744              -                 -
    Deferred Income Taxes                                                              (12,275)          (11,891)            8,164
    Deferred Investment Tax Credits                                                     (1,271)           (1,271)           (1,271)
    Mark-to-Market Energy Trading and Derivative Contracts                              (1,127)           (3,506)            2,590
  CHANGES IN CERTAIN CURRENT ASSETS AND LIABILITIES:
      Accounts Receivable (net)                                                        (74,071)           24,844            (1,445)
      Fuel, Materials and Supplies                                                      (2,754)            3,187             8,478
      Accrued Utility Revenues                                                          (6,829)             -                 -
      Accounts Payable                                                                  63,761           (42,604)           28,393
      Taxes Accrued                                                                    (13,661)           (1,543)            6,443
  Fuel Recovery                                                                         14,169            32,505           (53,841)
  Transmission Coordination Agreement Settlement                                          -                 -               15,465
  Change in Other Assets                                                               (16,928)           (1,432)            2,549
  Change in Other Liabilities                                                           16,514            11,056            (3,869)
                                                                                      --------          --------          --------
            Net Cash Flows From Operating Activities                                    38,369            72,360            94,278
                                                                                      --------          --------          --------

INVESTING ACTIVITIES:
  Construction Expenditures                                                            (43,563)          (39,662)          (64,477)
  Sales Proceeds and Other                                                                 150              (127)             -
                                                                                      --------          --------          --------
            Net Cash Used For Investing Activities                                     (43,413)          (39,789)          (64,477)
                                                                                      --------          --------          --------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt                                                        (130,799)             -              (48,000)
  Change in Short-term Debt Affiliated (net)                                           125,000              -                 -
  Change in Advances from Affiliates (net)                                              29,959            (8,130)           37,170
  Dividends Paid on Common Stock                                                       (20,247)          (28,824)          (18,000)
  Dividends Paid on Cumulative Preferred Stock                                            (104)             (104)             (104)
                                                                                      --------          --------          --------
            Net Cash Flows From (Used For) Financing Activities                          3,809           (37,058)          (28,934)
                                                                                      --------          --------          --------

Net Increase (Decrease) in Cash and Cash Equivalents                                    (1,235)           (4,487)              867
Cash and Cash Equivalents at Beginning of Period                                         2,454             6,941             6,074
                                                                                      --------          --------          --------
Cash and Cash Equivalents at End of Period                                            $  1,219            $2,454            $6,941
                                                                                      ========            ======            ======

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,934,000
$19,279,000 and $19,088,000 and for income taxes was $15,544,000, $21,997,000
and ($906,000) in 2002, 2001 and 2000 respectively.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


AEP TEXAS NORTH COMPANY
Statements of Capitalization
- ----------------------------
                                                                                        December 31,
                                                                                   2002              2001
                                                                                   ----              ----
                                                                                       (in thousands)
<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $180,744          $245,535
                                                                                 --------          --------

PREFERRED STOCK: $100 par value - authorized shares 810,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2002            Year Ended December 31,       December 31, 2002
- ------     ------------     ----------------------------     -----------------
                              2002      2001      2000
                              ----      ----      ----

Not Subject to Mandatory Redemption:

 4.40%       $107               -        -          1              23,672           2,367             2,367

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                               88,190           211,657
Installment Purchase Contracts                                                     44,310            44,310
Less Portion Due Within One Year                                                     -              (35,000)
                                                                                 --------          --------

Long-term Debt Excluding Portion Due Within One Year                              132,500           220,967
                                                                                 --------          --------

  TOTAL CAPITALIZATION                                                           $315,611          $468,869
                                                                                 ========          ========

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


</TABLE>


<PAGE>


AEP TEXAS NORTH COMPANY
Schedule of Long-term Debt
- --------------------------


First mortgage bonds outstanding were as follows:

                             December 31,
                             -----------
                           2002       2001
                           ----       ----
                           (in thousands)
% Rate Due
6-7/8  2002 - October 1  $  -       $ 35,000
7      2004 - October 1   18,469      40,000
6-1/8  2004 - February 1  24,036      40,000
6-3/8  2005 - October 1   37,609      72,000
7-3/4  2007 - June 1       8,151      25,000
Unamortized Discount         (75)       (343)
                         -------    --------
                         $88,190    $211,657

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
Red River Authority
 of Texas:
6.00   2020 - June 1      $44,310    $44,310
                          =======    =======



Under the terms of the installment purchase contracts, TNC is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

At December 31, 2002, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                        $   -
2004                          42,505
2005                          37,609
2006                            -
2007                           8,151
Later Years                   44,310
                            --------
Principal Amount             132,575
Less: Unamortized Discount       (75)
                            --------
    Total                   $132,500





<PAGE>




AEP TEXAS NORTH COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------

The notes to TNC's financial statements are combined with the notes to financial
statements for AEP and its other subsidiary registrants. Listed below are the
combined notes that apply to TNC. 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  4

Rate Matters                                                    Note  6

Effects of Regulation                                           Note  7

Customer Choice and Industry Restructuring                      Note  8

Commitments and Contingencies                                   Note  9

Guarantees                                                      Note 10

Sustained Earnings Improvement Initiative                       Note 11

Acquisitions, Dispositions and Discontinued Operations          Note 12

Asset Imapairments and Investment Value Losses                  Note 13

Benefit Plans                                                   Note 14

Business Segments                                               Note 16

Risk Management, Financial Instruments and Derivatives          Note 17

Income Taxes                                                    Note 18

Leases                                                          Note 22

Lines of Credit and Sale of Receivables                         Note 23

Unaudited Quarterly Financial Information                       Note 24

Jointly Owned Electric Utility Plant                            Note 28

Related Party Transactions                                      Note 29



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of AEP Texas North Company:

We have audited the accompanying balance sheets and statements of capitalization
of AEP Texas North Company as of December 31, 2002 and 2001, and the related
statements of operations, retained earnings, comprehensive income, and cash
flows for each of the three years in the period ended December 31, 2002. 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 financial statements present fairly, in all material
respects, the financial position of AEP Texas North Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.


/s/ Deloitte & Touche LLP


Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003


<PAGE>








                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------
                                                                         Year Ended December 31,
                                        -----------------------------------------------------------------------------------------
                                            2002              2001             2000                 1999                  1998
                                            ----              ----             ----                 ----                  ----
                                                                            (in thousands)
<S>                                     <C>                <C>                <C>                  <C>                 <C>
INCOME STATEMENTS DATA:
  Operating Revenues                    $1,814,470         $1,784,259         $1,759,253           $1,586,050          $1,672,244
  Operating Expenses                     1,512,407          1,509,273          1,558,099            1,344,814           1,443,701
                                        ----------         ----------         ----------           ----------          ----------
  Operating Income                         302,063            274,986            201,154              241,236             228,543
  Nonoperating Items,
   Net                                      20,106              6,868             11,752                8,096              (8,301)
  Interest Charges                         116,677            120,036            148,000              128,840             126,912
                                        ----------         ----------         ----------           ----------         -----------
  Income Before
   Extraordinary Item                      205,492            161,818             64,906              120,492              93,330
  Extraordinary Gain                          -                  -                 8,938                 -                   -
                                        ----------         ----------         ----------           ----------          ----------
  Net Income                               205,492            161,818             73,844              120,492              93,330
  Preferred Stock
   Dividend Requirements                     2,897              2,011              2,504                2,706               2,497
                                        ----------         ----------         ----------           ----------          ----------
  Earnings Applicable
   to Common Stock                     $   202,595         $  159,807         $   71,340           $  117,786          $   90,833
                                       ===========         ==========         ==========           ==========          ==========

                                                                               December 31,
                                       ------------------------------------------------------------------------------------------
                                            2002              2001             2000                  1999                 1998
                                            ----              ----             ----                  ----                 ----
                                                                            (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                                $5,895,303         $5,664,657         $5,418,278           $5,262,951          $5,087,359
  Accumulated
   Depreciation and
   Amortization                          2,424,607          2,296,481          2,188,796            2,079,490           1,984,856
                                        ----------         ----------         ----------           ----------          ----------
  Net Electric Utility
   Plant                                $3,470,696         $3,368,176         $3,229,482           $3,183,461          $3,102,503
                                        ==========         ==========         ==========           ==========          ==========

  Total Assets                          $4,627,847         $4,482,785         $6,572,595           $4,352,219          $4,047,038
                                        ==========         ==========         ==========           ==========          ==========

  Common Stock and
   Paid-in Capital                        $977,700           $976,244           $975,676             $974,717            $924,091
  Accumulated Other
   Comprehensive Income
   (Loss)                                  (72,082)              (340)              -                    -                   -
  Retained Earnings                        260,439            150,797            120,584              175,854             179,461
                                        ----------         ----------         ----------           ----------          ----------
  Total Common
   Shareholder's Equity                 $1,166,057         $1,126,701         $1,096,260           $1,150,571          $1,103,552
                                        ==========         ==========         ==========           ==========          ==========

Cumulative Preferred Stock:
  Not Subject to
   Mandatory Redemption                 $   17,790         $   17,790         $   17,790           $   18,491          $   19,359
  Subject to Mandatory
   Redemption                               10,860             10,860             10,860               20,310              22,310
                                        ----------         ----------         ----------           ----------          -----------
  Total Cumulative
   Preferred Stock                        $ 28,650         $   28,650         $   28,650           $   38,801          $   41,669
                                          ========         ==========         ==========           ==========          ==========

  Long-term Debt (a)                    $1,893,861         $1,556,559         $1,605,818           $1,665,307          $1,552,455
                                        ==========         ==========         ==========           ==========          ==========

  Obligations Under
   Capital Leases (a)                   $   33,589         $   46,285           $ 63,160           $   64,645          $   65,175
                                        ==========         ==========           ========           ==========          ==========

  Total Capitalization
   And Liabilities                      $4,627,847         $4,482,785         $6,572,595           $4,352,219          $4,047,038
                                        ==========         ==========         ==========           ==========          ==========

(a) Including portion due within one year.

</TABLE>


<PAGE>

                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
          Management's Discussion and Analysis of Results of Operation
          ------------------------------------------------------------



APCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 925,000 retail customers in southwestern
Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool,
shares in the revenues and costs of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of revenues and costs.

Results of Operations
- ---------------------

Net Income increased $44 million or 27% in 2002 due to higher retail sales
resulting from increased generation, weather related electricity demands and
reductions in Maintenance expense. Most significantly, the Mountainer, Amos and
Glen Lyn plants, down for boiler maintenance in 2001, were back online in 2002
resulting in increased availability of generation and decreased maintenance
expense. In addition, Nonoperating Income less Nonoperating Expenses increased
$10 million as a result of a reduction in trading incentive compensation
recorded in Nonoperating Expenses offset in part by decreased power trading
gains recorded in Nonoperating Income.

Net Income increased $88 million or 119% in 2001 primarily due to the effect of
a court decision related to a corporate owned life insurance (COLI) program
recorded in 2000. In February 2001, the U.S. District Court for the Southern
District of Ohio ruled against AEP and certain of its subsidiaries, including
APCo, in a suit over deductibility of interest claimed in AEP's consolidated tax
return related to COLI. In 1998 and 1999 APCo paid the disputed taxes and
interest attributable to the COLI interest deductions for taxable years 1991-98.
Also contributing to the increase in net income was growth in and strong
performance by the wholesale electricity business in the first half of 2001
offset in part by the effect of extremely mild weather in November and December
combined with weak economic conditions which reduced retail energy sales.

Operating Revenues
- ------------------

Operating Revenues increased $30 million or 2% in 2002 as a result of weather
related demand and increased generation resulting from availablility of plants
previously down for maintenance coming back online. An increase of $25 million,
or 1%, in 2001 Operating Revenues was attributable to an increase in AEP Power
Pool transactions. Changes in components of revenues were as follows:

                     Increase (Decrease)
                     From Previous Year
                    (dollars in millions)
                     2002           2001
                  ---------------------------
                  Amount    %   Amount     %
                  ------    -   ------     -
Wholesale
  Electricity*   $16.0      2    $(11.7)  (1)
Energy Delivery*  (1.0)     -      20.1    3
Sales to AEP
  Affiliates      15.2      9      16.6   11
                 -----           ------
     Total
      Revenues   $30.2      2    $ 25.0    1
                 =====           ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.


Operating Revenues for 2002 increased as a result of an increase in generation
and availability at the Mountaineer, Amos and Glen Lyn plants; and increases in
residential and commercial sales due to warmer weather during July and
September. Sales to AEP affiliates increased for the year due to an increase in
generation capacity and power available to be delivered to AEP Power Pool. These
increases were partially offset by flat industrial sales as recessionary
conditions continued into 2002.

The year 2001 saw a decrease in kilowatt hour sales to industrial customers.
This decrease was due to the economic recession. In the fourth quarter, sales to
residential and commercial customers declined, reflecting recession-related
reductions in demand.

The increase in Sales to AEP Affiliates in 2001 is due to an increase in AEP
Power Pool transactions. As the quantity of energy sold by the AEP Power Pool
rose, APCo's contribution of energy to the Pool rose, accounting for the
increase in APCo's revenues from Sales to AEP Affiliates.

Operating Expenses
- ------------------

Operating Expenses for 2002 were comparable to those of 2001. Increases in Fuel
and Wholesale Electricity Purchased Power expenses were offset by decreases in
power purchases from AEP Affiliates due to increases in APCo generation and
availability as plants previously down for maintenance resumed operations. The
decrease in operating expenses in 2001 of 3% is due to decreases in income
taxes, other operation expense, fuel expense and taxes other than income taxes
partially offset by increases in electricity purchased power expense and
depreciation and amortization expenses. Changes in the components of Operating
Expenses are as follows:

                    Increase (Decrease)
                     From Previous Year
                   (dollars in millions)
                   2002             2001
               -----------------------------
                Amount    %    Amount    %
                ------    -    ------    -
Fuel           $  79.4   23  $ (17.6)   (5)
Wholesale
 Electricity
 Purchases        15.0   36     17.4    70
AEP Affiliate
 Purchases      (112.3) (32)    (8.9)   (3)
Other Operation    8.9    3    (18.6)   (7)
Maintenance      (10.2)  (8)     7.9     6
Depreciation and
  Amortization     8.9    5     17.3    11
Taxes Other Than
  Income Taxes    (4.6)  (5)   (11.8)  (11)
Income Taxes      18.0   19    (34.5)  (27)
               -------      --------
  Total        $   3.1    - $  (48.8)   (3)
               =======      ========

Fuel expense increased for 2002 as a result of an increase in APCo generation.
Mountaineer, Amos, and Glen Lyn plants had undergone boiler plant maintenance in
2001 which resulted in increased availability in 2002. The decrease in Fuel
expense in 2001 is due to a decline in generation as a result of scheduled plant
maintenance.

Wholesale Electricity Purchases increased for 2002 as a result of increased
purchases from third parties for resale to wholesale customers and to meet
internal demand. Electricity purchased power expense increased in 2001 due to
increases in wholesale electricity prices and as a result of the previously
mentioned plant outages.

The decrease for 2002 in Purchases from AEP Affiliates is a result of increased
internal generation due to plant availability. Purchased power from AEP
affiliates decreased in 2001 as the result of a decrease in AEP Power Pool
capacity charges due to a reduction in APCo's MLR.

Other Operation expense increased in 2002 mainly due to severance expenses
related to the sustained earnings initiative plan, a reduction in the gains
recorded on the dispositions of SO2 emission allowances, and increased insurance
premiums and other employee benefit costs. These increases were offset by
reduced trading overhead expenses as a result of reduced staffing and weaker
market conditions; a decrease in transmission equalization charges caused by a
reduction in APCo's MLR ratio; and energy delivery severance accruals recorded
in 2001 for which there was no comparable activity in 2002. Other operation
expense decreased in 2001 mainly due to the effect of AEPSC billings in 2000 for
the disallowance of the COLI program interest deduction. Additionally, the
decrease was the result of a gain recorded on the disposition of SO2 emission
allowances offset in part by increased wholesale power trading incentive
compensation expense.

The decrease in Maintenance expense in 2002 is primarily due to previously
discussed boiler plant maintenance at Amos, Mountaineer and Glen Lyn plants in
the year 2001.

Depreciation and Amortization expense increased during 2002 due to increased
amortization for the net generation-related regulatory assets related to the
Company's West Virginia jurisdiction which were assigned to the distribution
portion of the Company's business and are being recovered through regulated
rates. Investment in production plant in service, primarily equipment related to
emission control, contributed to the increase in depreciation and amortization
expense.

Depreciation and Amortization expense increased in 2001 due to accelerated
amortization, beginning in July 2000, of the transition regulatory assets in the
Virginia and West Virginia jurisdictions. Additional investments in distribution
and transmission plant also contributed to the increases in depreciation and
amortization expense in 2001. During June 2000 we discontinued the application
of SFAS 71 in the Virginia and West Virginia jurisdictions. Consequently net
generation-related regulatory assets were assigned to the energy delivery
business's regulated distribution business where the Virginia and West Virginia
jurisdictions authorized the recovery of these transition regulatory assets
through regulated rates.

The decrease in Taxes Other Than Income Taxes for the year 2002 is due primarily
to a decrease in municipal license tax. The municipal license tax was replaced
by the Virginia consumption tax. The municipal license tax was imposed on APCo
and the Virginia consumption tax is imposed on the customer with APCo acting as
collector agent. The decrease in Taxes Other Than Income Taxes in 2001 is due to
the elimination of the Virginia gross receipts tax as a result of a tax law
change due to deregulation in that state.

The increase in Income Taxes for 2002 was due to an increase in pre-tax income.
Income taxes attributable to operations decreased in 2001 due to the effect of
the disallowance of COLI interest deductions in 2000 offset in part by an
increase in pre-tax operating income.

Nonoperating Income and Nonoperating Expenses
- ---------------------------------------------

The Nonoperating Income decrease for 2002 was due primarily to a decrease in net
power trading gains driven by a decline in market prices. Nonoperating Expenses
decreased as a result of decreased trading incentives. The increase in
Nonoperating Income and Nonoperating Expenses for 2001 is due to considerable
increases in the level of activity in the wholesale business's trading
transactions outside of the AEP System's traditional marketing area.

Interest Charges
- ----------------

Interest Charges for 2002 decreased primarily as a result of lower AEP money
pool balances and interest rates and the retirement of first mortgage bonds in
2001. Interest charges decreased in 2001 primarily due to the effect of
recognizing in 2000 previously deferred interest payments to the IRS related to
the COLI disallowances and interest on resultant state income tax deficiencies.
Additionally, the decrease in 2001 is due to the retirement of first mortgage
bonds in 2000.



<PAGE>
<TABLE>
<CAPTION>



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------
                                                                                           Year Ended December 31,
                                                                           ---------------------------------------------------
                                                                                2002                2001               2000
                                                                                ----                ----               ----
                                                                                               (in thousands)
<S>                                                                         <C>                  <C>                <C>
OPERATING REVENUES:
  Wholesale Electricity                                                     $1,033,904           $1,017,938         $1,029,657
  Energy Delivery                                                              594,089              595,036            574,918
  Sales to AEP Affiliates                                                      186,477              171,285            154,678
                                                                            ----------           ----------         ----------
     Total Operating Revenues                                                1,814,470            1,784,259          1,759,253
                                                                            ----------           ----------         ----------

OPERATING EXPENSES:
  Fuel                                                                         430,963              351,557            369,161
  Purchased Power:
    Wholesale Electricity                                                       57,091               42,092             24,720
    AEP Affiliates                                                             234,597              346,878            355,774
  Other Operation                                                              269,426              260,518            279,114
  Maintenance                                                                  122,209              132,373            124,493
  Depreciation and Amortization                                                189,335              180,393            163,089
  Taxes Other Than Income Taxes                                                 95,249               99,878            111,692
  Income Taxes                                                                 113,537               95,584            130,056
                                                                            ----------           ----------         ----------
     Total Operating Expenses                                                1,512,407            1,509,273          1,558,099
                                                                            ----------           ----------         ----------

OPERATING INCOME                                                               302,063              274,986            201,154

NONOPERATING INCOME                                                             29,278               49,507             31,204

NONOPERATING EXPENSES                                                           11,783               41,500             16,329

NONOPERATING INCOME TAX EXPENSE (BENEFIT)                                       (2,611)               1,139              3,123

INTEREST CHARGES                                                               116,677              120,036            148,000
                                                                            ----------           ----------         ----------

INCOME BEFORE EXTRAORDINARY ITEM                                               205,492              161,818             64,906

EXTRAORDINARY GAIN - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION
 (Inclusive of Tax Benefit of $7,872,000)                                        -                     -                 8,938
                                                                            ----------           ----------         ----------

NET INCOME                                                                     205,492              161,818             73,844

PREFERRED STOCK DIVIDEND REQUIREMENTS                                            2,897                2,011              2,504
                                                                            ----------           ----------         ----------

EARNINGS APPLICABLE TO COMMON STOCK                                           $202,595             $159,807           $ 71,340
                                                                              ========             ========           ========


Consolidated Statements of Comprehensive Income
                                                                                             Year Ended December 31,
                                                                              ------------------------------------------------
                                                                                  2002                2001               2000
                                                                                  ----                ----               ----
                                                                                                 (in thousands)

NET INCOME                                                                    $205,492             $161,818            $73,844

OTHER COMPREHENSIVE INCOME (LOSS)
  Foreign Currency Exchange Rate Hedge                                          (1,580)                (340)              -
  Minimum Pension Liability                                                    (70,162)                -                  -
                                                                              --------             --------            -------
COMPREHENSIVE INCOME                                                          $133,750             $161,478            $73,844
                                                                              ========             ========            =======

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------


                                                                                        Year Ended December 31,
                                                                        ---------------------------------------------------
                                                                                2002              2001               2000
                                                                                ----              ----               ----
                                                                                             (in thousands)
<S>                                                                           <C>               <C>                <C>
Retained Earnings January 1                                                   $150,797          $120,584           $175,854
  Net Income                                                                   205,492           161,818             73,844
                                                                              --------          --------           --------
                                                                               356,289           282,402            249,698
                                                                              --------          --------           --------
Deductions:
  Cash Dividends Declared:
    Common Stock                                                                92,952           129,594            126,612
    Cumulative Preferred Stock:
      4-1/2% Series                                                                801               801                811
      5.90%  Series                                                                278               278                307
      5.92%  Series                                                                364               364                364
      6.85%  Series                                                               -                 -                   289
                                                                              --------          --------           --------
              Total Cash Dividends Declared                                     94,395           131,037            128,383

  Capital Stock Expense                                                          1,455               568                731
                                                                              --------          --------           --------
              Total Deductions                                                  95,850           131,605            129,114
                                                                              --------          --------           --------

Retained Earnings December 31                                                 $260,439          $150,797           $120,584
                                                                              ========          ========           ========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------


                                                                                                              December 31,
                                                                                                    ------------------------------
                                                                                                        2002                2001
                                                                                                             (in thousands)
ASSETS
<S>                                                                                                  <C>                 <C>
ELECTRIC UTILITY PLANT:
  Production                                                                                         $2,245,945          $2,093,532
  Transmission                                                                                        1,218,108           1,222,226
  Distribution                                                                                        1,951,804           1,887,020
  General                                                                                               272,901             257,957
  Construction Work in Progress                                                                         206,545             203,922
                                                                                                     ----------          ----------
          Total Electric Utility Plant                                                                5,895,303           5,664,657
  Accumulated Depreciation and Amortization                                                           2,424,607           2,296,481
                                                                                                     ----------          ----------
          NET ELECTRIC UTILITY PLANT                                                                  3,470,696           3,368,176
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                           54,653              53,736
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                                      115,748             119,638
                                                                                                     ----------          ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                               4,285              13,663
  Accounts Receivable:
   Customers                                                                                            132,266             113,371
   Affiliated Companies                                                                                 122,665              63,368
   Miscellaneous                                                                                         28,629              11,847
   Allowance for Uncollectible Accounts                                                                 (13,439)             (1,877)
  Fuel Inventory                                                                                         53,646              56,699
  Materials and Supplies                                                                                 59,886              59,849
  Accrued Utility Revenues                                                                               30,948              30,907
  Energy Trading and Derivative Contracts                                                                94,238             137,742
  Prepayments and Other                                                                                  13,396              16,018
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          526,520             501,587
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                       395,553             397,383
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         64,677              42,265
                                                                                                     ----------          ----------

          TOTAL ASSETS                                                                               $4,627,847          $4,482,785
                                                                                                     ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES


                                                                                                              December 31,
                                                                                                    -------------------------------
                                                                                                        2002                2001
                                                                                                        ----                ----
                                                                                                             (in thousands)
<S>                                                                                                  <C>                 <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 30,000,000 Shares
    Outstanding - 13,499,500 Shares                                                                  $  260,458          $  260,458
  Paid-in Capital                                                                                       717,242             715,786
  Accumulated Other Comprehensive Income (Loss)                                                         (72,082)               (340)
  Retained Earnings                                                                                     260,439             150,797
                                                                                                     ----------          ----------
    Total Common Shareowner's Equity                                                                  1,166,057           1,126,701
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption                                                                  17,790              17,790
    Subject to Mandatory Redemption                                                                      10,860              10,860
  Long-term Debt                                                                                      1,738,854           1,476,552
                                                                                                     ----------          ----------

          TOTAL CAPITALIZATION                                                                        2,933,561           2,631,903
                                                                                                     ----------          ----------

OTHER NONCURRENT LIABILITIES                                                                            173,438              84,104
                                                                                                     ----------          ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                                    155,007              80,007
  Advances From Affiliates                                                                               39,205             291,817
  Accounts Payable - General                                                                            141,546             127,597
  Accounts Payable - Affiliated Companies                                                                98,374              84,518
  Taxes Accrued                                                                                          29,181              55,583
  Customer Deposits                                                                                      26,186              13,177
  Interest Accrued                                                                                       22,437              21,770
  Energy Trading and Derivative Contracts                                                                69,001             121,161
  Other                                                                                                  79,832              79,089
                                                                                                     ----------          ----------

          Total CURRENT LIABILITIES                                                                     660,769             874,719
                                                                                                     ----------          ----------

DEFERRED INCOME TAXES                                                                                   701,801             703,575
                                                                                                     ----------          ----------

DEFERRED INVESTMENT TAX CREDITS                                                                          33,691              38,328
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                        44,517              60,518
                                                                                                     ----------          ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                              80,070              89,638
                                                                                                     ----------          ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

          TOTAL CAPITALIZATION AND LIABILITIES                                                       $4,627,847          $4,482,785
                                                                                                     ==========          ==========

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------


                                                                                            Year Ended December 31,
                                                                               -----------------------------------------------
                                                                                  2002               2001              2000
                                                                                  ----               ----              ----
                                                                                                (in thousands)
<S>                                                                             <C>               <C>                  <C>
OPERATING ACTIVITIES:
  Net Income                                                                    $ 205,492         $ 161,818            $73,844
  Adjustments for Noncash Items:
    Depreciation and Amortization                                                 189,335           180,505            163,202
    Deferred Income Taxes                                                          16,777            42,498              8,602
    Deferred Investment Tax Credits                                                (4,637)           (4,765)            (4,915)
    Deferred Power Supply Costs (net)                                               6,365             1,411            (84,408)
    Mark-to-Market of Energy Trading Contracts                                    (21,151)          (68,254)            (1,843)
    Provision for Rate Refunds                                                       -                 -                (4,818)
    Extraordinary Gain                                                               -                 -                (8,938)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                     (83,412)          134,099           (166,911)
    Fuel, Materials and Supplies                                                    3,016           (19,957)            18,487
    Accrued Utility Revenues                                                          (41)           35,592            (13,081)
    Accounts Payable                                                               27,805           (45,073)           159,369
    Taxes Accrued                                                                 (26,402)           (7,675)            14,220
    Revenue Refunds Accrued                                                          -                 -                   181
    Incentive Plan Accrued                                                           (858)           (2,451)            10,662
  Disputed Tax and Interest Related to COLI                                          -                 -                72,440
  Change in Operating Reserves                                                     (3,190)           (5,358)           (19,770)
  Rate Stabilization Deferral                                                        -                 -                75,601
  Change in Other Assets                                                          (43,337)           19,418            (13,021)
  Change in Other Liabilities                                                      14,948           (27,954)             9,817
                                                                                ---------         ---------          ---------
            Net Cash Flows From Operating Activities                              280,710           393,854            288,720
                                                                                ---------         ---------          ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                      (276,549)         (306,046)          (199,285)
  Proceeds From Sales of Property and Other                                         1,074             1,182                159
  Net Cost of Removal and Other                                                      -               (8,434)            (7,500)
                                                                                ---------         ---------          ---------
            Net Cash Flows Used For Investing
             Activities                                                          (275,475)         (313,298)          (206,626)
                                                                                ---------         ---------          ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                                      647,401           124,588             74,788
  Retirement of Cumulative Preferred Stock                                           -                 -                (9,924)
  Retirement of Long-term Debt                                                   (315,007)         (175,000)          (136,166)
  Change in Short-term Debt (net)                                                    -             (191,495)            68,015
  Change in Advances From Affiliates                                             (252,612)          300,204             (8,387)
  Dividends Paid on Common Stock                                                  (92,952)         (129,594)          (126,612)
  Dividends Paid on Cumulative Preferred Stock                                     (1,443)           (1,443)            (1,938)
                                                                                ---------         ---------          ---------
            Net Cash Flows Used For
             Financing Activities                                                 (14,613)          (72,740)          (140,224)
                                                                                ---------         ---------          ---------

Net Increase (Decrease) in Cash and Cash Equivalents                               (9,378)            7,816            (58,130)
Cash and Cash Equivalents January 1                                                13,663             5,847             63,977
                                                                                ---------         ---------          ---------
Cash and Cash Equivalents December 31                                           $   4,285           $13,663            $ 5,847
                                                                                =========           =======            =======

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $111,528,000, $117,283,000
and $124,579,000 and for income taxes was $125,120,000, $56,981,000 and
$63,682,000 in 2002, 2001 and 2000, respectively. There were no noncash
acquisitions under capital leases in 2002. In 2001 and 2000, non cash
acquisitions under capital leases were $2,510,000 and $14,116,000, respectively.

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


</TABLE>

<PAGE>
<TABLE>
<CAPTION>



APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------

                                                                                          December 31,
                                                                                          -----------
                                                                                   2002                2001
                                                                                   ----                ----
                                                                                         (in thousands)
<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $1,166,057        $1,126,701
                                                                                 ----------        ----------

PREFERRED STOCK: No par value - authorized shares 8,000,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2002 (a)        Year Ended December 31,       December 31, 2002
- ------     ------------     ----------------------------     -----------------
                              2002      2001      2000
                              ----      ----      ----

Not Subject to Mandatory Redemption (b):

4-1/2%         $110            6         -        7,011            177,899           17,790            17,790
                                                                                 ----------        ----------

Subject to Mandatory Redemption (b):

5.90% (c)                      -         -       10,000             47,100            4,710             4,710
5.92% (c)                      -         -         -                61,500            6,150             6,150
                                                                                 ----------        ----------

                                                                                     10,860            10,860
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                489,697           639,365
Installment Purchase Contracts                                                      235,027           234,904
Senior Unsecured Notes                                                            1,166,609           518,247
Junior Debentures                                                                      -              161,507
Other Long-term Debt                                                                  2,528             2,536
Less Portion Due Within One Year                                                   (155,007)          (80,007)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                            1,738,854         1,476,552
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $2,933,561        $2,631,903
                                                                                 ==========        ==========


(a)  The cumulative preferred stock is callable at the price indicated plus
     accrued dividends. The involuntary liquidation preference is $100 per
     share. The aggregate involuntary liquidation price for all shares of
     cumulative preferred stock may not exceed $300 million. The unissued shares
     of the cumulative preferred stock may or may not possess mandatory
     redemption characteristics upon issuance.
(b)  The sinking fund provisions of each series subject to mandatory redemption
     have been met by shares purchased in advance of the due date.
(c)  Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
     share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
     series outstanding under sinking fund provisions at its option and all
     outstanding shares must be redeemed in 2008. Shares previously redeemed may
     be applied to meet the sinking fund requirement.

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------



First mortgage bonds outstanding were as follows:
                              December 31,
                              -----------
                            2002      2001
                            ----      ----
                             (in thousands)
% Rate Due
7.38   2002 - August 15  $   -      $ 50,000
7.40   2002 - December 1     -        30,000
6.65   2003 - May 1          -        40,000
6.85   2003 - June 1         -        30,000
6.00   2003 - November 1   30,000     30,000
7.70   2004 - September 1  21,000     21,000
7.85   2004 - November 1   50,000     50,000
8.00   2005 - May 1        50,000     50,000
6.89   2005 - June 22      30,000     30,000
6.80   2006 - March 1     100,000    100,000
8.50   2022 - December 1   70,000     70,000
7.80   2023 - May 1        30,237     30,237
7.15   2023 - November 1   20,000     20,000
7.125  2024 - May 1        45,000     45,000
8.00   2025 - June 1       45,000     45,000
Unamortized Discount       (1,540)    (1,872)
                         --------   --------
  Total                  $489,697   $639,365
                         ========   ========

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds, by governmental authorities as
follows:

                              December 31,
                              -----------
                            2002       2001
                            ----       ----
                             (in thousands)

% Rate Due
Industrial Development
 Authority of
 Russell County, Virginia:

7.70   2007 - November 1 $ 17,500   $ 17,500
5.00   2021 - November 1   19,500     19,500

Putnam County, West Virginia:

5.45   2019 - June 1       40,000     40,000
6.60   2019 - July 1       30,000     30,000

Mason County, West Virginia:

7-7/8  2013 - November 1   10,000     10,000
6.85   2022 - June 1       40,000     40,000
6.60   2022 - October 1    50,000     50,000
6.05   2024 - December 1   30,000     30,000
Unamortized Discount       (1,973)    (2,096)
                         --------   --------
  Total                  $235,027   $234,904
                         ========   ========


Under the terms of the installment purchase contracts, APCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior unsecured notes outstanding were as follows:

                              December 31,
                              -----------
                            2002       2001
                            ----       ----
                             (in thousands)
% Rate Due
 (a) 2003 - August 20    $ 125,000   $125,000
7.45 2004 - November 1      50,000     50,000
4.80 2005 - June 15        450,000       -
4.32 2007 - November 12    200,000       -
6.60 2009 - May 1          150,000    150,000
7.20 2038 - March 31       100,000    100,000
7.30 2038 - June 30        100,000    100,000
Unamortized Discount        (8,391)    (6,753)
  Total                 $1,166,609   $518,247
                        ==========   ========

(a) A floating  interest rate is determined monthly.  The rate on December
    31, 2002 and 2001 was 2.167% and 2.839%, respectively.

Junior debentures outstanding were as follows:

                            December 31,
                            -----------
                          2002       2001
                          ----       ----
                           (in thousands)
8-1/4% Series A due
  2026 - September 30  $   -        $ 75,000
8% Series B due 2027
  - March 31               -          90,000
Unamortized Discount       -          (3,493)
                       --------     --------
  Total                $   -        $161,507
                       ========     ========

At December 31, 2002, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                       $  155,007
2004                          121,008
2005                          530,010
2006                          100,011
2007                          217,513
Later Years                   782,216
                           ----------
  Total Principal Amount    1,905,765
Unamortized Discount          (11,904)
                           ----------
    Total                  $1,893,861
                           ==========



<PAGE>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------

The notes to APCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to APCo. The combined footnotes
begin on page L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note  1

Extraordinary Items and Cumulative Effect            Note  2

Effects of Regulation                                Note  7

Customer Choice and Industry Restructuring           Note  8

Commitments and Contingencies                        Note  9

Guarantees                                           Note 10

Sustained Earnings Improvement Initiative            Note 11

Asset Impairments and Investments Value Losses       Note 13

Benefit Plans                                        Note 14

Business Segments                                    Note 16

Risk Management, Financial Instruments
  and Derivatives                                    Note 17

Income Taxes                                         Note 18

Supplementary Information                            Note 20

Leases                                               Note 22

Lines of Credit and Sale of Receivables              Note 23

Unaudited Quarterly Financial Information            Note 24

Related Party Transactions                           Note 29



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of Appalachian Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Appalachian Power Company and subsidiaries as of
December 31, 2002 and 2001, 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, 2002. 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 Appalachian Power Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21,  2003



<PAGE>





                         COLUMBUS SOUTHERN POWER COMPANY
                                AND SUBSIDIARIES




<PAGE>




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------

                                                                             Year Ended December 31,
                                             --------------------------------------------------------------------------------------
                                                 2002               2001              2000               1999               1998
                                                 ----               ----              ----               ----               ----
                                                                                 (in thousands)
INCOME STATEMENTS DATA:
<S>                                          <C>                 <C>               <C>                 <C>               <C>
  Operating Revenues                         $1,400,160          $1,350,319        $1,304,409          $1,190,997        $1,187,745
  Operating Expenses                          1,180,381           1,098,142         1,108,532             968,207           975,534
                                             ----------          ----------        ----------          ----------        ----------
  Operating Income                              219,779             252,177           195,877             222,790           212,211
  Nonoperating Items,
   Net                                           15,263               7,738             5,153               2,709            (1,343)
  Interest Charges                               53,869              68,015            80,828              75,229            77,824
                                             ----------          ----------         ---------          ----------        ----------
  Income Before
   Extraordinary Item                           181,173             191,900           120,202             150,270           133,044
  Extraordinary Loss                               -                (30,024)          (25,236)               -                 -
                                             ----------          ----------         ---------          ----------        ----------
  Net Income                                    181,173             161,876            94,966             150,270           133,044
  Preferred Stock
   Dividend
   Requirements                                   1,332               1,095             1,783               2,131             2,131
                                             ----------          ----------         ---------          ----------        ----------
  Earnings Applicable to
   Common Stock                                $179,841            $160,781           $93,183            $148,139          $130,913
                                               ========            ========           =======            ========          ========


                                                                             Year Ended December 31,
                                             --------------------------------------------------------------------------------------
                                                 2002                2001              2000              1999               1998
                                                 ----                ----              ----              ----               ----
                                                                                  (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant                     $3,467,626           $3,354,320        $3,266,794         $3,151,619        $3,053,565
  Accumulated Depreciation                    1,465,174            1,377,032         1,299,697          1,210,994         1,134,348
                                             ----------           ----------        ----------         ----------        ----------
  Net Electric Utility
   Plant                                     $2,002,452           $1,977,288        $1,967,097         $1,940,625        $1,919,217
                                             ==========           ==========        ==========         ==========        ==========

  Total Assets                               $2,753,240           $2,722,388        $3,877,491         $2,808,623        $2,681,690
                                             ==========           ==========        ==========         ==========        ==========

  Common Stock and
   Paid-in Capital                             $616,410             $615,395          $614,380           $613,899          $613,518
  Accumulated Other
   Comprehensive Income
   (Loss)                                       (59,357)                -                 -                  -                 -
  Retained Earnings                             290,611              176,103            99,069            246,584           186,441
                                             ----------           ----------        ----------         ----------        ----------
  Total Common
   Shareholder's Equity                        $847,664             $791,498          $713,449           $860,483          $799,959
                                               ========             ========          ========           ========          ========

  Cumulative Preferred
   Stock - Subject to
   Mandatory
   Redemption (a)                              $  -                 $ 10,000          $ 15,000           $ 25,000          $ 25,000
                                               ========             ========          ========           ========          ========

  Long-term Debt (a)                           $621,626             $791,848          $899,615           $924,545          $959,786
                                               ========             ========          ========           ========          ========

  Obligations Under
   Capital Leases (a)                          $ 27,610             $ 34,887          $ 42,932           $ 40,270          $ 42,362
                                               ========             ========          ========           ========          ========

  Total Capitalization and
    Liabilities                              $2,753,240           $2,722,388        $3,877,491         $2,808,623        $2,681,690
                                             ==========           ==========        ==========         ==========        ==========

(a) Including portion due within one year.

</TABLE>


<PAGE>


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------

Columbus Southern Power Company is a public utility engaged in the generation,
purchase, sale, transmission and distribution of electric power to 689,000
retail customers in central and southern Ohio. CSPCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. CSPCo also sells wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
AEP Power Pool revenues and costs. The result of this calculation is the member
load ratio (MLR) which determines each companies percentage share of AEP Power
Pool revenues and costs.

Results of Operations
- ---------------------

Net Income increased $19 million or 12% in 2002 due to reduced interest charges
and a $30 million extraordinary loss recorded in 2001 to recognize prepaid Ohio
excise taxes stranded by Ohio deregulation offset by higher operating expenses.

Operating Revenues
- ------------------

Operating Revenues increased in 2002 mainly as a result of increased residential
and commercial sales due to demand caused by weather conditions.


Changes in the components of Operating Revenues were:

                                      Increase (Decrease)
                                      From Previous Year
                                      ------------------
                                    (dollars in millions)

                                        Amount        %
                                        ------        -
Retail*                                   $51         8
Wholesale Marketing                         3         2
Unrealized MTM                             (4)      (22)
Other                                       1         3
                                          ---
Wholesale Electricity*                     51         6
Energy Delivery*                            9         2
Sales to AEP Affiliates                   (10)      (15)
                                         ----
   Total Revenues                         $50         4
                                          ===

* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

During the summer months, cooling degree days increased 35%. For the fall
season, heating degree days increased 34%. This reflects a return to more normal
weather conditions since the weather experienced in 2001 was abnormally mild.

Operating Expenses
- ------------------

Operating Expenses increased in 2002 mainly as a result of purchased power,
operating expenses and state taxes.

Changes in the components of Operating Expenses were:

                                     Increase (Decrease)
                                     From Previous Year
                                     ------------------
                                    (dollars in millions)

                                       Amount         %
                                       ------         -

Fuel                                    $10           6
Wholesale Purchased Power                 4          37
AEP Affiliates Purchased
 Power                                   18           6
Other Operation Expenses                 18           8
Maintenance Expense                      (2)         (4)
Depreciation and
 Amortization                             4           3
Taxes Other Than
  Income Taxes                           25          22
Income Taxes                              5           5
                                        ---
     Total                              $82           7
                                        ===

Fuel cost increased as a result of a 10% increase in generation partially offset
by a slight cost decrease per ton of coal consumed.

Wholesale Purchased Power increased in 2002 due to increased purchases from
third parties for resale to wholesale customers and to meet internal demand.

Expenses related to AEP Affiliates Purchased Power increased due to greater
system pool capacity charges.

The increase in Other Operation expenses was attributable to a number of
factors: higher OPEB post retirement costs as a result of higher medical cost
and lower investment performance, 2002 Sustained Earnings Initiative Expenses,
and the 2001 reversal of a quality of service liability accrual. The increase
was partially offset by a reduction in energy trading overheads reflecting
reduced marketing activity.

The increase in Taxes Other Than Income Taxes in 2002 is due to an increase in
property taxes and a full year of the state excise tax which replaced the state
gross receipts tax during 2001.

The increase in Income Taxes is predominately due to an increase in state taxes
as a result of the State of Ohio's tax legislation resulting from utility
deregulation. This increase was offset in part by a decrease in federal taxes
due to a decrease in pre-tax operating income.

Nonoperating Income and Nonoperating Expense
- --------------------------------------------

The decrease in Nonoperating Income in 2002 is due to a reduction in net gains
from AEP Power Pool trading transactions outside of the AEP System's traditional
marketing area. The AEP Power Pool enters into power trading transactions for
the purchase and sale of electricity and for options, futures and swaps. CSPCo's
share of the AEP Power Pool's gains and losses from forward electricity trading
transactions outside of the AEP System traditional marketing area and for
speculative financial transactions (options, futures, swaps) is included in
Nonoperating Income. The decrease reflects a reduction in electricity prices and
margins due to a decrease in demand.

The decrease in Nonoperating Expenses in 2002 was due to a decrease in energy
trading incentive compensation.

Nonoperating Income Tax Expense increased in 2002 due to increase in pre-tax
nonoperating income.

Interest Charges
- ----------------

Interest Charges decreased in 2002 primarily due to a decrease in the
outstanding balance of long-term debt since the first quarter of 2001, the
refinancing of debt at favorable interest rates and a reduction in short-term
interest rates.



<PAGE>
<TABLE>
<CAPTION>

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------

                                                                                                Year Ended December 31,
                                                                                ---------------------------------------------------
                                                                                   2002                  2001               2000
                                                                                   ----                  ----               ----
<S>                                                                             <C>                  <C>                 <C>
OPERATING REVENUES:
  Wholesale Electricity                                                         $  850,680           $  799,589          $  856,998
  Energy Delivery                                                                  492,278              483,219             398,046
  Sales to AEP Affiliates                                                           57,202               67,511              49,365
                                                                                ----------           ----------          ----------
            Total Operating Revenues                                             1,400,160            1,350,319           1,304,409
                                                                                ----------           ----------          ----------

OPERATING EXPENSES:
  Fuel                                                                             185,086              175,153             189,155
  Purchased Power:
    Wholesale Electricity                                                           15,023               10,957               9,879
    AEP Affiliates                                                                 310,605              292,199             287,750
  Other Operation                                                                  237,802              219,497             219,840
  Maintenance                                                                       60,003               62,454              69,676
  Depreciation and Amortization                                                    131,624              127,364              99,640
  Taxes Other Than Income Taxes                                                    136,024              111,481             123,223
  Income Taxes                                                                     104,214               99,037             109,369
                                                                                ----------           ----------          ----------
            TOTAL OPERATING EXPENSES                                             1,180,381            1,098,142           1,108,532
                                                                                ----------           ----------          ----------

OPERATING INCOME                                                                   219,779              252,177             195,877

NONOPERATING INCOME                                                                 26,360               32,756              20,580

NONOPERATING EXPENSES                                                                4,308               21,095               8,070

NONOPERATING INCOME TAX EXPENSE                                                      6,789                3,923               7,357

INTEREST CHARGES                                                                    53,869               68,015              80,828
                                                                                ----------           ----------          ----------

INCOME BEFORE EXTRAORDINARY ITEM                                                   181,173              191,900             120,202

EXTRAORDINARY LOSS - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION - Net of
 tax (Note 2)                                                                         -                 (30,024)            (25,236)
                                                                                ----------           ----------          ----------

NET INCOME                                                                         181,173              161,876              94,966

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                1,332                1,095               1,783
                                                                                ----------           ----------          ----------

EARNINGS APPLICABLE TO COMMON STOCK                                               $179,841             $160,781            $ 93,183
                                                                                  ========             ========            ========



Consolidated Statements of Comprehensive Income
- -----------------------------------------------
                                                                                                Year Ended December 31,
                                                                                  -------------------------------------------------
                                                                                    2002                 2001                2000
                                                                                    ----                 ----                ----

NET INCOME                                                                        $181,173             $161,876             $94,966

OTHER COMPREHENSIVE INCOME (LOSS)
  Foreign Currency Exchange Rate Hedge                                                (267)                -                   -
  Minimum Pension Liability                                                        (59,090)                -                   -
                                                                                  --------             --------             -------
COMPREHENSIVE INCOME                                                              $121,816             $161,876             $94,966
                                                                                  ========             ========             =======

The common stock of the CSPCo is wholly owned by AEP.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------

                                                                                             Year Ended December 31,
                                                                            --------------------------------------------------
                                                                               2002                  2001               2000
                                                                               ----                  ----               ----
                                                                                                (in thousands)
<S>                                                                          <C>                  <C>                 <C>
Retained Earnings January 1                                                  $176,103             $ 99,069            $246,584
Net Income                                                                    181,173              161,876              94,966
                                                                             --------             --------            --------
                                                                              357,276              260,945             341,550
                                                                             --------             --------            --------
Deductions:
Cash Dividends Declared:
  Common Stock                                                                 65,300               82,952             240,600
  Cumulative Preferred Stock - 7% Series                                          350                  875               1,400
                                                                             --------             --------            --------
          Total Cash Dividends Declared                                        65,650               83,827             242,000
Capital Stock Expense                                                           1,015                1,015                 481
                                                                             --------             --------            --------
          Total Deductions                                                     66,665               84,842             242,481
                                                                             --------             --------            --------
Retained Earnings December 31                                                $290,611             $176,103            $ 99,069
                                                                             ========             ========            ========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------

                                                                                                               December 31,
                                                                                                               -----------
                                                                                                        2002                2001
                                                                                                        ----                ----
                                                                                                             (in thousands)

<S>                                                                                                  <C>                 <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                                                         $1,582,627          $1,574,506
  Transmission                                                                                          413,286             401,405
  Distribution                                                                                        1,208,255           1,159,105
  General                                                                                               165,025             146,732
  Construction Work in Progress                                                                          98,433              72,572
                                                                                                     ----------          ----------
          Total Electric Utility Plant                                                                3,467,626           3,354,320
  Accumulated Depreciation                                                                            1,465,174           1,377,032
                                                                                                     ----------          ----------

          NET ELECTRIC UTILITY PLANT                                                                  2,002,452           1,977,288
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                           35,759              40,369
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                                       77,810              73,310
                                                                                                     ----------          ----------

CURRENT ASSETS:
 Cash and Cash Equivalents                                                                                1,479              12,358
 Advances to Affiliates                                                                                  31,257                -
 Accounts Receivable:
  Customers                                                                                              49,566              41,770
  Affiliated Companies                                                                                   54,518              63,470
  Miscellaneous                                                                                          22,005              16,968
  Allowance for Uncollectible Accounts                                                                     (634)               (745)
 Fuel                                                                                                    24,844              20,019
 Materials and Supplies                                                                                  40,339              38,984
 Accrued Utility Revenues                                                                                12,671               7,087
 Energy Trading Contracts                                                                                63,348              84,323
 Prepayments and Other Current Assets                                                                     7,308              28,733
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          306,701             312,967
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                       257,682             262,267
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         72,836              56,187
                                                                                                     ----------          ----------

                    TOTAL ASSETS                                                                     $2,753,240          $2,722,388
                                                                                                     ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES

                                                                                                                December 31,
                                                                                                                -----------
                                                                                                           2002             2001
                                                                                                           ----             ----
                                                                                                              (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                                   <C>                <C>
CAPITALIZATION:
  Common Stock - No Par Value:
   Authorized - 24,000,000 Shares
   Outstanding - 16,410,426 Shares                                                                      $ 41,026           $ 41,026
  Paid-in Capital                                                                                        575,384            574,369
  Accumulated Other Comprehensive Income (Loss)                                                          (59,357)              -
  Retained Earnings                                                                                      290,611            176,103
                                                                                                      ----------         ----------
          Total Common Shareholder's Equity                                                              847,664            791,498
  Cumulative Preferred Stock - Subject to
   Mandatory Redemption                                                                                     -                10,000
  Long-term Debt - General                                                                               418,626            571,348
  Long term Debt - Affiliated Companies                                                                  160,000               -
                                                                                                      ----------         ----------
          TOTAL CAPITALIZATION                                                                         1,426,290          1,372,846
                                                                                                      ----------         ----------

OTHER NONCURRENT LIABILITIES                                                                              95,460             36,715
                                                                                                      ----------         ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year - General                                                            43,000             20,500
  Long-term Debt Due Within One Year - Affiliated Companies                                                 -               200,000
  Short-term Debt - Affiliated Companies                                                                 290,000               -
  Advances from Affiliates                                                                                  -               181,384
  Accounts Payable - General                                                                              89,736             60,689
  Accounts Payable - Affiliated Companies                                                                 81,599             83,697
  Taxes Accrued                                                                                          112,172            116,364
  Interest Accrued                                                                                         9,798             10,907
  Energy Trading Contracts                                                                                46,375             72,082
  Other                                                                                                   36,790             36,305
                                                                                                      ----------         ----------
          TOTAL CURRENT LIABILITIES                                                                      709,470            781,928
                                                                                                      ----------         ----------

DEFERRED INCOME TAXES                                                                                    437,771            443,722
                                                                                                      ----------         ----------

DEFERRED INVESTMENT TAX CREDITS                                                                           33,907             37,176
                                                                                                      ----------         ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                                        29,926             37,101
                                                                                                      ----------         ----------

DEFERRED CREDITS                                                                                          20,416             12,900
                                                                                                      ----------         ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                              $2,753,240         $2,722,388
                                                                                                      ==========         ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------

                                                                                              Year Ended December 31,
                                                                                 -----------------------------------------------
                                                                                     2002              2001               2000
                                                                                     ----              ----               ----
                                                                                                  (in thousands)
<S>                                                                              <C>                 <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                                                     $ 181,173           $ 161,876         $  94,966
  Adjustments for Noncash Items:
    Depreciation and Amortization                                                  131,753             128,500           100,182
    Deferred Income Taxes                                                           23,292              24,108            (4,063)
    Deferred Investment Tax Credits                                                 (3,269)             (4,058)           (3,482)
    Deferred Fuel Costs (net)                                                         -                   -                5,352
    Mark to Market of Energy Trading Contracts                                     (16,667)            (44,680)           (3,393)
    Extraordinary Loss                                                                -                 30,024            25,236
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                       (3,992)             19,987           (29,737)
    Fuel, Materials and Supplies                                                    (6,180)             (7,780)           11,957
    Accrued Utility Revenues                                                        (5,584)              2,551            38,479
    Accounts Payable                                                                26,949             (16,249)           81,284
  Disputed Tax and Interest Related to COLI                                            -                  -               39,483
  Change in Other Assets                                                            (8,027)            (42,066)         (121,115)
  Change in Other Liabilities                                                      (22,448)            (18,769)          132,441
                                                                                 ---------           ---------         ---------
            Net Cash Flows From Operating Activities                               297,000             233,444           367,590
                                                                                 ---------           ---------         ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                       (136,800)           (132,532)         (127,987)
  Proceeds From Sales and Leaseback
   Transactions and Other                                                              730              10,841             1,560
                                                                                 ---------           ---------         ---------
            Net Cash Flows Used For Investing
             Activities                                                           (136,070)           (121,691)         (126,427)
                                                                                 ---------           ---------         ---------

FINANCING ACTIVITIES:
  Change in Advances from Affiliates (net)                                        (212,641)             92,652            88,732
  Issuance of Affiliated Long-term Debt                                            160,000             200,000              -
  Retirement of Preferred Stock                                                    (10,000)             (5,000)          (10,000)
  Retirement of General Long-term Debt                                            (133,343)           (314,733)          (25,274)
  Retirement of Affiliated Long-term Debt                                         (200,000)               -                 -
  Change in Short-term Debt (net)                                                  290,000                -              (45,500)
  Dividends Paid on Common Stock                                                   (65,300)            (82,952)         (240,600)
  Dividends Paid on Cumulative Preferred Stock                                        (525)               (962)           (1,575)
                                                                                 ---------           ---------         ---------
            Net Cash Flows Used For
              Financing Activities                                                (171,809)           (110,995)         (234,217)
                                                                                 ---------           ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                               (10,879)                758             6,946
Cash and Cash Equivalents January 1                                                 12,358              11,600             4,654
                                                                                 ---------           ---------         ---------
Cash and Cash Equivalents December 31                                            $   1,479           $  12,358         $  11,600
                                                                                 =========           =========         =========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $53,514,000, $68,596,000
and $68,506,000 and for income taxes was $117,591,000, 80,485,000 and
$81,109,000 in 2002, 2001 and 2000, respectively.  Noncash acquisitions under
capital leases were  $1,019,000 and $10,777,000 in 2001 and 2000, respectively.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------


                                                                                          December 31,
                                                                                          -----------
                                                                                    2002              2001
                                                                                        (in thousands)

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  847,664        $  791,498
                                                                                 ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 2,500,000
                 $25  par value - authorized shares 7,000,000

                                     Shares
                             Number of Shares Redeemed          Outstanding
Series                         Year Ended December 31,       December 31, 2002
- ------                      ----------------------------     -----------------
                              2002      2001      2000
                              ----      ----      ----

Subject to Mandatory Redemption:

7.00%                       100,000    50,000   100,000               -               -                10,000
                                                                                 ----------        ----------


LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                222,797           243,197
Installment Purchase Contracts                                                       91,275            91,220
Senior Unsecured Notes                                                              147,554           147,458
Notes - Affiliated                                                                  160,000           200,000
Junior Debentures                                                                      -              109,973
Less Portion Due Within One Year                                                   ( 43,000)         (220,500)
                                                                                 ----------        ----------

  Total Long-term Debt Excluding Portion Due Within One Year                        578,626           571,348
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,426,290        $1,372,846
                                                                                 ==========        ==========



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


</TABLE>



<PAGE>



COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------

First mortgage bonds outstanding were as follows:
                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
7.25   2002 - October 1  $   -      $ 14,000
7.15   2002 - November 1     -         6,500
6.80   2003 - May 1        13,000     13,000
6.60   2003 - August 1     25,000     25,000
6.10   2003 - November 1    5,000      5,000
6.55   2004 - March 1      26,500     26,500
6.75   2004 - May 1        26,000     26,000
8.70   2022 - July 1        2,000      2,000
8.55   2022 - August 1     15,000     15,000
8.40   2022 - August 15    14,000     14,000
8.40   2022 - October 15   13,000     13,000
7.90   2023 - May 1        40,000     40,000
7.75   2023 - August 1     33,000     33,000
7.60   2024 - May 1        11,000     11,000
Unamortized Discount         (703)      (803)
                         --------   --------
  Total                  $222,797   $243,197
                         ========   ========

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by the Ohio Air Quality Development
Authority:

                              December 31,
                              -----------
                            2002       2001
                            ----       ----
                             (in thousands)
% Rate Due
6-3/8  2020 - December 1  $48,550    $48,550
6-1/4  2020 - December 1   43,695     43,695
Unamortized Discount         (970)    (1,025)
                          -------    -------
Total                     $91,275    $91,220
                          =======    =======

Under the terms of the installment purchase contracts, CSPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at the Zimmer Plant.


Senior unsecured notes outstanding were as follows:

                            December 31,
                            -----------
                            2002     2001
                            ----     ----
                            (in thousands)
% Rate Due
- ------ ------------------
6.85   2005 - October 3  $ 36,000  $ 36,000
6.51   2008 - February 1   52,000    52,000
6.55   2008 - June 26      60,000    60,000
Unamortized Discount         (446)     (542)
                         --------  --------
  Total                  $147,554  $147,458
                         ========  ========

Notes payable to parent company were as follows:

                              December 31,
                              -----------
                            2002         2001
                            ----         ----
                             (in thousands)
% Rate     Due
(a)        2002 - Sept 25 $   -      $200,000
6.501%     2006 - May 15   160,000       -
                          --------   --------
   Total                  $160,000   $200,000
                          ========   ========

(a) Redemed 9/25/02

Junior debentures outstanding were as follows:

                            December 31,
                            -----------
                          2002        2001
                          ----        ----
                           (in thousands)
% Rate Due
- ------ ------------------
8-3/8  2025 - Sept 30  $   -        $ 72,843
7.92   2027 - March 31     -          40,000
Unamortized Discount       -          (2,870)
                       --------     --------
  Total                $   -        $109,973
                       ========     ========


At December 31, 2002, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                        $ 43,000
2004                          52,500
2005                          36,000
2006                         160,000
2007                            -
Later Years                  332,245
                            --------
  Total Principal Amount     623,745
Unamortized Discount          (2,119)
                            --------
    Total                   $621,626



<PAGE>


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------

The notes to CSPCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to CSPCo. The combined footnotes
begin on page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference
                                                          ---------

Significant Accounting Policies                           Note  1

Extraordinary Items and Cumulative Effect                 Note  2

Effects of Regulation                                     Note  7

Customer Choice and Industry Restructuring                Note  8

Commitments and Contingencies                             Note  9

Guarantees                                                Note 10

Sustained Earnings Improvement Initiative                 Note 11

Asset Impairments and Investment Value Losses             Note 13

Benefit Plans                                             Note 14

Business Segments                                         Note 16

Risk Management, Financial Instruments and Derivatives    Note 17

Income Taxes                                              Note 18

Supplementary Information                                 Note 20

Leases                                                    Note 22

Lines of Credit and Sale of Receivables                   Note 23

Unaudited Quarterly Financial Information                 Note 24

Jointly Owned Electric Utility Plant                      Note 28

Related Party Transactions                                Note 29




<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholder and Board of Directors
of Columbus Southern Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Columbus Southern Power Company and subsidiaries
as of December 31, 2002 and 2001, 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, 2002. 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 Columbus Southern Power Company and
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003




<PAGE>
                         INDIANA MICHIGAN POWER COMPANY
                                AND SUBSIDIARIES




<PAGE>
<TABLE>
<CAPTION>




INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------

                                                                           Year Ended December 31,
                                        -----------------------------------------------------------------------------------------
                                            2002                2001               2000               1999                1998
                                            ----                ----               ----               ----                ----
                                                                              (in thousands)
INCOME STATEMENTS DATA:
<S>                                     <C>                <C>                 <C>                 <C>                 <C>
  Operating Revenues                    $1,526,764         $1,526,997          $1,488,209          $1,351,666          $1,405,794
  Operating Expenses                     1,375,575          1,367,292           1,522,911           1,243,014           1,239,787
                                        ----------         ----------          ----------          ----------          ----------
  Operating Income
   (Loss)                                  151,189            159,705             (34,702)            108,652             166,007
  Nonoperating Items,
   Net                                      16,726              9,730               9,933               4,530                (839)
  Interest Charges                          93,923             93,647             107,263              80,406              68,540
                                        ----------         ----------          ----------          ----------          ----------
  Net Income (Loss)                         73,992             75,788            (132,032)             32,776              96,628
  Preferred Stock
   Dividend
   Requirements                              4,601              4,621               4,624               4,885               4,824
                                        ----------         ----------           ---------          ----------          ----------
  Earnings (Loss)
   Applicable to
   Common Stock                         $   69,391         $   71,167           $(136,656)         $   27,891          $   91,804
                                        ==========         ==========           =========          ==========          ==========

                                                                                   December 31,
                                        -----------------------------------------------------------------------------------------
                                              2002               2001               2000               1999                1998
                                              ----               ----               ----               ----                ----
                                                                                (in thousands)
BALANCE SHEETS DATA:

  Electric Utility
   Plant                                $5,029,958         $4,923,721          $4,871,473          $4,770,027          $4,631,848
  Accumulated
   Depreciation and
   Amortization                          2,568,604          2,436,972           2,280,521           2,194,397           2,081,355
                                        ----------         ----------          ----------          ----------          ----------
  Net Electric Utility
   Plant                                $2,461,354         $2,486,749          $2,590,952          $2,575,630          $2,550,493
                                        ==========         ==========          ==========          ==========          ==========

  Total Assets                          $4,587,191         $4,394,062          $5,774,108          $4,575,210          $4,148,523
                                        ==========         ==========          ==========          ==========          ==========

  Common Stock and
   Paid-in Capital                      $  915,144         $  789,800          $  789,656          $  789,323          $  789,189
  Accumulated Other
   Comprehensive Income
   (Loss)                                  (40,487)            (3,835)               -                   -                   -
  Retained Earnings                        143,996             74,605               3,443             166,389             253,154
                                        ----------         ----------          ----------          ----------          ----------
  Total Common
   Shareholder's Equity                 $1,018,653         $  860,570          $  793,099          $  955,712          $1,042,343
                                        ==========         ==========          ==========          ==========          ==========

  Cumulative Preferred
   Stock:
    Not Subject to
     Mandatory
     Redemption                         $    8,101         $    8,736          $    8,736        $    9,248          $    9,273
    Subject to
     Mandatory
     Redemption (a)                         64,945             64,945              64,945            64,945              68,445
                                        ----------         ----------          ----------        ----------          ----------
      Total Cumulative
        Preferred Stock                 $   73,046         $   73,681          $   73,681        $   74,193          $   77,718
                                        ==========         ==========          ==========        ==========          ==========

  Long-term Debt (a)                    $1,617,062         $1,652,082          $1,388,939        $1,324,326          $1,175,789
                                        ==========         ==========          ==========        ==========          ==========

  Obligations Under
   Capital Leases (a)                   $   50,848         $   61,933           $  163,173        $  187,965          $  186,427
                                        ==========         ==========           ==========        ==========          ==========

  Total Capitalization
    And Liabilities                     $4,587,191         $4,394,062           $5,774,108        $4,575,210          $4,148,523
                                        ==========         ==========           ==========        ==========          ==========

(a) Including portion due within one year. (a)

</TABLE>

<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------

I&M is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 571,000 retail customers in its service
territory in northern and eastern Indiana and a portion of southwestern
Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers. I&M also sells wholesale power to municipalities and electric
cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing revenues
and costs. The result of this calculation is each company's member load ratio
(MLR) which determines each company's percentage share of revenues and costs.

Under unit power agreements, I&M purchases AEGCo's 50% share of the 2,600 MW
Rockport Plant capacity unless it is sold to other utilities. AEGCo is an
affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo
and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant capacity to
KPCo through 2004. The KPCo agreement extends until December 31, 2009 for
Rockport Unit 1 and until December 7, 2022 for Rockport Plant Unit 2 if AEP's
restructuring settlement agreement filed with the FERC becomes operative.
Therefore, I&M purchases 910 MW of AEGCo's 50% share of Rockport Plant capacity.

Results of Operations
- ---------------------

During 2002 Net Income decreased by $2 million due to increased operations and
maintenance costs incurred as part of planned and unplanned outages at Cook
Plant and Rockport Plant.

During 2000 both of the Cook Plant nuclear units were successfully restarted
after being shutdown in September 1997 due to questions regarding the
operability of certain safety systems which arose during a NRC architect
engineer design inspection (see Note 5).

As a result of costs incurred in 2000 to restart the Cook Plant and a
disallowance of interest deductions for a corporate owned life insurance (COLI)
program, Net Income increased in 2001 by $208 million. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including I&M, in a suit over deductibility of interest
claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 I&M
paid the disputed taxes and interest attributable to the COLI interest
deductions for the taxable years 1991-98 and deferred them. The deferrals were
expensed and impacted Net Income in 2000.

Operating Revenues Increase
- ---------------------------

Operating Revenues were flat in 2002 and increased 3% in 2001. The 2001 increase
reflects increased sales to AEP affiliates through the AEP Power Pool. The
following analyzes the changes in Operating Revenues:

                    Increase (Decrease)
                    From Previous Year
                    ------------------
                   (dollars in millions)
                     2002           2001
               ------------------------------
               Amount    %    Amount     %
               ------    -    ------     -
Retail*       $ 28.2    4   $ (2.3)     N.M
Marketing        2.6    1    (12.0)     (4)
Other            2.6    6      5.0      13
              ------        ------
 Total
  Wholesale
  Electricity   33.4    3     (9.3)     (1)

Energy
 Delivery*       7.3    2      3.4       1
Sales to AEP
 Affiliates    (40.9) (16)    44.7      21
              ------        ------
     Total    $ (0.2)  N.M. $ 38.8       3
              ======        ======

N.M. = Not Meaningful

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery. The increase in Operating
Revenues in 2001 is primarily due to increased sales to AEP affiliates
reflecting increased availablility of the Cook Plant. The return to service of
the Cook Plant units increased the amount of power I&M could sell to its
affiliates in the AEP Power Pool.

Operating Expenses
- ------------------

Total Operating Expenses increased 1% in 2002 and decreased 10% in 2001. The
2001 decrease was primarily due to the unfavorable COLI tax ruling and costs
related to the extended Cook Plant outage and restart efforts in 2000. The
changes in the components of Operating Expenses were:

                      Increase (Decrease)
                      From Previous Year
                     -------------------
                     (dollars in millions)
                     2002           2001
                -----------------------------
                Amount     %    Amount    %
                ------     -    ------    -

Fuel            $(10.6)    (4)  $  39.2   19
Wholesale
 Electricity
 Purchases         4.7     25       4.9   36
AEP Affiliate
 Purchases        (4.5)    (2)    (27.2) (10)
Other Operation   13.6      3    (147.7) (25)
Maintenance       24.3     19     (92.6) (42)
Depreciation and
 Amortization      3.8      2       9.3    6
Taxes Other Than
 Income Taxes     (7.8)   (12)      4.9    8
Income Taxes     (15.2)   (28)     53.6  N.M.
                ------          -------
    Total       $  8.3      1   $(155.6) (10)
                ======          =======

N.M. = Not Meaningful

Fuel expense decreased in 2002 due to lower average costs of fuel and a decline
in nuclear generation. The increase in Fuel expense in 2001 reflects an increase
in nuclear generation as the Cook Plant units returned to service following the
extended outage.

Wholesale Electricity purchases increased in 2002 and 2001 due to increased
purchases from third parties for sales for resale. AEP Affiliates purchases
declined in 2002 due to lower purchases from AEGCo at lower costs. The decline
in purchased power from AEP affiliates in 2001 reflects generation from the Cook
Plant replacing purchases from the AEP Power Pool which declined 21%.

Other Operation expense increased in 2002 primarily due to higher costs for
pensions, other benefits and insurance. The decrease in Other Operation and
Maintenance expenses in 2001 was primarily due to the cessation of expenditures
to prepare the Cook Plant nuclear units for restart with their return to service
in 2000. Maintenance expense increased for nuclear maintenance costs incurred
during refueling outages in 2002.

The increase in Depreciation and Amortization charges in 2001 reflects increased
generation and distribution plant investments and amortization of I&M's share of
deferred merger costs.

Due to a change in the Indiana property tax law which lowered the floor
percentage for calculating tax liability, Taxes Other Than Income Taxes declined
in 2002. Taxes Other than Income Taxes increased in 2001 due to higher real and
personal property tax expense from the effect of a favorable accrual adjustment
of amounts recorded in December 2000 to actual expenses.

Income Taxes attributable to operations decreased in 2002 due to a decrease in
pre-tax operating income. The significant increase in Income Taxes attributable
to operations in 2001 is due to an increase in pre-tax operating income.

Nonoperating Income, Nonoperating Expenses and Income Taxes
- -----------------------------------------------------------

The decrease in Nonoperating Income in 2002 is primarily due to decreased net
gains on forward electricity trading transactions outside AEP's traditional
marketing area. The increase in Nonoperating Income in 2001 is primarily due to
increased net gains on forward electricity trading transactions outside AEP's
traditional marketing area.

Nonoperating Expenses decreased in 2002 due to decreased trading overheads and
traders' incentive compensation. Nonoperating Expenses increased in 2001 due to
increased trading overheads and traders' incentive compensation.

The increase in Nonoperating Income Taxes in 2001 reflects the increase in
nonoperating pre-tax income.

Interest Charges
- ----------------

The decrease in 2001 Interest Charges reflects the recognition in 2000 of
deferred interest payments to the IRS on disputed income taxes from the
disallowance of tax deductions for COLI interest for the years 1991-1998.


<PAGE>
<TABLE>
<CAPTION>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------

                                                                                               Year Ended December 31,
                                                                                 -------------------------------------------------
                                                                                     2002               2001                2000
                                                                                     ----               ----                ----
                                                                                                   (in thousands)
<S>                                                                              <C>                 <C>                <C>
OPERATING REVENUES:
  Wholesale Electricity                                                          $  990,905          $  957,548         $  966,882
  Energy Delivery                                                                   321,721             314,410            311,019
  Sales to AEP Affiliates                                                           214,138             255,039            210,308
                                                                                 ----------          ----------         ----------

            TOTAL OPERATING REVENUES                                              1,526,764           1,526,997          1,488,209
                                                                                 ----------          ----------         ----------

OPERATING EXPENSES:
  Fuel                                                                              239,455             250,098            210,870
  Purchased Power:
    Wholesale Electricity                                                            23,443              18,707             13,785
    AEP Affiliates                                                                  233,724             238,237            265,475
  Other Operation                                                                   462,707             449,115            596,861
  Maintenance                                                                       151,602             127,263            219,854
  Depreciation and Amortization                                                     168,070             164,230            154,920
  Taxes other Than Income Taxes                                                      57,721              65,518             60,622
  Income Taxes                                                                       38,853              54,124                524
                                                                                 ----------          ----------         ----------

            TOTAL OPERATING EXPENSES                                              1,375,575           1,367,292          1,522,911
                                                                                 ----------          ----------         ----------

OPERATING INCOME (LOSS)                                                             151,189             159,705            (34,702)

NONOPERATING INCOME                                                                  93,739              97,810             76,499

NONOPERATING EXPENSES                                                                71,029              83,037             62,377

NONOPERATING INCOME TAXES                                                             5,984               5,043              4,189

INTEREST CHARGES                                                                     93,923              93,647            107,263
                                                                                 ----------          ----------         ----------

NET INCOME (LOSS)                                                                    73,992              75,788           (132,032)

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                 4,601               4,621              4,624
                                                                                 ----------          ----------          ---------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                                       $   69,391          $   71,167          $(136,656)
                                                                                 ==========          ==========          =========


Consolidated Statements of Comprehensive Income
- -----------------------------------------------

                                                                                               Year Ended December 31,
                                                                                 --------------------------------------------------
                                                                                      2002               2001               2000
                                                                                      ----               ----               ----
                                                                                                    (in thousands)

NET INCOME (LOSS)                                                                  $ 73,992             $75,788          $(132,032)

OTHER COMPREHENSIVE INCOME (LOSS)
  Cash Flow Interest Rate Hedge                                                       3,835              (3,835)              -
  Cash Flow Power Hedge                                                                (286)               -                  -
  Minimum Pension Liability                                                         (40,201)               -                  -
                                                                                   --------             -------          ---------

COMPREHENSIVE INCOME (LOSS)                                                        $ 37,340             $71,953          $(132,032)
                                                                                   ========             =======          =========

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>



INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------

                                                                                            Year Ended December 31,
                                                                             --------------------------------------------------
                                                                               2002                2001                  2000
                                                                               ----                ----                  ----
                                                                                               (in thousands)
<S>                                                                          <C>                    <C>               <C>
Retained Earnings January 1                                                  $ 74,605              $ 3,443            $ 166,389
Net Income (Loss)                                                              73,992               75,788             (132,032)
                                                                             --------             --------            ---------
                                                                              148,597               79,231               34,357
                                                                             --------             --------            ---------
Deductions:
 Cash Dividends Declared:
   Common Stock                                                                  -                    -                  26,290
   Cumulative Preferred Stock:
     4-1/8% Series                                                                229                  229                  230
     4.56% Series                                                                  66                   66                   66
     4.12% Series                                                                  52                   72                   74
     5.90% Series                                                                 897                  897                  897
     6-1/4% Series                                                              1,203                1,203                1,203
     6.30% Series                                                                 834                  834                  834
     6-7/8% Series                                                              1,186                1,186                1,186
                                                                             --------             --------            ---------
           Total Cash Dividends Declared                                        4,467                4,487               30,780
  Capital Stock Expense                                                           134                  139                  134
                                                                             --------             --------            ---------
            Total Deductions                                                    4,601                4,626               30,914
                                                                             --------             --------            ---------

Retained Earnings December 31                                                $143,996             $ 74,605              $ 3,443
                                                                             ========             ========              =======

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------

                                                                                                       December 31,
                                                                                                       -----------
                                                                                               2002                 2001
                                                                                               ----                 ----
                                                                                                     (in thousands)
ASSETS
<S>                                                                                         <C>                  <C>
ELECTRIC UTILITY PLANT:
 Production                                                                                 $2,768,463           $2,758,160
 Transmission                                                                                  971,599              957,336
 Distribution                                                                                  921,835              900,921
 General (including nuclear fuel)                                                              220,137              233,005
 Construction Work in Progress                                                                 147,924               74,299
                                                                                            ----------           ----------
         Total Electric Utility Plant                                                        5,029,958            4,923,721
 Accumulated Depreciation and Amortization                                                   2,568,604            2,436,972
                                                                                            ----------           ----------
         NET ELECTRIC UTILITY PLANT                                                          2,461,354            2,486,749
                                                                                            ----------           ----------

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
 FUEL DISPOSAL TRUST FUNDS                                                                     870,754              834,109
                                                                                            ----------           ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                               83,265               82,898
                                                                                            ----------           ----------

OTHER PROPERTY AND INVESTMENTS                                                                 120,941              127,977
                                                                                            ----------           ----------

CURRENT ASSETS:
 Cash and Cash Equivalents                                                                       3,237               16,804
 Advances to Affiliates                                                                        191,226               46,309
 Accounts Receivable:
  Customers                                                                                     67,333               60,864
  Affiliated Companies                                                                         122,489               31,908
  Miscellaneous                                                                                 30,468               25,398
  Allowance for Uncollectible Accounts                                                            (578)                (741)
 Fuel                                                                                           32,731               28,989
 Materials and Supplies                                                                         95,552               91,440
 Energy Trading and Derivative Contracts                                                        68,148              108,895
 Accrued Utility Revenues                                                                        6,511                2,072
 Prepayments and Other                                                                          11,899                6,497
                                                                                            ----------           ----------
         TOTAL CURRENT ASSETS                                                                  629,016              418,435
                                                                                            ----------           ----------

REGULATORY ASSETS                                                                              348,212              408,927
                                                                                            ----------           ----------

DEFERRED CHARGES                                                                                73,649               34,967
                                                                                            ----------           ----------

           TOTAL ASSETS                                                                     $4,587,191           $4,394,062
                                                                                            ==========           ==========

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES

                                                                                                              December 31,
                                                                                                              -----------
                                                                                                        2002               2001
                                                                                                        ----               ----
                                                                                                             (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                                                                  <C>                <C>
CAPITALIZATION:
 Common Stock - No Par Value:
   Authorized - 2,500,000 Shares
   Outstanding - 1,400,000 Shares                                                                    $   56,584         $   56,584
 Paid-in Capital                                                                                        858,560            733,216
 Accumulated Other Comprehensive Income (Loss)                                                          (40,487)            (3,835)
 Retained Earnings                                                                                      143,996             74,605
                                                                                                     ----------         ----------
           Total Common Shareholder's Equity                                                          1,018,653            860,570
 Cumulative Preferred Stock:
   Not Subject to Mandatory Redemption                                                                    8,101              8,736
   Subject to Mandatory Redemption                                                                       64,945             64,945
 Long-term Debt                                                                                       1,587,062          1,312,082
                                                                                                     ----------         ----------
           TOTAL CAPITALIZATION                                                                       2,678,761          2,246,333
                                                                                                     ----------         ----------

OTHER NONCURRENT LIABILITIES:
 Nuclear Decommissioning                                                                                620,672            600,244
 Other                                                                                                  138,965             87,025
                                                                                                     ----------         ----------
           TOTAL OTHER NONCURRENT LIABILITIES                                                           759,637            687,269
                                                                                                     ----------         ----------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                                                                      30,000            340,000
 Accounts Payable - General                                                                             125,048             86,766
 Accounts Payable - Affiliated Companies                                                                 93,608             43,956
 Taxes Accrued                                                                                           71,559             69,761
 Interest Accrued                                                                                        21,481             20,691
 Obligations Under Capital Leases                                                                         8,229             10,840
 Energy Trading and Derivative Contracts                                                                 48,568             93,413
 Other                                                                                                   92,822             76,486
                                                                                                     ----------         ----------
           TOTAL CURRENT LIABILITIES                                                                    491,315            741,913
                                                                                                     ----------         ----------

DEFERRED INCOME TAXES                                                                                   356,197            400,531
                                                                                                     ----------         ----------

DEFERRED INVESTMENT TAX CREDITS                                                                          97,709            105,449
                                                                                                     ----------         ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                                                                  73,885             77,592
                                                                                                     ----------         ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                        32,261             42,936
                                                                                                     ----------         ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                              97,426             92,039
                                                                                                     ----------         ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

             TOTAL CAPITALIZATION AND LIABILITIES                                                    $4,587,191         $4,394,062
                                                                                                     ==========         ==========

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



</TABLE>


<PAGE>
<TABLE>
<CAPTION>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------

                                                                                                Year Ended December 31,
                                                                                                ----------------------
                                                                                     2002               2001               2000
                                                                                     ----               ----               ----
                                                                                                   (in thousands)
<S>                                                                             <C>                  <C>                <C>
OPERATING ACTIVITIES:
  Net Income (Loss)                                                             $  73,992            $  75,788          $(132,032)
  Adjustments for Noncash Items:
   Depreciation and Amortization                                                  168,070              166,360            163,391
   Amortization (Deferral) of Incremental Nuclear
    Refueling Outage Expenses (net)                                               (26,577)                 418              5,737
   Amortization of Nuclear Outage Costs                                            40,000               40,000             40,000
   Deferred Income Taxes                                                          (16,921)             (29,205)          (125,179)
   Deferred Investment Tax Credits                                                 (7,740)              (8,324)            (7,854)
   Unrecovered Fuel and Purchased Power Costs                                      37,501               37,501             37,501
  Changes in Certain Current Assets
    And Liabilities:
   Accounts Receivable (net)                                                     (102,283)              64,841            (25,305)
   Fuel, Materials and Supplies                                                    (7,854)             (19,426)            10,743
   Accrued Utility Revenues                                                        (4,439)              (2,072)            44,428
   Accounts Payable                                                                87,934              (60,185)            85,056
   Taxes Accrued                                                                    1,798                1,345             19,446
  Mark-to-Market of Energy Trading and Derivatives Contracts                       (9,517)             (62,647)            14,830
  Disputed Tax and Interest Related to COLI                                          -                    -                56,856
  Regulatory Asset - Trading Losses                                                  (992)               8,493            (17,914)
  Regulatory Liability - Trading Gains                                              2,494               34,293             (7,416)
  Change in Other Assets                                                          (28,233)              (5,871)           (68,160)
  Change in Other Liabilities                                                      21,001               (5,102)            37,309
                                                                                ---------            ---------          ---------
     Net Cash Flows From Operating Activities                                     228,234              236,207            131,437
                                                                                ---------            ---------          ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                      (167,484)             (91,052)          (171,071)
  Buyout of Nuclear Fuel Leases                                                      -                 (92,616)              -
  Other                                                                             1,759                1,074                587
                                                                                ---------            ---------          ---------
    Net Cash Flows Used For Investing Activities                                 (165,725)            (182,594)         (170,484)
                                                                                ---------            ---------         ---------

FINANCING ACTIVITIES:
 Capital Contributions from Parent Company                                        125,000                 -                  -
 Issuance of Long-term Debt                                                       288,732              297,656            199,220
 Retirement of Cumulative Preferred Stock                                            (424)                -                  (314)
 Retirement of Long-term Debt                                                    (340,000)             (44,922)          (148,000)
 Change in Advances from Affiliates (net)                                        (144,917)            (299,891)           253,582
 Change in Short-term Debt (net)                                                     -                    -              (224,262)
 Dividends Paid on Common Stock                                                      -                    -               (26,290)
 Dividends Paid on Cumulative Preferred Stock                                      (4,467)              (4,487)            (3,368)
                                                                                ---------            ---------          ---------
    Net Cash Flows From (Used For)
     Financing Activities                                                         (76,076)             (51,644)            50,568
                                                                                ---------            ---------          ---------

Net Increase (Decrease) in Cash and
 Cash Equivalents                                                                 (13,567)               1,969             11,521
Cash and Cash Equivalents January 1                                                16,804               14,835              3,314
                                                                                ---------            ---------          ---------
Cash and Cash Equivalents December 31                                             $ 3,237              $16,804            $14,835
                                                                                  =======              =======            =======

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $89,984,000, $92,140,000
and $82,511,000 and for income taxes was $60,523,000, $100,470,000 and
$73,254,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions under
capital leases were $1,023,000 and $22,218,000 in 2001 and 2000, respectively.

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------

                                                                                            December 31,
                                                                                            -----------
                                                                                     2002                2001
                                                                                     ----                ----
                                                                                          (in thousands)

<S>                                                                                <C>              <C>
COMMON SHAREHOLDER'S EQUITY                                                        $1,018,653        $  860,570
                                                                                   ----------        ----------

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           2002 (a)       Year Ended December 31,       December 31, 2002
- ------        ------------     ------------------------       -----------------
                                2002     2001     2000
                                ----     ----     ----

Not Subject to Mandatory Redemption-$100 Par:

    4-1/8%     106.125            20     -       3,750              55,369              5,537             5,539
    4.56%      102               -       -        -                 14,412              1,441             1,441
    4.12%      102.728         6,326     -       1,375              11,230              1,123             1,756
                                                                                   ----------        ----------
                                                                                        8,101             8,736
                                                                                   ----------        ----------
Subject to Mandatory Redemption-$100 Par(b):

    5.90%  (c)                   -       -        -                152,000             15,200            15,200
    6-1/4% (c)                   -       -        -                192,500             19,250            19,250
    6.30%  (c)                   -       -        -                132,450             13,245            13,245
    6-7/8% (d)                   -       -        -                172,500             17,250            17,250
                                                                                   ----------        ----------
                                                                                       64,945            64,945
                                                                                   ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                  174,245           264,141
Installment Purchase Contracts                                                        310,336           310,239
Senior Unsecured Notes                                                                747,027           696,144
Other Long-term Debt (e)                                                              223,736           219,947
Junior Debentures                                                                     161,718           161,611
Less Portion Due Within One Year                                                      (30,000)         (340,000)
                                                                                   ----------        ----------

    Long-term Debt Excluding Portion Due Within One Year                            1,587,062         1,312,082
                                                                                   ----------        ----------

    TOTAL CAPITALIZATION                                                           $2,678,761        $2,246,333
                                                                                   ==========        ==========

(a)  The cumulative preferred stock is callable at the price indicated plus
     accrued dividends
(b)  Sinking fund provisions require the redemption of 15,000 shares in 2003 and
     67,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
     provisions of each series subject to mandatory redemption have been met by
     purchase of shares in advance of these due dates. Shares previously
     purchased may be applied to meet the sinking fund requirement.
(c)  Commencing in 2004 and continuing through 2008 I&M 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. The series are callable beginning November 1,
     2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March
     1, 2004 for the 6.30% series at $100 plus accrued dividends.
(d)  Commencing in 2003 and continuing through the year 2007, a sinking fund
     will require the redemption of 15,000 shares each year and the redemption
     of the remaining shares outstanding on April 1, 2008, in each case at $100
     per share. Callable at $100 per share plus accrued dividends beginning
     February 1, 2003.
(e)  Represents a liability for SNF disposal including interest payable to the
     DOE. See Note 9.

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


</TABLE>



<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------


First mortgage bonds outstanding were as follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
7.60   2002 - November 1 $   -      $ 50,000
7.70   2002 - December 15    -        40,000
6.10   2003 - November 1   30,000     30,000
8.50   2022 - December 15  75,000     75,000
7.35   2023 - October 1    15,000     15,000
7.20   2024 - February 1   30,000     30,000
7.50   2024 - March 1      25,000     25,000
Unamortized Discount         (755)      (859)
                         --------   --------
                         $174,245   $264,141

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered in connection with the issuance
of pollution control revenue bonds by governmental authorities as follows:

                              December 31,
                              -----------
                            2002       2001
                            ----       ----
                             (in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7.00   2015 - April 1    $ 25,000   $ 25,000
5.90   2019 - November 1   52,000     52,000

City of Rockport, Indiana:
 (a)    2014 - August 1      -        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
4.90(c) 2025 - June 1      50,000       -

City of Sullivan, Indiana:
5.95   2009 - May 1        45,000     45,000
Unamortized Discount       (1,664)    (1,761)
                         --------   --------
                         $310,336   $310,239
                         ========   ========

(a)  A variable  interest  rate was  determined  weekly.  The  average  weighted
     interest rates were 1.5% in 2002 and 2.4% for 2001.
(b)  In June 2001 an auction rate was established.  Auction rates are determined
     by standard procedures every 35 days. The auction rate for 2002 ranged from
     1.3% to 1.7% and averaged 1.5%. 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 averaged 3.3% during 2001.
(c)  Rate is fixed until June 1, 2007 (term rate bonds).


The terms of the installment purchase contracts require I&M to pay amounts
sufficient for the cities to pay interest on and the principal of (at stated
maturities and upon mandatory redemptions) related pollution control revenue
bonds issued to finance the construction of pollution control facilities at
certain generating plants. The term rate bonds due 2025 are subject to mandatory
tender for purchase on the term maturity date (June 1, 2007). Accordingly, the
term rate bonds have been classified for repayment purposes in 2007 (the term
end date).

Senior unsecured notes outstanding were as follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
- ------ ------------------
 (a)   2002 - September 3 $   -     $200,000
6-7/8  2004 - July 1       150,000   150,000
6.125  2006 - December 15  300,000   300,000
6.45   2008 - November 10   50,000    50,000
6.375  2012 - November 1   100,000      -
6      2032 - December 31  150,000      -
Unamortized Discount        (2,973)   (3,856)
                          --------  --------
                          $747,027  $696,144
                          ========  ========

(a) A floating interest rate was determined quarterly. The rate on December 31,
2001 was 2.71%. The average interest rates were 2.6% in 2002 and 5.1% in 2001.

Junior debentures outstanding were as follows:

                            December 31,
                            -----------
                          2002        2001
                          ----        ----
                           (in thousands)
% Rate Due
- ------ -----------------
8.00   2026 - March 31 $ 40,000     $ 40,000
7.60   2038 - June 30   125,000      125,000
Unamortized Discount     (3,282)      (3,389)
                       --------     --------
  Total                $161,718     $161,611
                       ========     ========

Interest may be deferred and payment 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.

At December 31, 2002, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                       $   30,000
2004                          150,000
2005                             -
2006                          300,000
2007                           50,000
Later Years                 1,095,736
                           ----------
  Total Principal Amount    1,625,736
Unamortized Discount           (8,674)
                           ----------
    Total                  $1,617,062
                           ==========



<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements

The notes to I&M's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to I&M. The combined footnotes begin on
page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference
                                                          ---------

Significant Accounting Policies                           Note  1

Merger                                                    Note  4

Nuclear Plant Restart                                     Note  5

Effects of Regulation                                     Note  7

Customer Choice and Industry Restructuring                Note  8

Commitments and Contingencies                             Note  9

Guarantees                                                Note 10

Sustained Earnings Improvement Initiative                 Note 11

Asset Impairments and Investment Value Losses             Note 13

Benefit Plans                                             Note 14

Business Segments                                         Note 16

Risk Management, Financial Instruments and Derivatives    Note 17

Income Taxes                                              Note 18

Supplementary Information                                 Note 20

Leases                                                    Note 22

Lines of Credit and Sale of Receivables                   Note 23

Unaudited Quarterly Financial Information                 Note 24

Related Party Transactions                                Note 29



<PAGE>


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 subsidiaries
as of December 31, 2002 and 2001, 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, 2002. 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
subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003





<PAGE>






                             KENTUCKY POWER COMPANY




<PAGE>
<TABLE>
<CAPTION>



KENTUCKY POWER COMPANY
Selected Financial Data
- -----------------------

                                                                       Year Ended December 31,
                                        --------------------------------------------------------------------------------------
                                             2002             2001             2000                1999                  1998
                                             ----             ----             ----                ----                  ----
                                                                          (in thousands)
INCOME STATEMENTS DATA:
<S>                                     <C>                 <C>                <C>               <C>                <C>
  Operating Revenues                    $  378,683          $   379,025        $  389,875        $  358,757         $  362,999
  Operating Expenses                       336,486              331,347           340,137           304,082            311,106
                                        ----------          -----------        ----------        ----------         ----------
  Operating Income                          42,197               47,678            49,738            54,675             51,893
  Nonoperating
   Items, Net                                5,206                1,248             2,070              (327)            (1,726)
  Interest Charges                          26,836               27,361            31,045            28,918             28,491
                                        ----------          -----------        ----------        ----------         ----------
  Net Income                            $   20,567          $    21,565        $   20,763        $   25,430         $   21,676
                                        ==========          ===========        ==========        ==========         ==========


                                                                       Year Ended December 31,
                                        --------------------------------------------------------------------------------------
                                            2002              2001              2000              1999                 1998
                                            ----              ----              ----              ----                 ----
                                                                          (in thousands)
BALANCE SHEETS DATA:

  Electric Utility
   Plant                                $1,295,619          $1,128,415         $1,103,064       $1,079,048          $1,043,711
  Accumulated
   Depreciation and
   Amortization                            397,304             384,104            360,648          340,008             315,546
                                        ----------          ----------         ----------       ----------          ----------
  Net Electric
   Utility Plant                        $  898,315            $744,311           $742,416         $739,040            $728,165
                                        ==========            ========           ========         ========            ========

  Total Assets                          $1,164,676          $  999,048         $1,494,543       $  986,123          $  921,847
                                        ==========          ==========         ==========       ==========          ==========

  Common Stock and
   Paid-in Capital                      $  259,200          $  209,200           $209,200         $209,200            $199,200
  Accumulated Other
   Comprehensive
   Income (Loss)                            (9,451)             (1,903)              -                -                   -
  Retained Earnings                         48,269              48,833             57,513           67,110              71,452
                                        ----------          ----------         ----------       ----------          ----------
  Total Common
   Shareholder's
   Equity                               $  298,018          $  256,130           $266,713         $276,310            $270,652
                                        ==========          ==========           ========         ========            ========

  Long-term
   Debt (a)                             $  466,632          $  346,093           $330,880         $365,782            $368,838
                                        ==========          ==========           ========         ========            ========

  Obligations Under
   Capital    Leases(a)
                                        $    7,248          $    9,583           $ 14,184         $ 15,141            $ 18,977
                                        ==========          ==========           ========         ========            ========

  Total
   Capitalization
   and Liabilities                      $1,164,676          $  999,048         $1,494,543       $  986,123          $  921,847
                                        ==========          ==========         ==========       ==========          ==========

(a) Including portion due within one year.

</TABLE>


<PAGE>



KENTUCKY POWER COMPANY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------



KPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power serving 174,000 retail customers in eastern
Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to neighboring utility systems and
power marketers including power trading transactions. KPCo also sells wholesale
power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

KPCo has a unit power agreement with AEGCo, an affiliated company, which expires
in 2004. The unit power agreement extends until December 31, 2009 for Rockport
Plant Unit 1 and until December 7, 2002 for Rockport Plant Unit 2 if AEP's
settlement restructuring agreement filed with the FERC becomes operative. The
agreement provides for KPCo to purchase 15% of the total output of the two unit
2,600-mw capacity Rockport Plant. Under the unit power agreement, there is a
demand charge for the right to receive the power, which is payable even it the
power is not taken. The amount of the demand charge is such that when added to
other amounts received by AEGCo, it will enable AEGCo to recover all its fixed
expenses including a FERC-approved rate of return on common equity.

Results of Operations
- ---------------------

Net Income for 2002 decreased $1 million or 5%. Total Revenues were flat while
increases in Operating Expenses, driven by expenses related to planned outages
at the Big Sandy plant, were offset by comparable gains in net nonoperating
income which benefited from decreases in trading incentive compensation.

Changes in Revenues
- -------------------


                                      Increase (Decrease)
                                          Year-to-Date
                                      -------------------
                                     (dollars in millions)

                                       Amount         %
                                       ------         -
Wholesale Electricity*                 $13            6
Energy Delivery*                         1            1
Sales to AEP Affiliates                (14)         (34)
                                       ---
  Total                                $ -            -
                                       ===

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

Revenues in 2002 were comparable to those of last year. Increased sales to
retail electricity customers reflecting warmer summer weather, colder days in
late 2002, and increased fuel recovery revenues were offset by lower Sales to
AEP Affiliates resulting from planned outages in 2002. KPCo's decreased
generation was due to scheduled maintenance resulting in lower availability in
the fourth quarter.

Changes in Operating Expenses
- -----------------------------


                                        Increase (Decrease)
                                            Year-to-Date
                                        -------------------
                                       (dollars in millions)

                                        Amount          %
                                        ------          -

Fuel                                    $(5.6)         (8)
Wholesale Electricity                      -           N.M.
Purchases from AEP   Affiliates
                                          2.8           2
Other Operation                          (5.4)         (9)
Maintenance                              12.6          56
Depreciation                               .7           2
Taxes Other Than
 Income Taxes                              .4           5
Income Taxes                              (.4)         (4)
                                        -----
  Total Operating Expenses              $ 5.1           2
                                        =====

N.M. = Not Meaningful

Fuel expense decreased in 2002 as a result of planned fourth quarter outages at
the Big Sandy plant for scheduled boiler maintenance. The 800 megawatt Unit 2,
representing approximately 75% of the plant's generation capacity, was off-line
from mid-September through the end of the year, thereby reducing the demand for
fuel in the fourth quarter. Purchases from AEP Affiliates for 2002 increased to
meet demand during the planned outages at the Big Sandy plant.

Other Operation expense decreased in 2002 due to reduced consumption of emission
allowances due to the planned outage; reduced accruals for trading incentive
compensation due to reduced trading activity; and improvements in transmission
expense resulting from less wholesale activity and related transmission, and an
increase in AEP transmission equalization credits. Under the AEP Transmission
Equalization Agreement, KPCo and certain eastern region affiliates share the
costs associated with the ownership of their transmission system based upon each
company's peak demand and investment. A decrease in KPCo's peak demand relative
to its affiliates' peak demand was the main reason for the increase in
transmission equalization credits. These developments were offset in part by
severance expenses related to a sustained earnings initiative (see Note 11).

Maintenance expense increased in 2002 primarily as a result of planned power
plant outages. Big Sandy plant Unit 2 was down for the fourth quarter for
planned boiler overhaul and electric plant maintenance. The Company experienced
marginal increases in overhead line maintenance expense.

Nonoperating Income Taxes for 2002 have increased as a result of increases in
pre-tax income for the year offset in part by prior-year tax return adjustments.

Other Changes
- -------------

Nonoperating Income for 2002 decreased as a result of AEP's previously announced
plan to reduce trading activity, and decreased margins on power trading activity
outside of the AEP System's traditional marketing area resulting from soft
market demand. Nonoperating Expenses decreased in 2002 as a result of decreases
in trading incentive compensation.





<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY
Statements of Income
- --------------------

                                                                                                Year Ended December 31,
                                                                                  -------------------------------------------------
                                                                                    2002                 2001                2000
                                                                                    ----                 ----                ----
                                                                                                    (in thousands)
<S>                                                                               <C>                  <C>                 <C>
OPERATING REVENUES:
  Wholesale Electricity                                                           $218,665             $205,476            $226,708
  Energy Delivery                                                                  132,054              131,183             121,346
  Sales to AEP Affiliates                                                           27,964               42,366              41,821
                                                                                  --------             --------            --------
      TOTAL OPERATING REVENUES                                                     378,683              379,025             389,875
                                                                                  --------             --------            --------

OPERATING EXPENSES:
  Fuel                                                                              65,043               70,635              74,638
  Purchased Power:
    Wholesale Electricity                                                               29                   86               1,940
    AEP Affiliates                                                                 133,002              130,204             127,707
  Other Operation                                                                   52,892               58,275              52,495
  Maintenance                                                                       35,089               22,444              25,866
  Depreciation and Amortization                                                     33,233               32,491              31,028
  Taxes Other Than Income Taxes                                                      8,240                7,854               7,251
  Income Taxes                                                                       8,958                9,358              19,212
                                                                                  --------             --------            --------
      TOTAL OPERATING EXPENSES                                                     336,486              331,347             340,137
                                                                                  --------             --------            --------

OPERATING INCOME                                                                    42,197               47,678              49,738

NONOPERATING INCOME                                                                  7,863               10,881               6,139

NONOPERATING EXPENSES                                                                  753                8,949               2,940

NONOPERATING INCOME TAXES                                                            1,904                  684               1,129

INTEREST CHARGES                                                                    26,836               27,361              31,045
                                                                                  --------             --------            --------

NET INCOME                                                                        $ 20,567             $ 21,565            $ 20,763
                                                                                  ========             ========            ========

Statements of Comprehensive Income
- ----------------------------------
                                                                                                 Year Ended December 31,
                                                                                  -------------------------------------------------
                                                                                     2002                2001                 2000
                                                                                     ----                ----                 ----
                                                                                                    (in thousands)

NET INCOME                                                                        $ 20,567              $21,565             $20,763

OTHER COMPREHENSIVE INCOME (LOSS)
  Cash Flow Interest Rate Hedge                                                      2,225               (1,903)               -
  Minimum Pension Liability                                                         (9,773)                -                   -
                                                                                  --------              -------             -------
COMPREHENSIVE INCOME                                                              $ 13,019              $19,662             $20,763
                                                                                  ========              =======             =======

Statements of Retained Earnings
- -------------------------------
                                                                                                  Year Ended December 31,
                                                                                  -------------------------------------------------
                                                                                     2002                2001                 2000
                                                                                     ----                ----                 ----
                                                                                                     (in thousands)

RETAINED EARNINGS JANUARY 1                                                        $48,833              $57,513             $67,110

NET INCOME                                                                          20,567               21,565              20,763

CASH DIVIDENDS DECLARED                                                             21,131               30,245              30,360
                                                                                   -------              -------             -------

RETAINED EARNINGS DECEMBER 31                                                      $48,269              $48,833             $57,513
                                                                                   =======              =======             =======

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>



KENTUCKY POWER COMPANY
Balance Sheets
- --------------

                                                                                                               December 31,
                                                                                                               -----------
                                                                                                        2002                2001
                                                                                                        ----                ----
                                                                                                             (in thousands)
ASSETS
<S>                                                                                                  <C>                 <C>
ELECTRIC UTILITY PLANT:
  Production                                                                                         $  275,121          $  271,070
  Transmission                                                                                          373,639             374,116
  Distribution                                                                                          425,817             402,537
  General                                                                                                55,913              65,059
  Construction Work in Progress                                                                         165,129              15,633
                                                                                                     ----------          ----------
          Total Electric Utility Plant                                                                1,295,619           1,128,415
  Accumulated Depreciation and Amortization                                                             397,304             384,104
                                                                                                     ----------          ----------
          NET ELECTRIC UTILITY PLANT                                                                    898,315             744,311
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                            6,904               6,492
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                        29,871              29,477
                                                                                                     ----------          ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                               2,304               1,947
  Accounts Receivable:
   Customers                                                                                             22,044              20,036
   Affiliated Companies                                                                                  23,802              16,012
   Miscellaneous                                                                                          2,889               3,333
   Allowance for Uncollectible Accounts                                                                    (192)               (264)
  Fuel                                                                                                   10,817              12,060
  Materials and Supplies                                                                                 16,127              15,766
  Accrued Utility Revenues                                                                                5,301               5,395
  Accrued Tax Benefit                                                                                     1,253                -
  Energy Trading Contracts                                                                               24,320              33,905
  Prepayments and other                                                                                   2,127               1,314
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          110,792             109,504
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                       101,976              97,692
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         16,818              11,572
                                                                                                     ----------          ----------

          TOTAL ASSETS                                                                               $1,164,676          $  999,048
                                                                                                     ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY

                                                                                                              December 31,
                                                                                                              -----------
                                                                                                        2002                2001
                                                                                                        ----                ----
                                                                                                             (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                                  <C>                   <C>
CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized - 2,000,000 Shares
    Outstanding - 1,009,000 Shares                                                                   $   50,450            $ 50,450
  Paid-in Capital                                                                                       208,750             158,750
  Accumulated Other Comprehensive Income (Loss)                                                          (9,451)             (1,903)
  Retained Earnings                                                                                      48,269              48,833
                                                                                                     ----------            --------
    Total Common Shareowner's Equity                                                                    298,018             256,130
  Long-term Debt                                                                                        391,632             176,093
  Long-term Debt - Affiliated Companies                                                                  60,000              75,000
                                                                                                     ----------            --------

          TOTAL CAPITALIZATION                                                                          749,650             507,223
                                                                                                     ----------            --------

OTHER NONCURRENT LIABILITIES                                                                             27,319              11,929
                                                                                                     ----------            --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year - General                                                             -                 95,000
  Long-term Debt Due within One Year -
    Affiliated Companies                                                                                 15,000                -
  Advances from Affiliates                                                                               23,386              66,200
  Accounts Payable:
    General                                                                                              46,515              23,464
    Affiliated Companies                                                                                 44,035              22,557
  Customer Deposits                                                                                       8,048               4,461
  Taxes Accrued                                                                                            -                 10,305
  Interest Accrued                                                                                        6,471               5,269
  Energy Trading and Derivative Contracts                                                                17,803              38,664
  Other                                                                                                  14,322              12,882
                                                                                                     ----------            --------

          TOTAL CURRENT LIABILITIES                                                                     175,580             278,802
                                                                                                     ----------            --------

DEFERRED INCOME TAXES                                                                                   178,313             168,304
                                                                                                     ----------            --------

DEFERRED INVESTMENT TAX CREDITS                                                                           9,165              10,405
                                                                                                     ----------            --------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                        11,488              14,917
                                                                                                     ----------            --------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                              13,161               7,468
                                                                                                     ----------            --------

COMMITMENTS AND CONTINGENCIES (Note 9)

          TOTAL CAPITALIZATION AND LIABILITIES                                                       $1,164,676            $999,048
                                                                                                     ==========            ========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY
Statements of Cash Flows
- ------------------------
                                                                                            Year Ended December 31,
                                                                               ----------------------------------------------
                                                                                  2002              2001               2000
                                                                                  ----              ----               ----
                                                                                               (in thousands)
<S>                                                                            <C>                <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                                                   $  20,567          $ 21,565          $  20,763
  Adjustments for Noncash Items:
    Depreciation and Amortization                                                 33,233            32,491             31,034
    Deferred Income Taxes                                                          9,839             6,293              3,765
    Deferred Investment Tax Credits                                               (1,240)           (1,251)            (1,252)
    Deferred Fuel Costs (net)                                                      2,998            (4,707)             2,948
    Mark-to-Market of Energy Trading Contracts                                   (12,267)           (1,454)            (4,376)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                     (9,426)           23,694            (20,930)
    Fuel, Materials and Supplies                                                     882            (7,658)             8,386
    Accrued Utility Revenues                                                          94             1,105              7,237
    Accounts Payable                                                              44,529           (22,942)            39,883
    Taxes Accrued                                                                (11,558)           (1,580)             2,025
  Disputed Tax and Interest Related to COLI                                         -                 -                 5,943
  Change in Other Assets                                                         (21,491)           (2,762)            62,653
  Change in Other Liabilities                                                     16,161            (9,446)           (62,702)
                                                                               ---------          --------          ---------
            Net Cash Flows From Operating Activities                              72,321            33,348             95,377
                                                                               ---------          --------          ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                     (178,700)          (37,206)           (36,209)
  Proceeds From Sales of Property                                                    217               216                266
                                                                               ---------          --------          ---------
            Net Cash Flows Used For Investing
             Activities                                                         (178,483)          (36,990)           (35,943)
                                                                               ---------          --------          ---------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company                                       50,000              -                  -
  Issuance of Long-term Debt                                                     274,964            75,000             69,685
  Retirement of Long-term Debt                                                  (154,500)          (60,000)          (105,000)
  Change in Short-term Debt (net)                                                   -                 -               (39,665)
  Change in Advances From Affiliates (net)                                       (42,814)           18,564             47,636
  Dividends Paid                                                                 (21,131)          (30,245)           (30,360)
                                                                               ---------          --------          ---------
            Net Cash Flows From (Used For)
             Financing Activities                                                106,519             3,319            (57,704)
                                                                               ---------          --------          ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                 357              (323)             1,730
Cash and Cash Equivalents January 1                                                1,947             2,270                540
                                                                               ---------          --------          ---------
Cash and Cash Equivalents December 31                                          $   2,304          $  1,947          $   2,270
                                                                               =========          ========          =========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $25,176,000, $27,090,000
and $28,619,000 and for income taxes was $13,040,500, $7,549,000 and $7,923,000
in 2002, 2001 and 2000, respectively. Noncash acquisitions under capital leases
were $22,021, $817,000 and $2,817,000 and in 2002, 2001 and 2000, respectively.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



KENTUCKY POWER COMPANY
Statements of Capitalization
- ----------------------------

                                                                                                                December 31,
                                                                                                                -----------
                                                                                                         2002                2001
                                                                                                         ----                ----
                                                                                                              (in thousands)

<S>                                                                                                    <C>                 <C>
COMMON SHAREHOLDER'S EQUITY                                                                            $298,018            $256,130
                                                                                                       --------            --------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                                       -                 59,383
Senior Unsecured Notes                                                                                  352,508             147,625
Notes Payable                                                                                            75,000             100,000
Junior Debentures                                                                                        39,124              39,085
Less Portion Due Within One Year                                                                        (15,000)            (95,000)
                                                                                                       --------   -         -------

  Long-term Debt Excluding Portion Due Within One Year                                                  451,632             251,093
                                                                                                       --------   -         -------

  TOTAL CAPITALIZATION                                                                                 $749,650            $507,223
                                                                                                       ========            ========

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


</TABLE>

<PAGE>


KENTUCKY POWER COMPANY
Schedule of Long-term Debt
- --------------------------



<PAGE>


First mortgage bonds outstanding were as follows:

                             December 31,
                             -----------
                           2002        2001
                           ----        ----
                            (in thousands)
% Rate Due
6.65   2003 - May 1      $   -      $ 15,000
6.70   2003 - June 1         -        15,000
6.70   2003 - July 1         -        15,000
7.90   2023 - June 1         -        14,500
Unamortized Discount         -          (117)
                         --------   --------
                         $   -      $ 59,383
                         ========   ========

First mortgage bonds were secured by a first mortgage lien on electric utility
plant.

Senior unsecured notes outstanding were as follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
- ------ ------------------
 (a)   2002 - November 19 $   -     $ 70,000
6.91   2007 - October 1     48,000    48,000
6.45   2008 - November 10   30,000    30,000
5.50   2007 - July         125,000      -
4.31   2007 - November 12   80,400      -
4.37   2007 - December 12   69,564      -
Unamortized Discount          (456)     (375)
                          --------  --------
                          $352,508  $147,625

(a) A floating interest rate is determined monthly. The rate December 31, 2001
was 4.3%.

Notes payable to parent company were as follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
4.336  2003 - May 15      $15,000   $15,000
6.501  2006 - May 15       60,000    60,000
                          -------   -------
                          $75,000   $75,000


Notes payable to banks outstanding were as follows:

                               December 31,
                               -----------
                              2002     2001
                              ----     ----
                             (in thousands)
% Rate   Due
7.45   2002 - September 20   $  -    $25,000
                             ======= =======

Junior debentures outstanding were as follows:

                            December 31,
                            -----------
                          2002         2001
                          ----         ----
                            (in thousands)
% Rate Due
8.72   2025 - June 30   $40,000      $40,000
Unamortized Discount       (876)        (915)
                        -------      -------
  Total                 $39,124      $39,085
                        =======      =======

Interest may be deferred and payment 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 the Company.

At December 31, 2002, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                        $ 15,000
2004                            -
2005                            -
2006                          60,000
2007                         322,964
Later Years                   70,000
                            --------
  Total Principal Amount     467,964
Unamortized Discount          (1,332)
                            --------
    Total                   $466,632
                            ========



<PAGE>




KENTUCKY POWER COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------

The notes to KPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to KPCo. The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference
                                                          ---------

Significant Accounting Policies                           Note  1

Merger                                                    Note  4

Rate Matters                                              Note  6

Effects of Regulation                                     Note  7

Commitments and Contingencies                             Note  9

Guarantees                                                Note 10

Sustained Earnings Improvement Initiative                 Note 11

Asset Impairments and Investment Value Losses             Note 13

Benefit Plans                                             Note 14

Business Segments                                         Note 16

Risk Management, Financial Instruments and Derivatives    Note 17

Income Taxes                                              Note 18

Leases                                                    Note 22

Lines of Credit and Sale of Receivables                   Note 23

Unaudited Quarterly Financial Information                 Note 24

Related Party Transactions                                Note 29


<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholder and Board of
Directors of Kentucky Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Kentucky Power Company as of December 31, 2002 and 2001, and the related
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. 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 financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2002 and 2001, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003


<PAGE>








                               OHIO POWER COMPANY





<PAGE>
<TABLE>
<CAPTION>



OHIO POWER COMPANY
Selected Financial Data
- -----------------------

                                                                           Year Ended December 31,
                                           ---------------------------------------------------------------------------------------
                                              2002              2001                2000               1999                1998
                                              ----              ----                ----               ----                ----
                                                                               (in thousands)
<S>                                        <C>                <C>                <C>                 <C>                <C>
INCOME STATEMENTS DATA:
  Operating Revenues                       $2,113,125         $2,098,105         $2,140,331          $1,978,826         $2,105,547
  Operating Expenses                        1,814,796          1,857,395          1,913,504           1,689,997          1,816,175
                                           ----------         ----------         ----------          ----------         ----------
  Operating Income                            298,329            240,710            226,827             288,829            289,372
  Nonoperating Items,
   Net                                          5,376             18,686             (5,004)              7,000                588
  Interest Charges                             83,682             93,603            119,210              83,672             80,035
                                           ----------         ----------         ----------          ----------         ----------
  Income Before
   Extraordinary Item                         220,023            165,793            102,613             212,157            209,925
  Extraordinary Loss                             -               (18,348)           (18,876)               -                  -
                                           ----------         ----------          ---------          ----------         ----------
  Net Income                                  220,023            147,445             83,737             212,157            209,925
  Preferred Stock
   Dividend
   Requirements                                 1,258              1,258              1,266               1,417              1,474
                                           ----------         ----------         ----------          ----------         ----------
  Earnings Applicable
   To Common Stock                         $  218,765         $  146,187         $   82,471          $  210,740         $  208,451
                                           ==========         ==========         ==========          ==========         ==========

                                                                           Year Ended December 31,
                                           ---------------------------------------------------------------------------------------
                                              2002                2001              2000               1999                1998
                                              ----                ----              ----               ----                ----
                                                                               (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                                   $5,685,826         $5,390,576         $5,577,631          $5,400,917         $5,257,841
  Accumulated
   Depreciation                             2,566,828          2,452,571          2,764,130           2,621,711          2,461,376
                                           ----------         ----------         ----------          ----------         ----------
  Net Electric Utility
   Plant                                   $3,118,998         $2,938,005         $2,813,501          $2,779,206         $2,796,465
                                           ==========         ==========         ==========          ==========         ==========
  Total Assets                             $4,457,032         $4,394,073         $6,193,975          $4,675,159         $4,344,680
                                           ==========         ==========         ==========          ==========         ==========

  Common Stock and
   Paid-in Capital                           $783,684           $783,684           $783,684            $783,577           $783,536
  Accumulated Other
   Comprehensive Income
   (Loss)                                     (72,886)              (196)              -                   -                  -
  Retained Earnings                           522,316            401,297            398,086             587,424            587,500
                                           ----------         ----------         ----------          ----------         ----------
  Total Common
   Shareholder's Equity                    $1,233,114         $1,184,785         $1,181,770          $1,371,001         $1,371,036
                                           ==========         ==========         ==========          ==========         ==========

  Cumulative Preferred Stock:
   Not Subject to
    Mandatory Redemption                   $   16,648         $   16,648           $ 16,648            $ 16,937           $ 17,370
   Subject to Mandatory
    Redemption (a)                              8,850              8,850              8,850               8,850             11,850
                                           ----------         ----------         ----------          ----------          ----------
    Total Cumulative
     Preferred Stock                       $   25,498         $   25,498         $   25,498          $   25,787         $   29,220
                                           ==========         ==========         ==========          ==========         ==========
  Long-term Debt (a)                       $1,067,314         $1,203,841         $1,195,493          $1,151,511         $1,084,928
                                           ==========         ==========         ==========          ==========         ==========
  Obligations Under
   Capital Leases (a)                      $   65,626         $   80,666         $  116,581          $  136,543         $  142,635
                                           ==========         ==========         ==========          ==========         ==========
  Total Capitalization
   and Liabilities                         $4,457,032         $4,394,073         $6,193,975          $4,675,159         $4,344,680
                                           ==========         ==========         ==========          ==========         ==========

(a) Including portion due within one year.

</TABLE>


<PAGE>




OHIO POWER COMPANY
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------
<PAGE>






Ohio Power Company (OPCo) is a public utility engaged in the generation,
purchase, sale, transmission and distribution of electric power to 702,000
retail customers in northwestern, east central, eastern and southern sections of
Ohio. OPCo supplies electric power to the AEP Power Pool and shares the revenues
and costs of the AEP Power Pool's wholesale sales to neighboring utility systems
and power marketers including power trading transactions. OPCo also sells
wholesale power to municipalities and cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges or the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

Results of Operations
- ---------------------

Income Before Extraordinary Item increased $54 million or 33% in 2002 mainly due
to reductions in operating expenses, predominantly fuel, and interest charges.

Income Before Extraordinary Item increased $63 million or 62% in 2001 primarily
due to the effect of a court decision related to a corporate owned life
insurance (COLI) program recorded in 2000. In February 2001 the U.S. District
Court for the Southern District of Ohio ruled against AEP and certain of its
subsidiaries, including OPCo, in a suit over deductibility of interest claimed
in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo paid
the disputed taxes and interest attributable to the COLI interest deductions for
taxable years 1991-98. The payments were included in Other Property and
Investments pending the resolution of this matter. Net Income was also favorably
impacted by the growth in and strong performance by the wholesale business. The
effects of the COLI decision in 2000 and favorable wholesale business in 2001
were offset in part by the commencement of the amortization of transition
regulatory assets in 2001, the effect of mild winter weather and the economic
downturn.

Operating Revenues
- ------------------

Operating Revenues increased 1% in 2002 mainly as a result of increased
residential and commercial sales due to demand caused by weather conditions.
Changes in the components of Operating Revenues were:

                      Increase (Decrease)
                      From Previous Year
                      ------------------
                    (Dollars in Millions)
                      2002          2001
                -----------------------------
                     Amount %     Amount %
                     ------ -     ------ -
Retail*              $ 11   2     $(66) (8)
Wholesale
 Marketing             10   5      (19) (8)
Unrealized MTM          2   8       33  N.M.
Other                   1   1       (4) (5)
                     ----         ----
Total
 Wholesale
 Electricity*          24   2      (56) (5)
Energy
 Delivery*             37   7       85  18
Sales to AEP
 Affiliates           (46) (9)     (71)(12)
                     ----         ----

     Total           $ 15   1     $(42) (2)
                     ====         ====

* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

During the summer months, cooling degree days increased 39%. For the fall
season, heating degree days increased 32%. This reflects a return to more normal
weather conditions since 2001 weather was abnormally mild. Sales to AEP
Affiliates decreased due to a 15% decrease in price, reflective of lower average
fuel cost, while MWH sales rose slightly.

Operating Revenues decreased 2% in 2001 due to decreased sales to the AEP Power
Pool. This was the result of an affiliate being able to supply more power to the
Power Pool from two nuclear units that returned to service in June and December
2000.

Operating Expenses
- ------------------

Operating Expenses decreased 2% in 2002 mostly due to reductions in Fuel.
Operating Expenses in 2001 also decreased 3%. This reduction was the result of
lower Fuel and Income Taxes partially offset by amortization of transition
regulatory assets.

Changes in the components of Operating Expenses were:

                     Increase (Decrease)
                      From Previous Year
                      ------------------
                    (dollars in millions)
                    2002           2001
                    ----           ----
                   Amount   %     Amount  %
                   ------   -     ------  -

Fuel              $(102)  (15)    $(85)  (11)
Wholesale
 Electricity
 Purchased Power      4     6       15    30
AEP Affiliates
 Purchased Power      8    14       12    23
Other Operation      16     4       (4)   (1)
Maintenance          (6)   (4)      18    15
Depreciation
 and Amortization     9     4       84    54
Taxes Other Than
  Income Taxes       16    10      (10)   (6)
Income Taxes         12    12      (86)  (46)
                  -----           ----
  Total Operating
   Expenses       $ (43)   (2)    $(56)   (3)
                  =====           ====

The Fuel expense decrease for 2002 reflects a reduction of 19% in average cost
of fuel for generation, offset in part by a slight increase in MWH generated.
The decrease in fuel costs are the result of purchasing coal at lower prices on
the open market in 2002 instead of affiliated company coal.

Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net generation
because of decreased sales to the AEP Power Pool caused by an affiliate's two
nuclear units returning to service.

Wholesale Electricity Purchased Power expense increased in 2002. This was the
result of a 11% increase of MWH sales, partially offset by a decrease in price.
In 2001 the increase was due to increases in MWH purchases from third parties
because of the non-availability of associated nuclear power for resale to
wholesale customers and to meet internal demand.

AEP Affiliates Purchased Power expense increased in 2002 as a result of an 18%
increase of MWH purchased from affiliates with a slight decrease in the average
price. The increase for 2001 was also a result of increased purchases through
the AEP Power Pool.

Maintenance expense increased in 2001 mainly due to boiler repairs at Amos,
Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler inspections
at the Amos and Cardinal Plants.

In 2001, the commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
retail electricity supply under Ohio deregulation accounted for the significant
increase in Depreciation and Amortization expense.

The 2002 increase in Taxes Other Than Income Taxes is the result of increases in
state excise tax created from a change in the base tax calculation. The decrease
in 2001 was due to a decrease in property tax expense reflecting a reduction in
rates on generation property under the Ohio Restructuring law partially offset
by a new state excise tax.

Income Taxes increased in 2002 due to an increase in both federal and state tax
expenses. Federal taxes increased due to higher pre-tax operating income offset
in part by changes in certain book/tax timing differences accounted for on a
flow-thru basis. State taxes increased predominately as a result of the State of
Ohio's tax legislation revision involving utility deregulation.

Income Taxes decreased in 2001 due to an unfavorable ruling in AEP's suit
against the government over interest deductions claimed relating to AEP's COLI
program which was recorded in 2000 and a decrease in pre-tax book income.

Nonoperating Income and Nonoperating Expense
- --------------------------------------------

Nonoperating Expenses decreased during 2002 due to reductions in variable
incentive compensation expenses associated with wholesale trading.

Nonoperating Income and Nonoperating Expenses increased in 2001 as a result of
an increase in the level of trading activity outside of the AEP System's
traditional marketing area.

The 2002 increase in Nonoperating Income Tax Expense is a result of the
favorable tax benefit from the sale of the Ohio Coal companies in 2001. This
event also caused the decrease for 2001.

Interest Charges
- ----------------

The 2002 decrease in Interest Charges was primarily due to a decrease in the
outstanding balances of long-term debt, the refinancing of debt at favorable
interest rates and a reduction in short-term interest rates.

The major reason for the decrease in Interest Charges in 2001 was the
recognition in 2000 of deferred interest payments to the IRS related to COLI
disallowances.

Extraordinary Loss
- ------------------

In the second quarter of 2001 an extraordinary loss of $18 million net of tax
was recorded to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation. In 2000 the application of regulatory accounting for generation
under SFAS 71 was discontinued which resulted in an after tax extraordinary loss
of $19 million.



<PAGE>
<TABLE>
<CAPTION>


OHIO POWER COMPANY
Statements of Income
- --------------------

                                                                                                Year Ended December 31,
                                                                                -------------------------------------------------
                                                                                   2002                2001                2000
                                                                                   ----                ----                ----
                                                                                                 (in thousands)
<S>                                                                             <C>                 <C>                <C>
OPERATING REVENUES:
  Wholesale Electricity                                                         $1,058,250          $1,034,026         $1,090,297
  Energy Delivery                                                                  589,673             552,713            467,587
  Sales to AEP Affiliates                                                          465,202             511,366            582,447
                                                                                ----------          ----------         ----------
            TOTAL OPERATING REVENUES                                             2,113,125           2,098,105          2,140,331
                                                                                ----------          ----------         ----------

OPERATING EXPENSES:
  Fuel                                                                             584,730             686,568            771,969
  Purchased Power:
    Wholesale Electricity                                                           67,385              63,441             48,657
    AEP Affiliates                                                                  71,154              62,585             50,741
  Other Operation                                                                  416,533             400,790            404,410
  Maintenance                                                                      136,609             142,878            124,735
  Depreciation and Amortization                                                    248,557             239,982            155,944
  Taxes Other Than Income Taxes                                                    176,247             159,778            169,527
  Income Taxes                                                                     113,581             101,373            187,521
                                                                                ----------          ----------         ----------
            TOTAL OPERATING EXPENSES                                             1,814,796           1,857,395          1,913,504
                                                                                ----------          ----------         ----------

OPERATING INCOME                                                                   298,329             240,710            226,827

NONOPERATING INCOME                                                                 51,953              70,108             57,163

NONOPERATING EXPENSES                                                               28,567              53,802             44,009

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                            18,010              (2,380)            18,158

INTEREST CHARGES                                                                    83,682              93,603            119,210
                                                                                ----------          ----------         ----------

INCOME BEFORE EXTRAORDINARY ITEM                                                   220,023             165,793            102,613

EXTRAORDINARY LOSS - DISCONTINUANCE OF
  REGULATORY ACCOUNTING FOR GENERATION -
  Net of tax (See Note 2)                                                             -                (18,348)           (18,876)
                                                                                ----------          ----------         ----------

NET INCOME                                                                         220,023             147,445             83,737

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                1,258               1,258              1,266
                                                                                ----------          ----------         ----------

EARNINGS APPLICABLE TO COMMON STOCK                                             $  218,765          $  146,187         $   82,471
                                                                                ==========          ==========         ==========

Statements of Comprehensive Income
- ----------------------------------
                                                                                                 Year Ended December 31,
                                                                                  -----------------------------------------------
                                                                                                     (in thousands)

                                                                                   2002                2001                2000
                                                                                   ----                ----                ----

NET INCOME                                                                        $220,023           $147,445             $83,737

OTHER COMPREHENSIVE INCOME (LOSS)
  Foreign Currency Exchange Rate Hedge                                                (542)              (196)               -
  Minimum Pension Liability                                                        (72,148)              -                   -
                                                                                  --------           --------             -------
COMPREHENSIVE INCOME                                                              $147,333           $147,249             $83,737
                                                                                  ========           ========             =======

The common stock of OPCo is wholly owned by AEP.

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



OHIO POWER COMPANY
Statement of Retained Earnings
- ------------------------------

                                                                                             Year Ended December 31,
                                                                                  -----------------------------------------------
                                                                                     2002              2001             2000
                                                                                     ----              ----             ----
                                                                                                   (in thousands)

Retained Earnings January 1                                                       $401,297           $398,086            $587,424
  Net Income                                                                       220,023            147,445              83,737
                                                                                  --------           --------            --------
                                                                                   621,320            545,531             671,161
                                                                                  --------           --------            --------

Deductions:
  Cash Dividends Declared:
    Common Stock                                                                    97,746            142,976             271,813
    Cumulative Preferred Stock:
       4.08%  Series                                                                    58                 58                  59
       4.20%  Series                                                                    96                 96                  96
       4.40%  Series                                                                   139                139                 139
       4-1/2% Series                                                                   439                439                 442
       5.90%  Series                                                                   428                428                 428
       6.02%  Series                                                                    66                 66                  66
       6.35%  Series                                                                    32                 32                  32
                                                                                  --------           --------            --------
              Total Dividends                                                       99,004            144,234             273,075
                                                                                  --------           --------            --------

Retained Earnings December 31                                                     $522,316           $401,297            $398,086
                                                                                  ========           ========            ========

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


</TABLE>



<PAGE>
<TABLE>
<CAPTION>


OHIO POWER COMPANY
Balance Sheets
- --------------

                                                                                                   December 31,
                                                                                                   -----------
                                                                                           2002                 2001
                                                                                           ----                 ----
                                                                                                 (in thousands)
ASSETS
<S>                                                                                   <C>                    <C>
ELECTRIC UTILITY PLANT:
  Production                                                                          $3,116,825             $3,007,866
  Transmission                                                                           905,829                891,283
  Distribution                                                                         1,114,600              1,081,122
  General                                                                                260,153                245,232
  Construction Work in Progress                                                          288,419                165,073
                                                                                      ----------             ----------
          Total Electric Utility Plant                                                 5,685,826              5,390,576
  Accumulated Depreciation and Amortization                                            2,566,828              2,452,571
                                                                                      ----------             ----------
          NET ELECTRIC UTILITY PLANT                                                   3,118,998              2,938,005
                                                                                      ----------             ----------

OTHER PROPERTY AND INVESTMENTS                                                            61,686                 62,303
                                                                                      ----------             ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                       103,230                 99,706
                                                                                      ----------             ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                5,285                  8,848
  Accounts Receivable:
   Customers                                                                              95,100                 84,694
   Affiliated Companies                                                                  124,244                148,563
   Miscellaneous                                                                          19,281                 20,409
   Allowance for Uncollectible Accounts                                                     (909)                (1,379)
  Fuel                                                                                    87,409                 84,724
  Materials and Supplies                                                                  85,379                 88,768
  Energy Trading Contracts                                                                92,108                114,280
  Prepayments and Other                                                                   12,083                 20,865
                                                                                      ----------             ----------
          TOTAL CURRENT ASSETS                                                           519,980                569,772
                                                                                      ----------             ----------

REGULATORY ASSETS                                                                        568,641                644,625
                                                                                      ----------             ----------

DEFERRED CHARGES                                                                          84,497                 79,662
                                                                                      ----------             ----------

                    TOTAL ASSETS                                                      $4,457,032             $4,394,073
                                                                                      ==========             ==========


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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


OHIO POWER COMPANY

                                                                                                     December 31,
                                                                                                     -----------
                                                                                              2002                2001
                                                                                              ----                ----
                                                                                                    (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                       <C>                  <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 40,000,000 Shares
    Outstanding - 27,952,473 Shares                                                       $  321,201           $  321,201
  Paid-in Capital                                                                            462,483              462,483
  Accumulated Other Comprehensive Income (Loss)                                              (72,886)                (196)
  Retained Earnings                                                                          522,316              401,297
                                                                                          ----------           ----------
    Total Common Shareholder's Equity                                                      1,233,114            1,184,785
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption                                                       16,648               16,648
    Subject to Mandatory Redemption                                                            8,850                8,850
  Long-term Debt                                                                             917,649            1,203,841
                                                                                          ----------           ----------

          TOTAL CAPITALIZATION                                                             2,176,261            2,414,124
                                                                                          ----------           ----------

OTHER NONCURRENT LIABILITIES                                                                 227,689              130,386
                                                                                          ----------           ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year - General                                                89,665                 -
  Long-term Debt Due Within One Year - Affiliated Companies                                   60,000                 -
  Short-term Debt - Affiliated Companies                                                     275,000                 -
  Advances From Affiliates                                                                   129,979              300,213
  Accounts Payable - General                                                                 170,563              131,057
  Accounts Payable - Affiliated Companies                                                    145,718              176,520
  Customer Deposits                                                                           12,969                5,452
  Taxes Accrued                                                                              111,778              126,770
  Interest Accrued                                                                            18,809               17,679
  Obligations Under Capital Leases                                                            14,360               16,405
  Energy Trading Contracts                                                                    61,839               98,081
  Other                                                                                       80,608               90,431
                                                                                          ----------           ----------

          Total CURRENT LIABILITIES                                                        1,171,288              962,608
                                                                                          ----------           ----------

DEFERRED INCOME TAXES                                                                        794,387              797,889
                                                                                          ----------           ----------

DEFERRED INVESTMENT TAX CREDITS                                                               18,748               21,925
                                                                                          ----------           ----------

LONG-TERM ENERGY TRADING CONTRACTS                                                            39,702               50,459
                                                                                          ----------           ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                   28,957               16,682
                                                                                          ----------           ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                  $4,457,032           $4,394,073
                                                                                          ==========           ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>



OHIO POWER COMPANY
Statements of Cash Flows
- ------------------------
                                                                                            Year Ended December 31,
                                                                                  ----------------------------------------------
                                                                                    2002              2001             2000
                                                                                    ----              ----             ----
                                                                                                (in thousands)
<S>                                                                               <C>                <C>                <C>
OPERATING ACTIVITIES:
  Net Income                                                                      $ 220,023          $ 147,445          $ 83,737
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization                                        248,557            252,123           200,350
    Deferred Income Taxes                                                            46,010            215,833           (65,956)
    Deferred Investment Tax Credits                                                  (3,177)            (3,289)           (3,399)
    Deferred Fuel Costs (net)                                                          -                  -              (56,869)
    Extraordinary Loss                                                                                  18,348            18,876
    Mark to Market of Energy Trading Contracts                                      (28,693)           (59,833)           (5,614)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                        14,571             51,640            51,430
    Fuel, Materials and Supplies                                                        704              4,852            46,645
    Accrued Utility Revenues                                                          3,081                264            45,311
    Accounts Payable                                                                  8,704              9,887            56,069
    Customer Deposits                                                                 7,517            (34,284)           31,540
    Taxes Accrued                                                                   (14,992)           (96,331)           60,919
  Disputed Tax and Interest Related to COLI                                            -                  -              110,494
  Employee Benefit and Other Noncurrent Liabilities                                 110,298           (392,026)          145,573
  Impairment Loss                                                                     1,757               -                 -
  Change in Other Assets                                                             (2,233)            79,831          (439,448)
  Change in Other Liabilities                                                      (133,154)          (107,704)          359,640
                                                                                  ---------          ---------         ---------
            Net Cash Flows From Operating Activities                                478,973             86,756           639,298
                                                                                  ---------          ---------         ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                        (354,797)          (344,571)         (254,016)
  Proceeds From Sales of Property and Other                                           6,499             16,778             6,354
  Investment in Coal Companies                                                         -               (32,115)             -
                                                                                  ---------          ---------         ---------
            Net Cash Flows Used For
              Investing Activities                                                 (348,298)          (359,908)         (247,662)
                                                                                  ---------          ---------         ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                                           -               300,000            74,748
  Change in Advances From Affiliates (net)                                         (170,234)           392,699           (92,486)
  Retirement of Cumulative Preferred Stock                                             -                  -                 (182)
  Retirement of Long-term Debt                                                     (140,000)          (297,858)          (30,663)
  Change in Short-term Debt (net)                                                   275,000               -             (194,918)
  Dividends Paid on Common Stock                                                    (97,746)          (142,976)         (271,813)
  Dividends Paid on Cumulative Preferred Stock                                       (1,258)            (1,258)           (1,262)
                                                                                  ---------          ---------         ---------
            Net Cash Flows From (Used For)
              Financing Activities                                                 (134,238)           250,607          (516,576)
                                                                                  ---------          ---------         ---------

Net Decrease in Cash and Cash Equivalents                                            (3,563)           (22,545)         (124,940)
Cash and Cash Equivalents January 1                                                   8,848             31,393           156,333
                                                                                  ---------          ---------         ---------
Cash and Cash Equivalents December 31                                               $ 5,285            $ 8,848           $31,393
                                                                                    =======            =======           =======

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $81,041,000,
$94,747,000 and $87,120,000 and for income taxes was $105,058,000, $(22,417,000)
and $142,710,000 in 2002, 2001 and 2000, respectively. Noncash acquisitions
under capital leases were $106,000, $2,380,000 and $17,005,000 in 2002, 2001 and
2000, respectively.

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>



OHIO POWER COMPANY
Statements of Capitalization
- ----------------------------

                                                                                December 31,
                                                                                -----------
                                                                           2002              2001
                                                                           ----              ----
                                                                               (in thousands)

<S>                                                                     <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                             $1,233,114        $1,184,785
                                                                        ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 3,762,403
                 $25  par value - authorized shares 4,000,000

            Call Price                                      Shares
           December 31,    Number of Shares Redeemed     Outstanding
Series         2002 (a)     Year Ended December 31,   December 31, 2002
- ------     -------------  --------------------------- -----------------
                            2002      2001      2000
                            ----      ----      ----

Not Subject to Mandatory Redemption-$100 Par:

4.08%          $103          -         -         -         14,595             1,460             1,460
4.20%           103.20       -         -         276       22,824             2,282             2,282
4.40%           104          -         -         432       31,512             3,151             3,151
4-1/2%          110          -         -       2,181       97,546             9,755             9,755
                                                                         ----------        ----------

                                                                             16,648            16,648
                                                                         ----------        ----------
Subject to Mandatory Redemption-$100 Par (b):

5.90% (c)      $ -           -        -          -         72,500             7,250             7,250
6.02% (d)        -           -        -          -         11,000             1,100             1,100
6.35% (d)        -           -        -          -          5,000               500               500
                                                                         ----------        ----------

                                                                              8,850             8,850
                                                                         ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                        136,633           141,544
Installment Purchase Contracts                                              233,340           233,235
Senior Unsecured Notes                                                      397,341           396,962
Notes Payable to Affiliated Company                                         300,000           300,000
Junior Debentures                                                              -              132,100
Less Portion Due Within One Year                                           (149,665)             -
                                                                         ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                      917,649         1,203,841
                                                                         ----------        ----------

  TOTAL CAPITALIZATION                                                   $2,176,261        $2,414,124
                                                                         ==========        ==========

(a)  The cumulative preferred stock is callable at the price indicated plus
     accrued dividends.
(b)  Sinking fund provisions require the redemption of 35,000 shares in 2003 and
     57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
     provisions of each series subject to mandatory redemption have been met by
     purchase of shares in advance of the due dates. Shares previously purchased
     may be applied to the sinking fund requirement. At the company's option,
     all shares are redeemable at $100 per share plus accrued and unpaid
     dividends with at least 30 days notice beginning on or after November 1,
     2003 for the 5.09% series, October 1, 2003 for the 6.02% series, and April
     1, 2003 for the 6.35% series.
(c)  Commencing in 2004 and continuing through the year 2008, a sinking fund for
     the 5.90% cumulative preferred stock will require the redemption of 22,500
     shares each year and the redemption of the remaining shares outstanding on
     January 1, 2009, in each case at $100 per share. Shares previously redeemed
     may be applied to meet sinking fund requirements.
(d)  Commencing in 2003 and continuing through 2007 sinking fund provisions will
     require the redemption of 20,000 shares each year of the 6.02% series and
     15,000 shares each year of the 6.35% series, in each case at $100 per
     share. All remaining outstanding shares must be redeemed in 2008. Shares
     previously redeemed may be applied to meet the sinking fund requirements.

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

</TABLE>



<PAGE>


OHIO POWER COMPANY
Schedule of Long-term Debt
- --------------------------

First mortgage bonds outstanding were as follows:
                             December 31,
                             -----------
                            2002        2001
                            ----        ----
                             (in thousands)
% Rate Due
6.75   2003 - April 1    $ 29,850   $ 29,850
6.55   2003 - October 1    27,315     27,315
6.00   2003 - November 1   12,500     12,500
6.15   2003 - December 1   20,000     20,000
(a)    2022 - February 10    -         5,000
7.75   2023 - April 1       5,000      5,000
7.375  2023 - October 1    20,250     20,250
7.10   2023 - November 1   12,000     12,000
7.30   2024 - April 1      10,000     10,000
Unamortized Discount         (282)      (371)
                         --------   --------
  Total                  $136,633   $141,544
                         ========   ========

(a) Redeemed on May 10, 2002.

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                               December 31,
                               -----------
                              2002     2001
                              ----     ----
                              (in thousands)
% Rate Due

Mason County, West
 Virginia:
5.45%  2016 - December 1  $ 50,000  $ 50,000
Marshall County, West
 Virginia:
5.45%  2014 - July 1        50,000    50,000
5.90%  2022 - April 1       35,000    35,000
6.85%  2022 - June 1        50,000    50,000
Ohio Air Quality
 Development
5.15%  2026 - May 1         50,000    50,000
Unamortized Discount        (1,660)   (1,765)
  Total                   $233,340  $233,235
                          ========  ========

Under the terms of the installment purchase contracts, OPCo is required to pay
amounts





sufficient to enable the payment of interest on and the principal of (at stated
maturities and upon mandatory redemptions) related pollution control revenue
bonds issued to finance the construction of pollution control facilities at
certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                            -----------
                           2002       2001
                           ----       ----
                           (in thousands)
% Rate Due
- ------ ------------------
6.75   2004 - July 1    $100,000   $100,000
7.00   2004 - July 1      75,000     75,000
6.73   2004 - November 1  48,000     48,000
6.24   2008 - December 4  37,225     37,225
7-3/8  2038 - June 30    140,000    140,000
Unamortized Discount      (2,884)    (3,263)
                        --------   --------
  Total                 $397,341   $396,962
                        ========   ========

Notes payable to parent company were as follows:

                              December 31,
                              -----------
                             2002      2001
                             ----      ----
                             (in thousands)
% Rate Due
4.336% 2003 - May 15      $ 60,000   $ 60,000
6.501% 2006 - May 15       240,000    240,000
                          --------   --------
  Total                   $300,000   $300,000
                          ========   ========

Junior debentures outstanding were as follows:

                               December 31,
                               -----------
                             2002      2001
                             ----      ----
                             (in thousands)
% Rate Due
- ------ -----------------
(a)    2025 - September 30 $   -    $ 85,000
(a)    2027 - March 31         -      50,000
Unamortized Discount           -      (2,900)
                           -------- --------
  Total                    $   -    $132,100
                           ======== ========

(a) Redeemed on July 24, 2002

At December 31, 2002 future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                       $  149,665
2004                          223,000
2005                             -
2006                          240,000
2007                             -
Later Years                   459,475
                           ----------
  Total Principal Amount    1,072,140
Unamortized Discount            4,826
                           ----------
    Total                  $1,067,314
                           ==========



<PAGE>




OHIO POWER COMPANY
Index to Combined Notes to Financial Statements
- -----------------------------------------------

The notes to OPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to OPCo. The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note  1

Extraordinary Items and Cumulative Effect            Note  2

Effects of Regulation                                Note  7

Customer Choice and Industry Restructuring           Note  8

Commitments and Contingencies                        Note  9

Guarantees                                           Note 10

Sustained Earnings Improvement Initiative            Note 11

Acquisitions, Dispositions and Discontinued
  Operations                                         Note 12

Asset Impairments and Investment Value Losses        Note 13

Benefit Plans                                        Note 14

Business Segments                                    Note 16

Risk Management, Financial Instruments
  and Derivatives                                    Note 17

Income Taxes                                         Note 18

Supplementary Information                            Note 20

Leases                                               Note 22

Lines of Credit and Sale of Receivables              Note 23

Unaudited Quarterly Financial Information            Note 24

Related Party Transactions                           Note 29




<PAGE>


INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of
Directors of Ohio Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Ohio Power Company as of December 31, 2002 and 2001, and the related
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2002. 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 financial statements present fairly, in all material
respects, the financial position of Ohio Power Company as of December 31, 2002
and 2001, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003



<PAGE>








                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                                 AND SUBSIDIARY








<PAGE>
<TABLE>
<CAPTION>

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Selected Consolidated Financial Data
- ------------------------------------
                                                                               Year Ended December 31,
                                                 ---------------------------------------------------------------------------------
                                                     2002              2001             2000               1999             1998
                                                     ----              ----             ----               ----             ----
                                                                                   (in thousands)
INCOME STATEMENTS DATA:
<S>                                              <C>                  <C>              <C>              <C>               <C>
  Operating Revenues                             $  793,647           $957,000         $956,398         $749,390          $780,159
  Operating Expenses                                708,926            860,012          859,729          650,677           665,085
                                                 ----------           --------         --------         --------          --------
  Operating Income                                   84,721             96,988           96,669           98,713           115,074
  Nonoperating Items,
   Net                                               (3,239)                20            8,974              946               (91)
  Interest Charges                                   40,422             39,249           38,980           38,151            38,074
                                                 ----------           --------         --------         --------          --------
  Net Income                                         41,060             57,759           66,663           61,508            76,909
  Preferred Stock Dividend
    Requirements                                        213                213              212              212               213
  Gain On Reacquired
    Preferred Stock                                       1               -                -                -                 -
                                                 ----------           --------         --------         --------          --------
  Earnings Applicable to
    Common Stock                                 $   40,848           $ 57,546         $ 66,451         $ 61,296          $ 76,696
                                                 ==========           ========         ========         ========          ========


                                                                                     December 31,
                                                 ---------------------------------------------------------------------------------
                                                     2002              2001              2000             1999              1998
                                                     ----              ----              ----             ----              ----
                                                                                    (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant                         $2,759,504         $2,695,099       $2,604,670       $2,459,705        $2,391,722
  Accumulated Depreciation
   and Amortization                               1,239,855          1,184,443        1,150,253        1,114,255         1,082,081
                                                 ----------         ----------       ----------       ----------        ----------
  Net Electric Utility
   Plant                                         $1,519,649         $1,510,656       $1,454,417       $1,345,450        $1,309,641
                                                 ==========         ==========       ==========       ==========        ==========

  Total Assets                                   $1,776,690         $1,748,911       $2,138,423       $1,524,846        $1,471,089
                                                 ==========         ==========       ==========       ==========        ==========

  Common Stock and Paid-in
   Capital                                       $  337,246         $  337,246       $  337,246       $  337,246        $  337,246
  Accumulated Other Comprehensive
   Income (Loss)                                    (54,473)              -                -                -                 -
  Retained Earnings                                 116,474            142,994          137,688          139,237           142,941
                                                 ----------         ----------       ----------       ----------        ----------
  Total Common
   Shareholder's Equity                          $  399,247         $  480,240       $  474,934       $  476,483        $  480,187
                                                 ==========         ==========       ==========       ==========        ==========

  Cumulative Preferred
   Stock:
    Not Subject to
     Mandatory Redemption                        $    5,267         $    5,267       $    5,267       $    5,270        $    5,271
                                                 ==========         ==========       ==========       ==========        ==========

  Preferred Securities of
   Subsidiary Trust                              $   75,000         $   75,000       $   75,000       $   75,000        $   75,000
                                                 ==========         ==========       ==========       ==========        ==========

  Long-term Debt (a)                             $  545,437         $  451,129       $  470,822       $  384,516        $  384,064
                                                 ==========         ==========       ==========       ==========        ==========

  Total Capitalization and
   Liabilities                                   $1,776,690         $1,748,911       $2,138,423       $1,524,846        $1,471,089
                                                 ==========         ==========       ==========       ==========        ==========

(a) Including portion due within one year.
</TABLE>


<PAGE>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Management's Narrative Analysis of Results of Operations
- --------------------------------------------------------



<PAGE>


Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO
also sells electric power at wholesale to other utilities, municipalities and
rural electric cooperatives.

Wholesale power marketing activities are conducted on PSO's behalf by AEPSC.
PSO, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

Results of Operations
- ---------------------

In 2002, Net Income decreased by $17 million or 29% primarily resulting from
reduced wholesale margins and increased depreciation expense.

Changes in Operating Revenues
- -----------------------------

Operating revenues decreased in 2002 as a result of reduced wholesale margins, a
decline in fuel recovery revenue and decreases due to the interchange cost
reconstruction (ICR) adjustments (see Note 6).

                                    Increase (Decrease)
                                    From Previous Year
                                    ------------------
                                   (dollars in millions)

                                     Amount          %
                                     ------          -

Wholesale Electricity*               $(149.7)      (23)
Energy Delivery*                        13.6         5
Sales to AEP Affiliates                (27.3)      (74)
                                     -------
   Total Operating Revenues          $(163.4)      (17)
                                     =======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.



Changes in Operating Expenses
- -----------------------------

                                     Increase (Decrease)
                                     From Previous Year
                                     ------------------
                                   (dollars in millions)

                                      Amount         %
                                      ------         -

Fuel                                $(215.3)       (47)
Purchased Power:
 Wholesale Electricity                 23.3         96
 AEP Affiliates                        45.7        104
Other Operation                        (4.1)        (3)
Maintenance                             1.9          4
Depreciation and
 Amortization                           5.6          7
Taxes Other Than
 Income Taxes                           2.1          7
Income Taxes                          (10.3)       (30)
                                   --------        ---
     Total                          $(151.1)       (18)
                                    =======        ===

N.M. = Not Meaningful

The decrease in Fuel expense in 2002 was primarily due to lower market prices
for natural gas and fuel oil, and deferral of underrecovered fuel costs due to
the ICR adjustments through the fuel clause recovery mechanism (see Note 6) and
to the amortization of previously overrecovered fuel costs.

The increase in Electricity Marketing Purchased Power expense in 2002 resulted
mainly from ICR adjustments (see Note 6), partially offset by a decrease in
energy prices.

The increase in the AEP Affiliates Purchased Power expense in 2002 resulted
mainly from the ICR adjustments (see Note 6).

Other Operation expense decreased in 2002 primarily due to lower transmission
expenses and decreased factoring expenses due to reduced revenues.

Maintenance expense increased, in 2002 largely as a result of increased expenses
to repair damage to overhead lines caused by a winter storm in 2002.

Depreciation and Amortization expense increased in 2002 primarily due to the
additional depreciable capitalized costs involved in repowering Northeast
Station Units 1 & 2 completed in 2001.

Taxes Other Than Income Taxes increased in 2002 primarily due to the increase in
ad valorem taxes.


Income Taxes decreased in 2002 primarily due to a decrease in pre-tax income.

Other Changes
- -------------

Nonoperating Expenses increased primarily due to the write-down of certain
non-utility investments in 2002.


<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Income
- ---------------------------------

                                                                                            Year Ended December 31,
                                                                              -----------------------------------------------
                                                                               2002                 2001              2000
                                                                               ----                 ----              ----
                                                                                                (in thousands)
<S>                                                                           <C>                  <C>               <C>
OPERATING REVENUES:
  Wholesale Electricity                                                       $508,661             $658,352          $696,626
  Energy Delivery                                                              275,547              261,877           245,124
  Sales to AEP Affiliates                                                        9,439               36,771            14,648
                                                                              --------             --------          --------

            TOTAL OPERATING REVENUES                                           793,647              957,000           956,398
                                                                              --------             --------          --------

OPERATING EXPENSES:
  Fuel                                                                         246,199              461,470           402,933
  Purchased Power:
    Wholesale Electricity                                                       47,507               24,187            88,088
    AEP Affiliates                                                              89,454               43,758            60,788
  Other Operation                                                              133,538              137,678           121,697
  Maintenance                                                                   48,060               46,188            45,858
  Depreciation and Amortization                                                 85,896               80,245            76,418
  Taxes Other Than Income Taxes                                                 34,077               31,973            28,688
  Income Taxes                                                                  24,195               34,513            35,259
                                                                              --------             --------          --------

            TOTAL OPERATING EXPENSES                                           708,926              860,012           859,729
                                                                              --------             --------          --------

OPERATING INCOME                                                                84,721               96,988            96,669

NONOPERATING INCOME                                                              1,920                2,112             8,807

NONOPERATING EXPENSES                                                            6,971                1,740             1,139

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                        (1,812)                 352            (1,306)

INTEREST CHARGES                                                                40,422               39,249            38,980
                                                                              --------             --------          --------

NET INCOME                                                                      41,060               57,759            66,663

GAIN ON REACQUIRED PREFERRED STOCK                                                   1                 -                 -

LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS                                        213                  213               212
                                                                              --------             --------          --------

EARNINGS APPLICABLE TO COMMON STOCK                                           $ 40,848             $ 57,546          $ 66,451
                                                                              ========             ========          ========


Consolidated Statements of Comprehensive Income
- -----------------------------------------------
                                                                                             Year Ended December 31,
                                                                              -----------------------------------------------
                                                                                2002                 2001               2000
                                                                                ----                 ----               ----
                                                                                                (in thousands)

NET INCOME                                                                    $ 41,060              $57,759           $66,663
OTHER COMPREHENSIVE INCOME (LOSS):
  Cash Flow Power Hedges                                                           (42)                -                 -
  Minimum Pension Liability                                                    (54,431)                -                 -
                                                                              --------              -------           -------
COMPREHENSIVE INCOME (LOSS)                                                   $(13,413)             $57,759           $66,663
                                                                              ========              =======           =======


The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.


</TABLE>


<PAGE>
<TABLE>
<CAPTION>



PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Retained Earnings
- --------------------------------------------

                                                                                          Year Ended December 31,
                                                                               ---------------------------------------------
                                                                                 2002               2001              2000
                                                                                 ----               ----              ----
                                                                                                (in thousands)
<S>                                                                           <C>                  <C>              <C>
BEGINNING OF PERIOD                                                           $142,994             $137,688         $139,237
NET INCOME                                                                      41,060               57,759           66,663
DEDUCTIONS
  Capital Stock Gains                                                                (1)                -                -
  Cash Dividends Declared:
    Common Stock                                                                67,368               52,240           68,000
    Preferred Stock                                                                213                  213              212
                                                                              --------             --------         --------

BALANCE AT END OF PERIOD                                                      $116,474             $142,994         $137,688
                                                                              ========             ========         ========


The common stock of PSO is owned by a wholly owned subsidiary of AEP. See Notes
to Financial Statements beginning on page L-1.

</TABLE>



<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Balance Sheets
- ---------------------------

                                                                                                              December 31,
                                                                                                              -----------
                                                                                                        2002                2001
                                                                                                        ----                ----
                                                                                                             (in thousands)
ASSETS
<S>                                                                                                  <C>                 <C>
ELECTRIC UTILITY PLANT:
  Production                                                                                         $1,040,520          $1,034,711
  Transmission                                                                                          432,846             427,110
  Distribution                                                                                          990,947             972,806
  General                                                                                               206,747             203,572
  Construction Work in Progress                                                                          88,444              56,900
                                                                                                     ----------          ----------
      Total Electric Utility Plant                                                                    2,759,504           2,695,099
  Accumulated Depreciation and Amortization                                                           1,239,855           1,184,443
                                                                                                     ----------          ----------
          NET ELECTRIC UTILITY PLANT                                                                  1,519,649           1,510,656
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                            5,383              41,020
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                         4,481              21,354
                                                                                                     ----------          ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                              16,774               5,795
  Accounts Receivable:
   Customers                                                                                             31,687              31,144
   Affiliated Companies                                                                                  14,139              10,905
   Allowance for Uncollectible Accounts                                                                     (84)                (44)
  Fuel Inventory                                                                                         19,973              21,559
  Materials and Supplies                                                                                 37,375              36,785
  Under-recovered Fuel Costs                                                                             76,470                 756
  Energy Trading and Derivative Contracts                                                                 3,841              26,259
  Prepayments and Other                                                                                   2,735               2,368
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          202,910             135,527
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                        26,150              35,064
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         18,117               5,290
                                                                                                     ----------          ----------

                    TOTAL ASSETS                                                                     $1,776,690          $1,748,911
                                                                                                     ==========          ==========


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

</TABLE>



<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY

                                                                                                         December 31,
                                                                                                         -----------
                                                                                                   2002                 2001
                                                                                                   ----                 ----
                                                                                                        (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                            <C>                  <C>
CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                                                              $  157,230           $  157,230
  Paid-in Capital                                                                                 180,016              180,016
  Accumulated Other Comprehensive Income (Loss)                                                   (54,473)                -
  Retained Earnings                                                                               116,474              142,994
                                                                                               ----------           ----------
    Total Common Shareholder's Equity                                                             399,247              480,240
                                                                                               ----------           ----------

Cumulative Preferred Stock Not Subject
  to Mandatory Redemption                                                                           5,267                5,267
PSO-Obligated, Mandatorily Redeemable Preferred
  Securities of Subsidiary Trust Holding Solely Junior
  Subordinated Debentures of PSO                                                                   75,000               75,000
Long-term Debt                                                                                    445,437              345,129
                                                                                               ----------           ----------

          TOTAL CAPITALIZATION                                                                    924,951              905,636
                                                                                               ----------           ----------

OTHER NONCURRENT LIABILITIES                                                                       54,761                7,263
                                                                                               ----------           ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                              100,000              106,000
  Advances from Affiliates                                                                         86,105              123,087
  Accounts Payable - General                                                                       61,169               72,759
  Accounts Payable - Affiliated Companies                                                          78,076               40,857
  Customer Deposits                                                                                21,789               21,041
  Over-Recovered Fuel Costs                                                                          -                   9,476
  Taxes Accrued                                                                                     6,854               18,150
  Interest Accrued                                                                                  6,979                7,298
  Energy Trading and Derivative Contracts                                                           3,260               31,718
  Other                                                                                            24,957               12,216
                                                                                               ----------           ----------

          TOTAL CURRENT LIABILITIES                                                               389,189              442,602
                                                                                               ----------           ----------

DEFERRED INCOME TAXES                                                                             341,396              296,877
                                                                                               ----------           ----------

DEFERRED INVESTMENT TAX CREDITS                                                                    32,201               33,992
                                                                                               ----------           ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                        32,611               49,080
                                                                                               ----------           ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                   1,581               13,461
                                                                                               ----------           ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                       $1,776,690           $1,748,911
                                                                                               ==========           ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Cash Flows
- -------------------------------------

                                                                                                  Year Ended December 31,
                                                                                                ---------------------------
                                                                                         2002              2001              2000
                                                                                         ----              ----              ----
                                                                                                      (in thousands)
<S>                                                                                   <C>               <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                                                          $  41,060         $  57,759         $  66,663
  Adjustments to Reconcile Net Income to Net Cash from Operating Activities:
    Depreciation and Amortization                                                        85,896            80,245            76,418
    Deferred Income Taxes                                                                75,659           (17,751)           25,453
    Deferred Investment Tax Credits                                                      (1,791)           (1,791)           (1,791)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net)                                                            (3,737)           21,405           (28,826)
    Fuel, Materials and Supplies                                                            996              (589)              677
    Other Property and Investments                                                         (419)           (2,809)            7,994
    Accounts Payable                                                                     25,629           (55,319)           89,330
    Taxes Accrued                                                                       (11,296)           16,491           (16,821)
    Fuel Recovery                                                                       (85,190)           51,987           (36,798)
  Transmission Coordination Agreement Settlement                                           -                 -              (15,063)
  Changes in Other Assets                                                                 2,215            (9,120)            4,482
  Changes in Other Liabilities                                                           (6,928)            9,351            (6,103)
                                                                                      ---------         ---------         ---------
            Net Cash From Operating Activities                                          122,094           149,859           165,615
                                                                                      ---------         ---------         ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                             (89,365)         (124,520)         (176,851)
  Proceeds from Sale of Property                                                            963              -                 -
  Other Items                                                                              -                 (359)             -
                                                                                      ---------         ---------         ---------
            Net Cash Used For
              Investing Activities                                                      (88,402)         (124,879)         (176,851)
                                                                                      ---------         ---------         ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                                            187,850              -              105,625
  Retirement of Long-term Debt                                                         (106,000)          (20,000)          (20,000)
  Change in Advances From Affiliates (net)                                              (36,982)           41,967             1,951
  Dividends Paid on Common Stock                                                        (67,368)          (52,240)          (68,000)
  Dividends Paid on Cumulative Preferred Stock                                             (213)             (213)             (212)
                                                                                      ---------         ---------         ---------
            Net Cash From (used For)
              Financing Activities                                                      (22,713)          (30,486)           19,364
                                                                                      ---------         ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                     10,979            (5,506)            8,128
Cash and Cash Equivalents January 1                                                       5,795            11,301             3,173
                                                                                      ---------         ---------         ---------
Cash and Cash Equivalents December 31                                                 $  16,774         $   5,795         $  11,301
                                                                                      =========         =========         =========

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $38,620,000,
$38,250,000 and $33,732,000 and for income taxes was ($38,943,000),
$38,653,000 and $25,786,000 in 2002, 2001 and 2000, respectively.

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Consolidated Statements of Capitalization
- -----------------------------------------

                                                                                          December 31,
                                                                                         ------------
                                                                                    2002             2001
                                                                                    ----             ----
                                                                                        (in thousands)
<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $ 399,247         $480,240
                                                                                 ---------         --------

PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
redeemable at the option of PSO upon 30 days notice.

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2002            Year Ended December 31,       December 31, 2002
- ------     ------------     ----------------------------     -----------------
                              2002      2001      2000
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.00%        $105.75           6         -         25               44,600           4,460            4,460
4.24%         103.19           -         -         -                 8,069             807              807
                                                                                 ---------        ---------
                                                                                     5,267            5,267
                                                                                 ---------        ---------
TRUST PREFERRED SECURITIES
  PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
   holding solely Junior Subordinated Debentures of PSO, 8.00%,
   due April 30, 2037                                                               75,000           75,000
                                                                                 ---------         --------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                               298,079          297,772
Installment Purchase Contracts                                                      47,358           47,357
Senior Unsecured Notes                                                             200,000          106,000
Less Portion Due Within One Year                                                  (100,000)        (106,000)
                                                                                 ---------         --------

Long-term Debt Excluding Portion Due Within One Year                               445,437          345,129
                                                                                 ---------         --------

  TOTAL CAPITALIZATION                                                           $ 924,951         $905,636
                                                                                 =========         ========

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

</TABLE>



<PAGE>





PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Schedule of Long-term Debt
- --------------------------



<PAGE>



First mortgage bonds outstanding were as follows:

                                         December 31,
                                         -----------
                                      2002        2001
                                      ----        ----
                                       (in thousands)
% Rate Due
6.25 2003 - April 1              $ 35,000      $ 35,000
7.25 2003 - July 1                 65,000        65,000
7.38 2004 - December 1             50,000        50,000
6.50 2005 - June 1                 50,000        50,000
7.38 2023 - April 1               100,000       100,000
Unamortized Discount               (1,921)       (2,228)
                                 --------      --------
                                 $298,079      $297,772

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                                         December 31,
                                         -----------
                                      2002        2001
                                      ----        ----
                                        (in thousands)
% Rate Due
Oklahoma Environmental
 Finance Authority (OEFA):
5.90 2007 - December 1            $ 1,000       $ 1,000

Oklahoma Development
 Finance Authority (ODFA):
4.875  2014 - June 1               33,700        33,700

Red River Authority
  of Texas:
6.00   2020 - June 1               12,660        12,660
Unamortized Discount                   (2)           (3)
                                  -------       -------
  Total                           $47,358       $47,357
                                  =======       =======



Under the terms of the installment purchase contracts, PSO is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior unsecured notes outstanding were as follows:

                                         December 31,
                                         -----------
                                      2002        2001
                                      ----        ----
                                        (in thousands)
% Rate Due
(a)   2002 - November 21            $   -       $106,000
(b)   2032 - December 31             200,000        -
                                    --------    --------
       TOTAL                        $200,000    $106,000
                                    ========    ========

(a) A floating interest rate is determined monthly. The rate on December 31,
    2001 was $2.775%.
(b) A fixed interest rate of 6.00% was the rate on December 31, 2002.


At December 31, 2002, future annual long-term debt payments are as follows:

                                              Amount
                                              ------
                                          (in thousands)

2003                                         $100,000
2004                                           50,000
2005                                           50,000
2006                                             -
2007                                            1,000
Later Years                                   346,360
                                             --------
  Total Principal Amount                      547,360
Unamortized Discount                           (1,923)
                                             --------

    Total                                    $545,437
                                             ========

See Note 25 for discussion of the Trust Preferred Securities issued by a wholly
owned statutory business trust of PSO (see Note 25).



<PAGE>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------

The notes to PSO's consolidated financial statements are combined with the notes
to financial statements for AEP and its other subsidiary registrants. Listed
below are the combined notes that apply to PSO. The combined footnotes begin on
page L-1.

                                                                  Combined
                                                                  Footnote
                                                                  Reference
                                                                  ---------


Significant Accounting Policies                                   Note  1

Merger                                                            Note  4

Rate Matters                                                      Note  6

Effects of Regulation                                             Note  7

Customer Choice and Industry Restructuring                        Note  8

Commitments and Contingencies                                     Note  9

Guarantees                                                        Note 10

Sustained Earnings Improvement Initiative                         Note 11

Benefit Plans                                                     Note 14

Business Segments                                                 Note 16

Risk Management, Financial Instruments and Derivatives            Note 17

Income Taxes                                                      Note 18

Leases                                                            Note 22

Lines of Credit and Sale of Receivables                           Note 23

Unaudited Quarterly Financial Information                         Note 24

Trust Preferred Securities                                        Note 25

Jointly Owned Electric Utility Plant                              Note 28

Related Party Transactions                                        Note 29


<PAGE>


INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Public Service Company of Oklahoma and
subsidiary as of December 31, 2002 and 2001, 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, 2002. 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 Public Service Company of Oklahoma
and subsidiary as of December 31, 2002 and 2001, and the results of their
operations and their cash flows each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.


/s/ Deloitte & Touche LLP


Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003




<PAGE>

                       SOUTHWESTERN ELECTRIC POWER COMPANY
                                AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ------------------------------------

                                                                            Year Ended December 31,
                                            ------------------------------------------------------------------------------------
                                              2002              2001              2000                1999               1998
                                              ----              ----              ----                ----               ----
                                                                             (in thousands)
<S>                                         <C>                <C>              <C>                <C>                <C>
INCOME STATEMENTS DATA:
  Operating Revenues                        $1,084,720         $1,101,326       $1,118,274         $  971,527         $  952,952
  Operating Expenses                           942,251            955,119          989,996            824,465            802,274
                                            ----------         ----------       ----------         ----------         ----------
  Operating Income                             142,469            146,207          128,278            147,062            150,678
  Nonoperating Items, Net                         (309)               741            3,851             (1,965)             2,451
  Interest Charges                              59,168             57,581           59,457             58,892             55,135
                                            ----------         ----------       ----------         ----------         ----------
  Income Before
   Extraordinary Item                           82,992             89,367           72,672             86,205             97,994
  Extraordinary Loss                              -                  -                -                (3,011)              -
                                            ----------         ----------       ----------         ----------         ----------
  Net Income                                    82,992             89,367           72,672             83,194             97,994
  Preferred Stock Dividend
   Requirements                                    229                229              229                229                705
  Loss on
   Reacquired Preferred
   Stock                                          -                  -                -                  -                  (856)
                                            ----------         ----------       ----------         ----------         ----------
  Earnings Applicable to
   Common Stock                             $   82,763           $ 89,138         $ 72,443         $   82,965         $   96,433
                                            ==========           ========         ========         ==========         ==========


                                                                                December 31,
                                            ------------------------------------------------------------------------------------
                                              2002               2001              2000               1999               1998
                                              ----               ----              ----               ----               ----
                                                                              (in thousands)
BALANCE SHEETS DATA:
  Electric Utility Plant                    $3,596,174         $3,460,764       $3,319,024         $3,231,431         $3,157,911
  Accumulated Depreciation
   and Amortization                          1,697,338          1,550,618        1,457,005          1,384,242          1,317,057
                                            ----------         ----------       ----------         ----------         ----------
  Net Electric Utility
   Plant                                    $1,898,836         $1,910,146       $1,862,019         $1,847,189         $1,840,854
                                            ==========         ==========       ==========         ==========         ==========
  Total Assets                              $2,208,675         $2,300,676       $2,658,389         $2,106,762         $2,082,258
                                            ==========         ==========       ==========         ==========         ==========

  Common Stock and
   Paid-in Capital                          $  380,663         $  380,663       $  380,663         $  380,663         $  380,663
  Accumulated Other Comprehensive
   Income (Loss)                               (53,683)              -                -                  -                  -
  Retained Earnings                            334,789            308,915          293,989            283,546            296,581
                                            ----------         ----------       ----------         ----------         ----------
  Total Common
   Shareholder's Equity                     $  661,769         $  689,578       $  674,652         $  664,209         $  677,244
                                            ==========         ==========       ==========         ==========         ==========

  Preferred Stock                           $    4,701         $    4,701        $   4,701         $    4,703         $    4,704
                                            ==========         ==========        =========         ==========         ==========

  Trust Preferred
   Securities                               $  110,000         $  110,000       $  110,000         $  110,000         $  110,000
                                            ==========         ==========       ==========         ==========         ==========

  Long-term Debt (a)                        $  693,448         $  645,283       $  645,963         $  541,568         $  587,673
                                            ==========         ==========       ==========         ==========         ==========

  Total Capitalization and Liabilities      $2,208,675         $2,300,676       $2,658,389         $2,106,762         $2,082,258
                                            ==========         ==========       ==========         ==========         ==========


(a) Including portion due within one year.

</TABLE>


<PAGE>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
- -------------------------------------------------------------


<PAGE>


Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 437,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas. SWEPCo also sells electric power at wholesale to
other utilities, municipalities and rural electric cooperatives.

Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC.
SWEPCo, along with the other AEP electric operating subsidiaries, shares in
AEP's electric power transactions with other utility systems and power
marketers.

Results of Operations
- ---------------------

In 2002, Net Income decreased $6.4 million or 7% primarily resulting from
reduced margins. In 2001, Net Income increased $16.7 million or 23% resulting
primarily from the favorable impact of our sharing in AEP's power marketing
activities for a full year.

Changes in Operating Revenues
- -----------------------------

                           Increase (Decrease)
                            From Previous Year
                            ------------------
                           (dollars in millions)

                         2002            2001
                         ----            ----

                      Amount     %       Amount     %
                      ------     -       ------     -
Wholesale
 Electricity*          $(25)    (4)      $(21)     (3)
Energy  Delivery*        15      5        (12)     (3)
Sales to AEP
 Affiliates              (7)    (9)        16      26
                       ----              ----
   Total
    Operating
    Revenues           $(17)    (2)      $(17)     (2)
                       ====              ====

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.




Operating Revenues decreased 2% for 2002 primarily due to decreased fuel
revenues offset in part by the addition of the Dolet Hills mining operation
($12.6 million) and the positive impact of the interchange cost reconstruction
(ICR) adjustments (see Note 6).

In 2001, Operating Revenues decreased $17 million or 2% resulting from
unfavorable wholesale marketing and trading conditions.

Changes in Operating Expenses
- -----------------------------

                             Increase (Decrease)
                              From Previous Year
                              ------------------
                            (dollars in millions)

                             2002              2001
                             ----              ----
                        Amount     %      Amount      %
                        ------     -      ------      -
Fuel                     $(69)    (15)     $(41)     (8)
Purchased
 Power:
  Wholesale
   Electricity             26     143       (40)    (69)
  AEP
     Affiliates            26     165         2      19
Other Operation            18      10        12       7
Maintenance                (8)    (10)        -      (1)
Depreciation
 and
 Amortization               3       3        15      14
Taxes Other
 Than
 Income Taxes              (1)     (1)        2       4
Income Taxes               (8)    (20)       16      60
                         ----              ----
   Total                 $(13)     (1)     $(34)     (4)
                         ====              ====


Fuel expense decreased in 2002 due to a reduction in MWH generated and a
decrease in the cost of fuel, primarily natural gas.

Fuel expense decreased in 2001 from lower natural gas prices and a mild summer
resulting in a reduction in generation.

In 2002, Purchased Power increased primarily due to the impact of ICR
adjustments (see Note 6). In 2001, the decrease in Purchased Power expense was
mainly due to reduced prices caused by decreased electricity demand.

The acquisition of Dolet Hills Lignite Company (Dolet Hills) in June 2001 caused
Other Operation expense to increase in 2002 by $4.3 million. Other Operation
expense was also impacted by the ICR adjustments (see Note 6). In 2001, Other
Operation expense increased also as a result of the Dolet Hills mining operation
in June 2001.

The 10% decrease in Maintenance expense in 2002 is primarily a result of higher
storm and tree trimming related expenses in 2001.

The increase in Depreciation and Amortization expense in 2002 is primarily due
to the addition of Dolet Hills in June 2001, which added $3.0 million of
additional expense in 2002. Depreciation and Amortization expense increased in
2001 due primarily to an increase in excess earnings accruals under the Texas
restructuring legislation and the acquisition of Dolet Hills mining operation.

In 2002, the decrease in Income Taxes was due to a decrease in pre-tax income.
In 2001, the increase in income tax expense was primarily due to an increase in
pre-tax income.



<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------

                                                                                                  Year Ended December 31,
                                                                                 ------------------------------------------------
                                                                                        2002             2001              2000
                                                                                        ----             ----              ----
                                                                                                     (in thousands)
<S>                                                                              <C>                 <C>               <C>
OPERATING REVENUES:
  Wholesale Electricity                                                          $  664,185          $  689,085        $  710,200
  Energy Delivery                                                                   348,236             333,004           344,950
  Sales to AEP Affiliates                                                            72,299              79,237            63,124
                                                                                 ----------          ----------        ----------
            TOTAL OPERATING REVENUES                                              1,084,720           1,101,326         1,118,274
                                                                                 ----------          ----------        ----------

OPERATING EXPENSES:
  Fuel                                                                              388,334             457,613           498,805
  Purchased Power:
    Wholesale Electricity                                                            44,119              18,164            58,518
    AEP Affiliates                                                                   42,022              15,858            13,338
  Other Operation                                                                   189,024             171,314           159,459
  Maintenance                                                                        66,855              74,677            75,123
  Depreciation and Amortization                                                     122,969             119,543           104,679
  Taxes Other Than Income Taxes                                                      55,232              55,834            53,830
  Income Taxes                                                                       33,696              42,116            26,244
                                                                                 ----------          ----------        ----------
            TOTAL OPERATING EXPENSES                                                942,251             955,119           989,996
                                                                                 ----------          ----------        ----------

OPERATING INCOME                                                                    142,469             146,207           128,278

NONOPERATING INCOME                                                                   3,260               4,512             5,487

NONOPERATING EXPENSES                                                                 1,797               3,229             3,112

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                              1,772                 542            (1,476)

INTEREST CHARGES                                                                     59,168              57,581            59,457
                                                                                 ----------          ----------        ----------

NET INCOME                                                                           82,992              89,367            72,672

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                   229                 229               229
                                                                                 ----------          ----------        ----------

EARNINGS APPLICABLE TO COMMON STOCK                                              $   82,763          $   89,138        $   72,443
                                                                                 ==========          ==========        ==========


Consolidated Statements of Comprehensive Income
- -----------------------------------------------
                                                                                                  Year Ended December 31,
                                                                                  -----------------------------------------------
                                                                                     2002               2001                2000
                                                                                     ----               ----                ----
                                                                                                    (in thousands)

NET INCOME                                                                          $82,992            $89,367            $72,672

OTHER COMPREHENSIVE INCOME (LOSS):
  Cash Flow Power Hedges                                                                (48)              -                  -
  Minimum Pension Liability                                                         (53,635)              -                  -
                                                                                    -------            -------            -------

COMPREHENSIVE INCOME                                                                $29,309            $89,367            $72,672
                                                                                    =======            =======            =======

The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.

</TABLE>

<PAGE>
<TABLE>
<CAPTION>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- --------------------------------------------

                                                                                                 Year Ended December 31,
                                                                                   ----------------------------------------------
                                                                                     2002               2001               2000
                                                                                     ----               ----               ----
                                                                                                    (in thousands)
<S>                                                                                <C>                <C>                <C>
BALANCE AT BEGINNING OF PERIOD                                                     $308,915           $293,989           $283,546
NET INCOME                                                                           82,992             89,367             72,672

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                                                     56,889             74,212             62,000
    Preferred Stock                                                                     229                229                229
                                                                                   --------           --------           --------

BALANCE AT END OF PERIOD                                                           $334,789           $308,915           $293,989
                                                                                   ========           ========           ========

The common stock of SWEPCo is owned by a wholly owned subsidiary of AEP. See
Notes to Financial Statements beginning on page L-1.


</TABLE>


<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ---------------------------

                                                                                                               December 31,
                                                                                                               -----------
                                                                                                         2002               2001
                                                                                                         ----               ----
                                                                                                              (in thousands)
<S>                                                                                                  <C>                 <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                                                         $1,503,722          $1,429,356
  Transmission                                                                                          575,003             538,749
  Distribution                                                                                        1,063,564           1,042,523
  General                                                                                               378,130             376,016
  Construction Work in Progress                                                                          75,755              74,120
                                                                                                     ----------          ----------
          Total Electric Utility Plant                                                                3,596,174           3,460,764
  Accumulated Depreciation and Amortization                                                           1,697,338           1,550,618
                                                                                                     ----------          ----------
          NET ELECTRIC UTILITY PLANT                                                                  1,898,836           1,910,146
                                                                                                     ----------          ----------

OTHER PROPERTY AND INVESTMENTS                                                                            5,978              43,000
                                                                                                     ----------          ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                         5,119              24,508
                                                                                                     ----------          ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                               2,069               5,415
  Accounts Receivable:
   Customers                                                                                             62,359              43,133
   Affiliated Companies                                                                                  19,253              12,069
   Allowance for Uncollectible Accounts                                                                  (2,128)                (89)
  Fuel Inventory                                                                                         61,741              52,212
  Materials and Supplies                                                                                 33,539              32,527
  Under-recovered Fuel Costs                                                                              2,865               8,839
  Energy Trading and Derivative Contracts                                                                 4,388              30,139
  Prepayments and Other                                                                                  17,851              18,716
                                                                                                     ----------          ----------
          TOTAL CURRENT ASSETS                                                                          201,937             202,961
                                                                                                     ----------          ----------

REGULATORY ASSETS                                                                                        49,233              52,308
                                                                                                     ----------          ----------

DEFERRED CHARGES                                                                                         47,572              67,753
                                                                                                     ----------          ----------

                    TOTAL ASSETS                                                                     $2,208,675          $2,300,676
                                                                                                     ==========          ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

                                                                                                           December 31,
                                                                                                           -----------
                                                                                                   2002                 2001
                                                                                                   ----                 ----
                                                                                                          (in thousands)
<S>                                                                                             <C>                  <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $18 Par Value:
    Authorized - 7,600,000 Shares
    Outstanding - 7,536,640 Shares                                                              $  135,660           $  135,660
  Paid-in Capital                                                                                  245,003              245,003
  Accumulated Other Comprehensive Income (Loss)                                                    (53,683)                -
  Retained Earnings                                                                                334,789              308,915
                                                                                                ----------           ----------
    Total Common Shareholder's Equity                                                              661,769              689,578
  Preferred Stock                                                                                    4,701                4,701
  SWEPCo-Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely Junior
   Subordinated Debentures of SWEPCo                                                               110,000              110,000
  Long-term Debt                                                                                   637,853              494,688
                                                                                                ----------           ----------
          TOTAL CAPITALIZATION                                                                   1,414,323            1,298,967
                                                                                                ----------           ----------

OTHER NONCURRENT LIABILITIES                                                                        78,494               40,109
                                                                                                ----------           ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                                55,595              150,595
  Advances from Affiliates, net                                                                     23,239              117,367
  Accounts Payable - General                                                                        62,139               71,810
  Accounts Payable - Affiliated Companies                                                           58,773               37,469
  Customer Deposits                                                                                 20,110               19,880
  Taxes Accrued                                                                                     19,081               36,522
  Interest Accrued                                                                                  17,051               13,027
  Energy Trading and Derivative Contracts                                                            3,724               36,297
  Over-recovered Fuel                                                                               17,226                5,487
  Other                                                                                             34,565               26,074
                                                                                                ----------           ----------
          TOTAL CURRENT LIABILITIES                                                                311,503              514,528
                                                                                                ----------           ----------

DEFERRED INCOME TAXES                                                                              341,064              369,781
                                                                                                ----------           ----------

DEFERRED INVESTMENT TAX CREDITS                                                                     44,190               48,714
                                                                                                ----------           ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                         17,295               13,127
                                                                                                ----------           ----------

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                                                    1,806               15,450
                                                                                                ----------           ----------

COMMITMENTS AND CONTINGENCIES (Note 9)

                    TOTAL CAPITALIZATION AND LIABILITIES                                        $2,208,675           $2,300,676
                                                                                                ==========           ==========

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- -------------------------------------
                                                                                                  Year Ended December 31,
                                                                                     --------------------------------------------
                                                                                        2002              2001              2000
                                                                                        ----              ----              ----
                                                                                                     (in thousands)
<S>                                                                                  <C>               <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                                                         $ 82,992          $ 89,367          $ 72,672
  Adjustments to Reconcile Net Income to Net Cash Flows From Operating
   Activities:
    Depreciation and Amortization                                                     122,969           119,543           104,679
    Deferred Income Taxes                                                              (3,134)          (31,396)           14,653
    Deferred Investment Tax Credits                                                    (4,524)           (4,453)           (4,482)
    Mark-to-Market Energy Trading and Derivative Contracts                             (1,151)          (10,695)            7,795
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                                         (24,371)          (11,447)           (1,254)
    Fuel, Materials and Supplies                                                      (10,541)          (19,578)           22,103
    Accounts Payable                                                                   11,633           (34,489)           43,962
    Taxes Accrued                                                                     (17,441)           25,298           (13,150)
    Transmission Coordination Agreement Settlement                                       -                 -              (24,406)
    Fuel Recovery                                                                      17,713            34,423           (38,357)
  Change in Other Assets                                                               24,257             1,323            54,414
  Change in Other Liabilities                                                          12,161            11,714           (37,001)
                                                                                    ---------         ---------         ---------
            Net Cash Flows From Operating Activities                                  210,563           169,610           201,628
                                                                                    ---------         ---------         ---------

INVESTING ACTIVITIES:
  Construction Expenditures                                                          (111,775)         (111,725)         (120,671)
  Purchase of Dolet Hills Mining Operations                                              -              (85,716)             -
  Other                                                                                 1,134              (411)              446
                                                                                    ---------         ---------         ---------
            Net Cash Flows Used For
              Investing Activities                                                   (110,641)         (197,852)         (120,225)
                                                                                    ---------         ---------         ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                                          198,573              -              149,360
  Redemption of Preferred Stock                                                          -                 -                   (1)
  Retirement of Long-term Debt                                                       (150,595)             (595)          (45,595)
  Change in Advances From Affiliates (net)                                            (94,128)          106,786          (124,074)
  Dividends Paid on Common Stock                                                      (56,889)          (74,212)          (62,000)
  Dividends Paid on Cumulative Preferred Stock                                           (229)             (229)             (229)
                                                                                    ---------         ---------         ---------
            Net Cash Flows From (Used For)
              Financing Activities                                                   (103,268)           31,750           (82,539)
                                                                                    ---------         ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                   (3,346)            3,508            (1,136)
Cash and Cash Equivalents January 1                                                     5,415             1,907             3,043
                                                                                    ---------         ---------         ---------
Cash and Cash Equivalents December 31                                               $   2,069         $   5,415         $   1,907
                                                                                    =========         =========         =========

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,008,000, $51,126,000
and $51,111,000 and for income taxes was $60,451,000, $49,901,000 and
$27,994,000 in 2002, 2001, and 2000, respectively.

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

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- -----------------------------------------


                                                                                          December 31,
                                                                                          -----------
                                                                                    2002               2001
                                                                                    ----               ----
                                                                                        (in thousands)
<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  661,769        $  689,578
                                                                                 ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 1,860,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2002            Year Ended December 31,       December 31, 2002
- ------     ------------     ----------------------------     -----------------
                              2002      2001      2000
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.28%        $103.90             -         -         -              7,386               740               740
4.65%        $102.75             -         -         -              1,907               190               190
5.00%        $109.00             -         -        12             37,715             3,771             3,771
                                                                                 ----------        ----------

                                                                                      4,701             4,701
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES
  SWEPCo-Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely
   Junior Subordinated Debentures of SWEPCo, 7.875%,
   due April 30, 2037                                                               110,000           110,000
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                315,420           315,449
Installment Purchase Contracts                                                      179,183           179,834
Senior Unsecured Notes                                                              198,845           150,000
Less Portion Due Within One Year                                                    (55,595)         (150,595)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                              637,853           494,688
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,414,323        $1,298,967
                                                                                 ==========        ==========

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


</TABLE>



<PAGE>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- --------------------------


<PAGE>


First mortgage bonds outstanding were as follows:
                              December 31,
                              -----------
                            2002       2001
                            ----       ----
                             (in thousands)
% Rate Due
6-5/8  2003 - February 1 $ 55,000   $ 55,000
7-3/4  2004 - June 1       40,000     40,000
6.20   2006 - November 1    5,505      5,650
6.20   2006 - November 1    1,000      1,000
7.00   2007 - September 1  90,000     90,000
7-1/4  2023 - July 1       45,000     45,000
6-7/8  2025 - October 1    80,000     80,000
Unamortized Discount       (1,085)    (1,201)
                         --------   --------
                         $315,420   $315,449
                         ========   ========

First mortgage bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                             December 31,
                             -----------
                            2002      2001
                            ----      ----
                            (in thousands)
% Rate Due
DeSoto County:

7.60   2019 - January 1  $ 53,500   $ 53,500

Sabine:

6.10   2018 - April 1      81,700     81,700

Titus County:

6.90   2004 - November 1   12,290     12,290
6.00   2008 - January 1    12,620     13,070
8.20   2011 - August 1     17,125     17,125

Unamortized Premium         1,948      2,149
                         --------   --------
                         $179,183   $179,834
                         ========   ========



Under the terms of the installment purchase contracts, SWEPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior unsecured notes outstanding were as follows:

                              December 31,
                              -----------
                            2002     2001
                            ----     ----
                            (in thousands)
% Rate Due
- ------ ------------------
 4.50  2005 - July 1     $200,000  $   -
 (a)   2002 - March 1        -      150,000
 Unamortized Discount      (1,155)     -
                         --------  --------
                         $198,845  $150,000
                         ========  ========

(a)A floating interest rate is determined monthly. The rate on December 31, 2001
was 2.311%.

At December 31, 2002 future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2003                        $ 55,595
2004                          52,885
2005                         200,595
2006                           6,520
2007                          90,450
Later Years                  287,695
                            --------
  Total Principal Amount     693,740
Unamortized Discount            (292)
                            --------
    Total                   $693,448
                            ========


See Note 25 for discussion of Trust Preferred Securities issued by a
wholly-owned statutory business trust of SWEPCo.




<PAGE>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Combined Notes to Consolidated Financial Statements
- ------------------------------------------------------------

The notes to SWEPCo's consolidated financial statements are combined with the
notes to financial statements for AEP and its other subsidiary registrants.
Listed below are the combined notes that apply to SWEPCo. The combined footnotes
begin on page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference
                                                          ---------

Significant Accounting Policies                           Note  1

Extraordinary Items and Cumulative Effect                 Note  2

Goodwill and Other Intangible Assets                      Note  3

Merger                                                    Note  4

Rate Matters                                              Note  6

Effects of Regulation                                     Note  7

Customer Choice and Industry Restructuring                Note  8

Commitments and Contingencies                             Note  9

Guarantees                                                Note 10

Sustained Earnings Improvement Initiative                 Note 11

Acquisitions, Dispositions and Discontinued Operations    Note 12

Benefit Plans                                             Note 14

Business Segments                                         Note 16

Risk Management, Financial Instruments and Derivatives    Note 17

Income Taxes                                              Note 18

Leases                                                    Note 22

Lines of Credit and Sale of Receivables                   Note 23

Unaudited Quarterly Financial Information                 Note 24

Trust Preferred Securities                                Note 25

Jointly Owned Electric Utility Plant                      Note 28

Related Party Transactions                                Note 29



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southwestern Electric Power Company and
subsidiaries as of December 31, 2002 and 2001, 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, 2002. 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 Southwestern Electric Power Company
and subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002 in conformity with accounting principles generally accepted in
the United States of America.


/s/ Deloitte & Touche LLP


Deloitte & Touche LLP
Columbus, Ohio
February 21, 2003



<PAGE>


COMBINED NOTES TO FINANCIAL STATEMENTS

Index to Combined Notes to Financial Statements

The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list of footnotes shows the
registrant to which they apply:


 1. Significant Accounting Policies         AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

 2. Extraordinary Items and                 AEP, APCo, CSPCo, OPCo, SWEPCo,
      Cumulative Effect                     TCC, TNC

 3. Goodwill and Other Intangible Assets    AEP, SWEPCo

 4. Merger                                  AEP, I&M, KPCo, PSO, SWEPCo, TCC,
                                            TNC

 5. Nuclear Plant Restart                   AEP, I&M

 6. Rate Matters                            AEP, KPCo, PSO, SWEPCo, TCC, TNC

 7. Effects of Regulation                   AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

 8. Customer Choice and Industry            AEP, APCo, CSPCo, I&M, OPCo, PSO,
      Restructuring                         SWEPCo, TCC, TNC

 9. Commitments and Contingencies           AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

10. Guarantees                              AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

11. Sustained Earnings Improvement          AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
      Initiative                            OPCo, PSO, SWEPCo, TCC, TNC

12. Acquisitions, Dispositions and          AEP, OPCo, SWEPCo, TCC, TNC
      Discontinued Operations

13. Asset Impairments and Investment        AEP, APCo, CSPCo, I&M, KPCo, OPCo,
      Value Losses                          TCC, TNC

14. Benefit Plans                           AEP, APCo, CSPCo, I&M, KPCo, OPCo,
                                            PSO, SWEPCo, TCC, TNC

15. Stock-Based Compensation                AEP

16. Business Segments                       AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

17. Risk Management, Financial              AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
      Instruments and Derivatives           OPCo, PSO, SWEPCo, TCC, TNC

18. Income Taxes                            AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

19. Basic and Diluted Earnings Per Share    AEP

20. Supplementary Information               AEP, APCo, CSPCo, I&M, OPCo

21. Power and Distribution Projects         AEP

22. Leases                                  AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
                                            OPCo, PSO, SWEPCo, TCC, TNC

23. Lines of Credit and Sale                AEP, AEGCo, APCo, CSPCo, I&M, KPCo,
      of Receivables                        OPCo, PSO, SWEPCo, TCC, TNC

24. Unaudited Quarterly Financial           AEP, AEGCo, APCo, CSPCo, I&M,  KPCo,
      Information                           OPCo, PSO, SWEPCo, TCC, TNC

25. Trust Preferred Securities              AEP, PSO, SWEPCo, TCC

26. Minority Interest in Finance            AEP
      Subsidiary

27. Equity Units                            AEP

28. Jointly Owned Electric Utility Plant    CSPCo, PSO, SWEPCo, TCC, TNC

29. Related Party Transactions              AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
                                            PSO, SWEPCo, TCC, TNC

30. Subsequent Events (Unaudited)           AEP



<PAGE>


1. Significant Accounting Policies:

Business Operations - AEP's (the Company's) principal business conducted by its
eleven domestic electric utility operating companies is the generation,
transmission and distribution of electric power. Nine of AEP's eleven domestic
electric utility operating companies, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC, TNC, are SEC registrants. AEGCo is a domestic generating company
wholly-owned by AEP that is an SEC registrant. These companies are subject to
regulation by the FERC under the Federal Power Act and follow the Uniform System
of Accounts prescribed by FERC. They are subject to further regulation with
regard to rates and other matters by state regulatory commissions.

AEP also engages in wholesale marketing and trading of electricity, natural gas
and to a lesser extent, other commodities in the United States and Europe. In
addition, the Company's domestic operations include non-regulated independent
power and cogeneration facilities, coal mining and intra-state midstream natural
gas operations in Louisiana and Texas.

International operations include supply of electricity and other non-regulated
power generation projects in the United Kingdom, and to a lesser extent in
Mexico, Australia, China and the Pacific Rim region. These operations are either
wholly-owned or partially-owned by various AEP subsidiaries. We also maintained
operations in Brazil through the fourth quarter of 2002. See Note 13 for
discussion of impaired investments and assets held for sale.

The Company also operates domestic barging operations, provides various energy
related services and furnishes communications related services domestically. See
Note 13 for further discussion of changes in our communications related business
and other business operations announced in 2002.

Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The
rates charged by the domestic utility subsidiaries are approved by the FERC and
the state utility commissions. The FERC regulates wholesale electricity
operations and transmission rates and the state commissions regulate retail
rates. The prices charged by foreign subsidiaries located in China, Mexico and
Brazil are regulated by the authorities of that country and are generally
subject to price controls.

Principles of Consolidation - AEP's consolidated financial statements include
AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated
with their wholly-owned or substantially controlled subsidiaries. The
consolidated financial statements for APCo, CSPCo, I&M, PSO, SWEPCo and TCC
include the registrant and its wholly-owned subsidiaries. Significant
intercompany items are eliminated in consolidation. Equity investments not
substantially controlled that are 50% or less owned are accounted for using the
equity method with their equity earnings included in Other Income for AEP and
nonoperating income for the registrant subsidiaries.

Basis of Accounting - As the owner of cost-based rate-regulated electric public
utility companies, AEP Co., Inc.'s consolidated financial statements reflect the
actions of regulators that result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate-regulated. In
accordance with SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory liabilities
(future revenue reductions or refunds) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues. Application of SFAS 71 for the generation portion of the business was
discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in
Virginia and West Virginia by APCo in June 2000, in Texas by TCC, TNC, and
SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note
8, "Customer Choice and Industry Restructuring" for additional information.

Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles necessarily includes the use of
estimates and assumptions by management. Actual results could differ from those
estimates.

Property, Plant and Equipment - Domestic electric utility property, plant and
equipment are stated at original cost of the acquirer. Property, plant and
equipment of the non-regulated operations and other investments are stated at
their fair market value at acquisition plus the original cost of property
acquired or constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and associated
removal costs, net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overhead incurred to operate and maintain plant
are included in operating expenses. Plants are tested for impairment as required
under SFAS 144. See Note 13.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- - AFUDC is a noncash, nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2002, 2001 and
2000 were not significant. Effective with the discontinuance of SFAS 71
regulatory accounting for domestic generating assets in Arkansas, Ohio, Texas,
Virginia, West Virginia and other non-regulated operations, interest is
capitalized during construction in accordance with SFAS 34, "Capitalization of
Interest Costs." The amounts of interest capitalized were not material in 2002,
2001, and 2000.


Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
- ----------------                         ------------------
                                                 2002
                                                 ----

Production:
  Steam-Nuclear                             2.5% to  3.4%
  Steam-Fossil-Fired                        2.6% to  4.5%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  3.0%
Distribution                                3.3% to  4.2%
Other                                       1.8% to  9.9%

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
- ----------------                         ------------------
                                                 2001
                                                 ----
Production:
  Steam-Nuclear                             2.5% to  3.4%
  Steam-Fossil-Fired                        2.5% to  4.5%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  3.1%
Distribution                                2.7% to  4.2%
Other                                       1.8% to 15.0%

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
- ----------------                         ------------------
                                                2000
                                                ----
Production:
  Steam-Nuclear                             2.8% to  3.4%
  Steam-Fossil-Fired                        2.3% to  4.5%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  3.1%
Distribution                                3.3% to  4.2%
Other                                       2.5% to  7.3%



The following table provides the annual composite depreciation rates generally
used by the AEP registrant subsidiaries for the years 2002, 2001 and 2000 which
were as follows:
<TABLE>
<CAPTION>

                      Nuclear         Steam         Hydro           Transmission            Distribution          General
                      -------         -----         -----           ------------            ------------          -------
<S>                    <C>           <C>           <C>                  <C>                     <C>              <C>
AEGCo                    - %          3.5%           - %                  - %                     - %             2.8%
APCo                     -            3.4           2.9                  2.2                     3.3              3.1
CSPCo                    -            3.2            -                   2.3                     3.6              3.2
I&M                     3.4           4.5           3.4                  1.9                     4.2              3.8
KPCo                     -            3.8            -                   1.7                     3.5              2.5
OPCo                     -            3.4           2.7                  2.3                     4.0              2.7
PSO                      -            2.7            -                   2.3                     3.4              6.3
SWEPCo                   -            3.4            -                   2.7                     3.6              4.7
TCC                     2.5           2.6           1.9                  2.3                     3.5              4.0
TNC                      -            2.8            -                   3.1                     3.3              6.8

</TABLE>


Depreciation, depletion and amortization of coal-mining assets is provided over
each asset's estimated useful life or the estimated life of the mine, whichever
is shorter, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used to amortize
coal rights and mine development costs based on estimated recoverable tonnages.
These costs are included in the cost of coal charged to fuel expense for coal
used by utility operations. Current average amortization rates are $0.32 per ton
in 2002, $3.46 per ton in 2001 and $5.07 per ton in 2000. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia. See Note 12, Acquisitions,
Dispositions and Discontinued Operations for further discussion of the changes
in our coal investments leading to the decline in amortization rates in 2002.

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

Inventory - Except for PSO, TCC and TNC, the regulated domestic utility
companies value fossil fuel inventories using a weighted average cost method.
PSO, TCC and TNC, utilize the LIFO method to value fossil fuel inventories. For
those domestic utilities whose generation is unregulated, inventory of coal and
oil is carried at the lower of cost or market. Coal mine inventories are also
carried at the lower of cost or market. Materials and supplies inventories are
carried at average cost.

Non-trading gas inventory is carried at the lower of cost or market. In
compliance with EITF 02-03 as described in the New Accounting Pronouncements
section of Note 1, natural gas inventories held in connection with trading
operations at October 25, 2002 continued to be carried at fair value until
December 31, 2002, and inventory purchased from October 26 through December 31,
2002 was carried at the lower of cost or market. Effective January 1, 2003, all
natural gas inventories held in connection with trading operations will be
adjusted to the historical cost basis and carried at the lower of cost or
market. We estimate the adjustment in January 2003 will decrease the value of
natural gas inventories held in connection with trading operations by
approximately $39 million. This change will be accounted for as a cumulative
effect of a change in accounting principle.

Accounts Receivable - AEP Credit, Inc. factors accounts receivable for certain
of the domestic utility subsidiaries and, until the first quarter of 2002,
factored accounts receivable for certain non-affiliated utilities. On December
31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement with a
group of banks and commercial paper conduits. This transaction constitutes a
sale of receivables in accordance with SFAS 140, allowing the receivables to be
taken off of the company's balance sheet. See Note 23 for further details.

Foreign Currency Translation - The financial statements of subsidiaries outside
the U.S. which are included in AEP's consolidated financial statements are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets
and liabilities are translated to U.S. dollars at year-end rates of exchange and
revenues and expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss adjustments are recorded
in shareholders' equity as Accumulated Other Comprehensive Income (Loss). The
non-cash impact of the changes in exchange rates on cash, resulting from the
translation of items at different exchange rates, is shown on AEP's Consolidated
Statements of Cash Flows in Effect of Exchange Rate Changes on Cash. Actual
currency transaction gains and losses are recorded in income.

Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the
fuel is burned. Where applicable under governing state regulatory commission
retail rate orders, fuel cost over or under-recoveries are deferred as
regulatory liabilities or regulatory assets in accordance with SFAS 71. These
deferrals generally are amortized when refunded or billed to customers in later
months with the regulator's review and approval. The amount of deferred fuel
costs under fuel clauses for AEP was $143 million at December 31, 2002 and $139
million at December 31, 2001. See Note 7 "Effects of Regulation".

We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for
APCo. Where fuel clauses have been eliminated due to the transition to market
pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective
January 1, 2002) changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes also impact
earnings. This is also true for certain of AEP's Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 6, "Rate Matters" and Note 8, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.

Revenue Recognition -

Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo), reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide currently for refunds to
customers that have not yet been made.

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

Traditional Electricity Supply and Delivery Activities - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale electricity
supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our income statement when the energy is delivered
to the customer and include unbilled as well as billed amounts. In general,
expenses are recorded when purchased electricity is received and when expenses
are incurred.

Domestic Gas Pipeline and Storage Activities - Revenues are recognized from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.

Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contacts
to fair value during the period are recognized currently in the results of
operations, appropriately discounted and net of applicable credit and liquidity
reserves.

Energy Marketing and Trading Transactions -
In 2000, 2001 and throughout the majority of 2002, AEP engaged in wholesale
electricity, natural gas and other commodity marketing and trading transactions
(trading activities). Trading activities involve the purchase and sale of energy
under forward contracts at fixed and variable prices and the trading of
financial energy contracts which includes exchange futures and options and
over-the-counter options and swaps. We use the mark-to-market method of
accounting for trading activities as required by EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains
and losses from settlements of forward trading contracts are recorded net in
revenues. For energy contracts not yet settled, whether physical or financial,
changes in fair value are recorded net in revenues as unrealized gains and
losses from mark-to-market valuations. When positions are settled and gains and
losses are realized, the previously recorded unrealized gains and losses from
mark-to-market valuations are reversed. In October 2002, management announced
plans to focus on wholesale markets around owned assets.

All of the registrant subsidiaries except AEGCo participate in AEP's wholesale
marketing and trading of electricity. For I&M, KPCo, PSO and a portion of TNC
and SWEPCo, when the contract settles the total gain or loss is realized in
cash. Where this amount is recorded on the income statement depends on whether
the contract's delivery points are within or outside of AEP's traditional
marketing area. For contracts with delivery points in AEP's traditional
marketing area, the total gain or loss realized in cash for sales and the cost
of purchased energy are included in revenues on a net basis. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts in AEP's traditional marketing area are deferred as regulatory
liabilities (gains) or regulatory assets (losses). For contracts with delivery
points outside of AEP's traditional marketing area only the difference between
the accumulated unrealized net gains or losses recorded in prior periods and the
cash proceeds is recognized in the income statement as nonoperating income.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.

For APCo, CSPCo and OPCo, depending on whether the delivery point for the
electricity is in AEP's traditional marketing area or not determines where the
contract is reported in the income statement. Physical forward trading sale and
purchase contracts with delivery points in AEP's traditional marketing area are
included in revenues on a net basis. Prior to settlement, changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area are also included in revenues on a net basis. Physical forward
sale and purchase contracts for delivery outside of AEP's traditional marketing
area are included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts with delivery points outside of AEP's traditional marketing area are
included in nonoperating income on a net basis.

The trading of energy options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in AEP's revenues until the contracts settle. When these contracts
settle, the net proceeds are recorded in revenues and reverse the prior
cumulative unrealized net gain or loss. APCo, CSPCo, OPCo, I&M and KPCo also
have financial transactions, but record the unrealized gains and losses, as well
as the net proceeds upon settlement, in nonoperating income.

The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. Open long-term trading contracts are marked-to-market
based mainly on AEP- developed valuation models. The models are derived from
internally assessed market prices with the exception of the NYMEX gas curve,
where we use daily settled prices. All fair value amounts are net of appropriate
valuation adjustments for items such as discounting, liquidity and credit
quality. Such valuation adjustments provide for a better approximation of fair
value. 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 prices, at the time of
settlement, do not correlate with AEP-developed price models.

As explained above, the effect on AEP's Consolidated Statements of Operations of
marking to market open electricity trading contracts in AEP's regulated
jurisdictions is deferred as regulatory assets (losses) or liabilities (gains)
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
activities whether deferred or recognized in revenues are part of Energy Trading
and Derivative Contracts assets or liabilities as appropriate.

Construction Projects for Outside Parties - Certain AEP entities engage in
construction projects for outside parties that are accounted for on the
percentage-of-completion method of revenue recognition. This method recognizes
revenue in proportion to costs incurred compared to total estimated costs.

Debt Instrument Hedging and Related Activities - In order to mitigate the risks
of market price and interest rate fluctuations, AEP, APCo, CSPCo, I&M, KPCo and
OPCo enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory debt instruments are entered into
in order to manage the change in interest rates between the time a debt offering
is initiated and the issuance of the debt (usually a period of 60 days). Gains
or losses from these transactions are deferred and amortized over the life of
the debt issuance with the amortization included in interest charges. There were
no such forward contracts outstanding at December 31, 2002 or 2001. See Note 17
- - "Risk Management, Financial Instruments and Derivatives" for further
discussion of the accounting for risk management transactions.

Levelization of Nuclear Refueling Outage Costs - In order to match costs with
regulated revenues, incremental operation and maintenance costs associated with
periodic refueling outages at I&M's Cook Plant are deferred and amortized over
the period beginning with the commencement of an outage and ending with the
beginning of the next outage.

Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS
71 requires the recordation of a regulatory asset to match the expensing of
maintenance costs with their recovery in cost-based regulated revenues. See
below for an explanation of costs deferred in connection with an extended outage
at I&M's Cook Plant.

Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended outage of the Cook Plant, I&M deferred $200 million of incremental
operation and maintenance costs during 1999. The deferred amount is being
amortized to expense on a straight-line basis over five years from January 1,
1999 to December 31, 2003. I&M amortized $40 million each year 1999 through 2002
leaving $40 million as an SFAS 71 regulatory asset at December 31, 2002 on the
Consolidated Balance Sheets of AEP and I&M.

Other Income and Other Expenses - Other Income includes non-operational revenue
including area business development and river transportation, equity earnings of
non-consolidated subsidiaries, gains on dispositions of property, interest and
dividends, an allowance for equity funds used during construction (explained
above) and miscellaneous income. Other Expenses includes non-operational expense
including area business development and river transportation, losses on
dispositions of property, miscellaneous amortization, donations and various
other non-operating and miscellaneous expenses.

AEP Consolidated Other Income and Deductions

                                          December 31,
                                   2002      2001      2000
                                   ----      ----      ----
                                         (in millions)
OTHER INCOME:
Equity Earnings                   $ 104     $ 123      $ 22
Non-operational Revenue             187       123        71
Interest and  Miscellaneous
Income                               25        16         2
Gain on Sale of  Frontera
                                     -         73        -
Gain on Sale of Retail
 Electric Provider                  129        -         -
                                  -----     -----      ----

   Total Other Income             $ 445     $ 335      $ 95
                                  =====     =====      ====

OTHER EXPENSES:
Property Taxes and
 Miscellaneous Expenses           $ 142      $ 68      $ 28
Non-operational   Expenses
                                    179        56        49
Fiber Optic and
 Datapult Exit Costs                 -         49        -
Provision for Loss - Airplane
                                     -         14        -
                                  -----     -----      ----

  Total Other Expenses            $ 321     $ 187      $ 77
                                  =====     =====      ====

Income Taxes - The AEP System follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in regulated revenues (that
is, deferred taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.

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

Excise Taxes - AEP and its subsidiary registrants, as an agent for a state or
local government, collect from customers certain excise taxes levied by the
state or local government upon the customer. These taxes are not recorded as
revenue or expense, but only as a pass-through billing to the customer to be
remitted to the government entity. Excise tax collections and payments related
to taxes imposed upon the customer are not presented in the income statement.

Debt and Preferred Stock - Gains and losses from the reacquisition of debt used
to finance domestic regulated electric utility plant are generally deferred and
amortized over the remaining term of the reacquired debt in accordance with
their rate-making treatment. If debt associated with the regulated business is
refinanced, the reacquisition costs attributable to the portions of the business
that are subject to cost based regulatory accounting under SFAS 71 are generally
deferred and amortized over the term of the replacement debt commensurate with
their recovery in rates. Gains and losses on the reacquisition of debt for
operations not subject to SFAS 71 are reported as a Loss on Reacquired Debt, an
extraordinary item on the Consolidated Statements of Operations of AEP and TCC.
See discussion of SFAS 145 in New Accounting Pronouncements section of this note
for new treatment effective in 2003.

Debt discount or premium and debt issuance expenses are deferred and amortized
utilizing the effective interest rate method over the term of the related debt.
The amortization expense is included in interest charges.

Where rates are regulated, redemption premiums paid to reacquire preferred stock
of the domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.

Goodwill and Intangible Assets - In June 2001, the FASB issued SFAS 141,
Business Combinations, and SFAS 142, Goodwill and Other Intangible Assets,
affecting AEP and SWEPCo.

SFAS 141 requires that the purchase method of accounting be used for all
business combinations initiated after June 30, 2001 and established new
standards for the recognition of certain identifiable intangible assets,
separate from goodwill. We adopted the provisions of SFAS 141 effective July 1,
2001. See Note 12 for further discussion of acquisitions initiated after June
30, 2001 and Note 3 for further discussion of our components of goodwill and
intangible assets.

SFAS 142 requires that goodwill and intangible assets with finite useful lives
no longer be amortized, but instead tested for impairment at least annually.
SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations with an
acquisition date before July 1, 2001, we amortized goodwill and intangible
assets with indefinite lives through December 2001, and then ceased
amortization. The goodwill associated with those business combinations with an
acquisition date before July 1, 2001 was amortized on a straight-line basis
generally over 40 years except for the portion of goodwill associated with gas
trading and marketing activities which was amortized on a straight-line basis
over 10 years. In accordance with SFAS 142, for all business combinations with
an acquisition date after June 30, 2001, we have not amortized goodwill and
intangible assets with indefinite lives. Intangible assets with finite lives
continue to be amortized over their respective estimated lives ranging from 5 to
10 years. See Note 3 for total goodwill, accumulated amortization and the impact
on operations of the adoption of SFAS 142.

In early 2002, we began testing our goodwill and intangible assets with
indefinite useful lives for impairment, in accordance with SFAS 142. See Note 3
for the results of our testing and the corresponding net transitional impairment
loss recorded as a Cumulative Effect of Accounting Change during 2002.

Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds
represent funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal liabilities. By
rules or orders, the state jurisdictional commissions (Indiana, Michigan and
Texas) and the FERC established investment limitations and general risk
management guidelines to protect their ratepayers' funds and to allow those
funds to earn a reasonable return. In general, limitations include:

o        Acceptable investments (rated investment grade or above)
o        Maximum percentage invested in a specific type of investment
o        Prohibition of investment in obligations of the applicable company or
         its affiliates.

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

Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Other Assets at market value
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. In accordance with SFAS 71,
unrealized gains and losses from securities in these trust funds are not
reported in equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or liabilities for
the spent nuclear fuel disposal trust funds in accordance with their treatment
in rates.

Comprehensive Income (Loss) - Comprehensive income (loss) is defined as the
change in equity (net assets) of a business enterprise during a period from
transactions and other events and circumstances from non-owner sources. It
includes all changes in equity during a period except those resulting from
investments by owners and distributions to owners. Comprehensive income (loss)
has two components: net income (loss) and other comprehensive income (loss).
There were no material differences between net income and comprehensive income
for AEGCo.

Components of Other Comprehensive Income (Loss) - Other comprehensive income
(loss) is included on the balance sheet in the equity section. The following
table provides the components that comprise the balance sheet amount in
Accumulated Other Comprehensive Income (Loss) for AEP.


                                           December 31,
   Components                       2002      2001      2000
- ------------------------------------------------------------
                                         (in millions)
Foreign Currency
 Adjustments                        $ 4     $(113)    $ (99)
Unrealized Losses
 On Securities                       (2)       -         -
Unrealized Gain on
 Hedged Derivatives                 (16)       (3)       -
Minimum Pension
 Liability                         (595)      (10)       (4)
                                  -----     -----     -----
                                  $(609)    $(126)    $(103)
                                  =====     =====     =====


Accumulated Other Comprehensive Income (Loss) for AEP registrant subsidiaries as
of December 31, 2002 and 2001 is shown in the following table. Registrant
subsidiary balances for Accumulated Other Comprehensive Income (Loss) for the
year ended December 31, 2000 was zero.

                                        December 31,
   Components                         2002       2001
- ------------------------------------------------------
                                     (in thousands)
Cash Flow Hedges:
   APCo                             $(1,920)   $ (340)
   CSPCo                               (267)     -
   I&M                                 (286)   (3,835)
   KPCo                                 322    (1,903)
   OPCo                                (738)     (196)
   PSO                                  (42)     -
   SWEPCo                               (48)     -
   TCC                                  (36)     -
   TNC                                  (15)     -
Minimum Pension
 Liability:
   APCo                            $(70,162)   $ -
   CSPCo                            (59,090)     -
   I&M                              (40,201)     -
   KPCo                              (9,773)     -
   OPCo                             (72,148)     -
   PSO                              (54,431)     -
   SWEPCo                           (53,635)     -
   TCC                              (73,124)     -
   TNC                              (30,748)     -

Segment Reporting - The AEP System has adopted SFAS No. 131, which requires
disclosure of selected financial information by business segment as viewed by
the chief operating decision-maker. See Note 16, "Business Segments" for further
discussion and details regarding segments.

Common Stock Options - At December 31, 2002, AEP has two stock-based employee
compensation plans with outstanding stock options, which are described more
fully in Note 15. AEP accounts for these plans under the recognition and
measurement principles of APB Opinion No. 25, Accounting for Stock Issued to
Employees and related Interpretations. No stock-based employee compensation
expense is reflected in AEP's earnings, as all options granted under these plans
had exercise prices equal to or above the market value of the underlying common
stock on the date of grant. The following table illustrates the effect on AEP's
net income (loss) and earnings (loss) per share as if AEP had applied the fair
value recognition provisions of FASB Statement No. 123, "Accounting for
Stock-Based Compensation", to stock-based employee compensation.

                                     Year Ended December 31,
                                   2002      2001      2000
                                   ----      ----      ----
                                          (in millions
                                      except per share data)

Net Income(Loss), as reported    $ (519)     $ 971     $ 267
Deduct:  Total stock-based
  employee compensation
  expense determined
  under fair value
  based method for
  all awards, net of
  related tax effects               (9)       (12)       (3)
                                ------      -----     -----
Pro forma net income
  (loss)                        $ (528)     $ 959     $ 264
                                ======      =====     =====

Earnings (Loss) per   share:
 Basic - as reported
                                $(1.57)     $3.01     $0.83
                                ======      =====     =====
 Basic - pro forma              $(1.59)     $2.98     $0.82
                                ======      =====     =====

 Diluted -  as reported
                                $(1.57)     $3.01     $0.83
                                ======      =====     =====
 Diluted - pro forma            $(1.59)     $2.97     $0.82
                                ======      =====     =====

Earnings Per Share (EPS) - AEP calculates earnings (loss) per share in
accordance with SFAS No. 128, "Earnings Per Share" (see Note 19). Basic earnings
(loss) per common share is calculated by dividing net earnings (loss) available
to common shareholders by the weighted average number of common shares
outstanding during the period. Diluted earnings (loss) per common share is
calculated by adjusting the weighted average outstanding common shares, assuming
conversion of all potentially dilutive stock options and awards. The effects of
stock options have not been included in the fiscal 2002 diluted loss per common
share calculation as their effect would have been anti-dilutive. Basic and
diluted EPS are the same in 2002, 2001 and 2000.

AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are wholly-owned
subsidiaries of AEP and are not required to report EPS.

Reclassification - Beginning in the fourth quarter of 2002, AEP and its
registrant subsidiaries elected to begin netting certain assets and liabilities
related to forward physical and financial transactions. This is done in
accordance with FASB Interpretation No. 39, "Offsetting of Amounts Related to
Certain Contracts" and Emerging Issues Task Force Topic D-43, "Assurance That a
Right of Setoff is Enforceable in a Bankruptcy under FASB Interpretation No.
39". Transactions with common counterparties have been netted at the applicable
entity level, by commodity and type (physical or financial) where the legal
right of offset exists. For comparability purposes, prior periods presented in
this report have been netted in accordance with this policy.

Certain additional prior year financial statement items have been reclassified
to conform to current year presentation. Such reclassifications had no impact on
previously reported net income.

New Accounting Pronouncements

SFAS 142, "Goodwill and Other Intangible Assets", was effective for AEP on
January 1, 2002. The adoption of SFAS 142 required the transition testing for
impairment of all indefinite lived intangibles by the end of the first quarter
2002 and initial testing of goodwill by the end of the second quarter 2002. In
the first quarter 2002, AEP completed testing the goodwill of its domestic
operations and its indefinite lived intangible assets and there was no
impairment. In the second quarter 2002, AEP completed initial testing for
goodwill impairment of the U.K. and Australian retail electricity and supply
operations. The fair values of the U.K. and Australia retail electricity and
supply operations were estimated using a combination of market values based on
recent market transactions and cash flow projections. As a result of that
testing, AEP determined that there was a net transitional impairment loss, which
is reported as a cumulative effect of a change in accounting principle. See
Notes 2, 3, 12 and 13 for further discussion of the actual impairment charges
and sales of impaired assets.

SFAS 142 also changed the accounting and reporting for goodwill and other
intangible assets. In accordance with SFAS 142 goodwill and indefinite lived
intangible assets acquired through acquisition after June 30, 2001 were not
amortized. Effective January 1, 2002, amortization related to goodwill and
indefinite lived intangible assets acquired before July 1, 2001 ceased. SFAS 142
requires that other intangible assets be separately identified and if they have
finite lives, they must be amortized over that life. See Note 3 for amortization
lives of AEP's and SWEPCo's intangible assets.

SFAS 143, "Accounting for Asset Retirement Obligations", is effective for AEP on
January 1, 2003. SFAS 143 generally applies to legal obligations associated with
the retirement of long-lived assets. A company is required to recognize an
estimated liability for any legal obligations associated with the future
retirement of its long-lived assets. The liability is measured at fair value and
is capitalized as part of the related asset's capitalized cost. The increase in
the capitalized cost is included in determining depreciation expense over the
expected useful life of the asset. The catch-up effect of adopting SFAS 143 will
be recorded as a cumulative effect of an accounting change. Additionally,
because the asset retirement obligation is recorded initially at fair value,
accretion expense (similar to interest) will be recognized each period as an
operating expense in the statement of operations.

The regulated entities have an asset retirement obligation associated with
nuclear decommissioning costs for the Cook and STP Nuclear Plants (affects I&M
and TCC) and possibly other obligations. AEP expects to establish regulatory
assets and liabilities that will result in no cumulative effect adjustment of
adopting SFAS 143 for the regulated entities.

In addition, the regulated transmission and distribution entities have asset
retirement obligations related to the final retirement of certain transmission
and distribution lines. There are also underground storage tanks located at
various sites throughout the AEP System and PCB's are contained in certain
transformer rectifier sets at power plants. The amounts relating to these
obligations cannot be determined because the entities are not able to estimate
the final retirement dates for these facilities.

In January 2003, the SEC Staff concluded that SFAS 143 also precludes an entity
from recording an expense for estimated costs associated with the removal or
retirement of assets that result from other than legal obligations. The SEC
Staff concluded that amounts that are included in accumulated depreciation
related to estimated removal costs arising from other than legal obligations
should be written off as part of the cumulative effect of adopting SFAS 143
unless the company is regulated under SFAS 71. Companies regulated under SFAS 71
may continue to include removal costs in depreciation rates but must quantify
the removal costs included in accumulated depreciation as regulatory liabilities
in footnote disclosure. The AEP registrant subsidiaries that are regulated
entities have included estimated removal costs for non-legal retirement
obligations in book depreciation rates.

For non-regulated entities, including certain formerly regulated generation
facilities, asset retirement obligations associated with wind farms, closure
costs associated with power plants in the U.K. and possibly other items will be
incurred. Also the amount of removal costs embedded in accumulated depreciation
is expected to result in a favorable cumulative effect adjustment to net income.
However, AEP and its registrant subsidiaries have not completed their
determination of the net effect of these items on first quarter 2003 results of
operations upon the adoption of the provisions of this standard.

In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-lived Assets" which sets forth the accounting to recognize and
measure an impairment loss. This standard replaced, SFAS 121, "Accounting for
Long-lived Assets and for Long-lived Assets to be Disposed Of." AEP adopted SFAS
144 effective January 1, 2002. The adoption of SFAS 144 did not materially
affect AEP's results of operations or financial conditions. See Notes 3 and 13
for discussion of impairments recognized in 2002 by AEP and its registrant
subsidiaries, affected by SFAS 144.

In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS
145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt",
effective for fiscal years beginning after May 15, 2002. SFAS 4 required gains
and losses from extinguishment of debt to be aggregated and classified as an
extraordinary item if material. In 2003, for financial reporting purposes AEP
and TCC will reclassify extraordinary losses net of tax on TCC's reacquired debt
of $2 million for 2001.

In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3, "Recognition and Reporting of Gains and Losses on
Energy Contracts under Issues No. 98-10 and 00-17" (EITF 02-3). EITF 02-3
rescinds EITF 98-10 and related interpretive guidance. Under EITF 02-3,
mark-to-market accounting is precluded for energy trading contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10 will also
eliminate any basis for recognizing physical inventories at fair value other
than as provided by generally accepted accounting principles. The consensus is
effective for fiscal periods beginning after December 15, 2002, and applies to
all energy trading contracts entered into and inventory purchased through
October 25, 2002. Effective January 1, 2003, nonderivative energy contracts are
required to be accounted for on a settlement basis and inventory is required to
be presented at the lower of cost or market. The effect of implementing this
consensus will be reported as a cumulative effect of an accounting change. Such
contracts and inventory will continue to be accounted for at fair value through
December 31, 2002. Energy contracts that qualify as derivatives will continue to
be accounted for at fair value under SFAS 133.

Effective January 1, 2003, EITF 02-3 requires that gains and losses on all
derivatives, whether settled financially or physically, be reported in the
income statement on a net basis if the derivatives are held for trading
purposes. Previous guidance in EITF 98-10 permitted non-financial settled energy
trading contracts to be reported either gross or net in the income statement.
Prior to the third quarter of 2002, AEP and its registrant subsidiaries recorded
and reported upon settlement, sales under forward trading contracts as revenues
and purchases under forward trading contracts as purchased energy expenses.
Effective July 1, 2002, AEP and its registrant subsidiaries reclassified such
forward trading revenues and purchases on a net basis, as permitted by EITF
98-10. The reclassification of such trading activity to a net basis of reporting
resulted in a substantial reduction in both revenues and purchased energy
expense, but did not have any impact on financial condition, results of
operations or cash flows.

Effective July 1, 2002, AEP and its registrant subsidiaries modified their
valuation procedures for estimating the fair value of energy trading contracts
at inception. Unrealized gain or loss at inception is recognized only when the
fair value of a contract is obtained from a quoted market price in an active
market or is otherwise evidenced by comparison to other observable market data.
Any fair value changes subsequent to the inception of a contract, however, are
recognized immediately based on the best market data available. AEP and its
registrant subsidiaries now also use such procedures for determining unrealized
gain or loss at inception for all derivative contracts.

In June 2002, FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes previous
accounting guidance, principally EITF No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. SFAS 146 requires that the liability for costs associated with
an exit or disposal activity be recognized when the liability is incurred. SFAS
146 also establishes that the liability should initially be measured and
recorded at fair value. The timing of recognizing future costs related to exit
or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. AEP will adopt the provisions of SFAS
146 for exit or disposal activities initiated after December 31, 2002.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others" (FIN 45) which requires that a liability related to
issuing a guarantee be recognized, as well as additional disclosures of
guarantees. This new guidance is an interpretation of SFAS Nos. 5, 57 and 107
and a rescission of FIN No. 34. The initial recognition and initial measurement
provisions of FIN 45 are effective on a prospective basis to guarantees issued
or modified after December 31, 2002. The disclosure requirements of FIN 45 are
effective for financial statements of interim and annual periods ending after
December 15, 2002. We do not expect that the implementation of FIN 45 will
materially affect results of operations, cash flows or financial condition. See
guarantee details discussed in Note 10.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation-Transition and Disclosure", which amends SFAS No. 123, "Accounting
for Stock-Based Compensation". SFAS 148 provides alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. Under the fair value based method,
compensation cost for stock options is measured when options are issued. In
addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require
more prominent and more frequent (quarterly) disclosures in financial statements
of the effects of stock-based compensation. SFAS 148 is effective for fiscal
years ending after December 15, 2002. AEP does not currently intend to adopt the
fair value based method of accounting for stock options.

In November 2002, the FASB issued an Invitation to Comment, "Accounting for
Stock-Based Compensation: A Comparison of FASB Statement No. 123, Accounting for
Stock-Based Compensation, and Its Related Interpretations, and IASB Proposed
IFRS, Share-Based Payment." The FASB plans to make a decision in the first
quarter of 2003 whether it will begin a more comprehensive reconsideration of
the accounting for stock options. This may include revisiting the decision in
SFAS 123 allowing companies to disclose the pro forma effects of the fair value
based method rather than requiring recognition of the fair value of employee
stock options as an expense.

In January 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46) which changes the requirements for
consolidation of certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have sufficient
equity at risk for the entity to finance its activities without additional
subordinated financial support from other parties. This new guidance is an
interpretation of Accounting Research Bulletin (ARB) No. 51, "Consolidated
Financial Statements". The initial recognition and initial measurement
provisions of FIN 46 for all enterprises with variable interests in variable
interest entities created after January 31, 2003, shall apply the provisions of
this Interpretation to those entities immediately. A public entity with variable
interests in variable interest entities created before February 1, 2003 shall
apply the provisions of this Interpretation no later than the beginning of the
first interim or annual reporting period beginning after June 15, 2003.

If it is reasonably possible that an enterprise will consolidate or disclose
information about a variable interest entity when this Interpretation becomes
effective, the enterprise shall disclose the following information in all
financial statements initially issued after January 31, 2003, regardless of the
date on which the variable interest entity was created:

a. The nature, purpose, size, and activities of the variable interest entity
b. The enterprise's maximum exposure to loss as a result of its involvement
    with the variable interest entity

AEP and its subsidiaries believe it is reasonably possible that they will be
required to consolidate identified variable interest entities as a result of
this new guidance. See Notes 9, 22, 23 and 26 for additional disclosures
relating to the variable interest entities.

2. Extraordinary Items and Cumulative Effect:

Extraordinary Items - Extraordinary items were recorded for the discontinuance
of regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas state
jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for
descriptions of the restructuring plans and related accounting effects. OPCo and
CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits during the quarter ended June 30, 2001. This loss resulted from
regulatory decisions in connection with Ohio deregulation which stranded the
recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo
and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies
appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the
Ohio companies believe failed to provide for recovery for the final year of the
GRT. In April 2002, the Ohio Supreme Court denied recovery of the final year of
the GRT.

In October 2001, TCC reacquired $101 million of pollution control bonds in
advance of their maturity. Since these pollution control bonds were used to
finance unregulated generation assets, a loss of $2 million after-tax was
recorded. AEP and its registrant subsidiaries had no extraordinary items in
2002.

The following table shows the components of the extraordinary items reported on
AEP's Consolidated Statements of Operations:

                                  Year Ended
                                 December 31,
                                 -----------
                               2002  2001  2000
                               ----  ----  ----
                                (in millions)
Extraordinary Items:
 Discontinuance of Regulatory
 Accounting for Generation:
 Ohio Jurisdiction (Net of Tax
  of $20 million in 2001 and
  $35 Million in 2000)(a)       $ -  $(48) $(44)
 Virginia and West Virginia
   Jurisdictions (Inclusive of
   Tax Benefit of $8 Million)(b)  -     -     9
 Loss on Reacquired Debt
  (Net of Tax of $1 Million
   in 2001)(c)                    -    (2)    -
                                ---- ----  ----

  Extraordinary Items           $ -  $(50) $(35)
                                ==== ====  ====

(a) Relates to AEP, OPCo and CSPCo.
(b) Relates to AEP and APCo.
(c) Relates to AEP and TCC.

Cumulative Effect of Accounting Change - SFAS 142 requires that goodwill and
intangible assets with indefinite useful lives no longer be amortized and be
tested annually for impairment. The implementation of SFAS 142 resulted in a
$350 million net transitional loss for our U.K. and Australian operations and is
reported in AEP's Consolidated Statements of Operations as a cumulative effect
of accounting change (see Note 3 for further details).

The FASB's Derivative Implementation Group (DIG) issued accounting guidance
under SFAS 133 for certain derivative fuel supply contracts with volumetric
optionality and derivative electricity capacity contracts. This guidance,
effective in the third quarter of 2001, concluded that fuel supply contracts
with volumetric optionality cannot qualify for a normal purchase or sale
exclusion from mark-to-market accounting and provided guidance for determining
when certain option-type contracts and forward contracts in electricity can
qualify for the normal purchase or sale exclusion.

For AEP, the effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market effect of $18 million, net of tax of $2
million. It was reported as a cumulative effect of an accounting change on AEP's
Consolidated Statements of Operations.

3. Goodwill and Other Intangible Assets:

As described in the Significant Accounting Policies footnote, AEP adopted the
provisions of SFAS 141 effective July 1, 2001. SFAS 141 requires that the
purchase method of accounting be used for all business combinations initiated
after June 30, 2001 and established new standards for the recognition of certain
identifiable intangible assets, separate from goodwill. Business combinations
initiated after June 30, 2001 (see Note 12 for details) are accounted for
utilizing SFAS 141.

SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, but instead tested for impairment at least
annually. SFAS 142 required a two-step impairment test for goodwill. The first
step was to compare the carrying amount of the reporting unit's assets to the
fair value of the reporting unit. If the carrying amount exceeded the fair value
then the second step was required to be completed, which involves allocating the
fair value of the reporting unit to each asset and liability, with the excess
being implied goodwill. The impairment loss is the amount by which the recorded
goodwill exceeds the implied goodwill. AEP was required to complete a
"transitional" impairment test for goodwill as of the beginning of the fiscal
year in which the statement was adopted. This transitional impairment test
required that AEP complete step one of the goodwill impairment test within six
months from the date of initial adoption, or June 30, 2002. In the first quarter
2002, AEP completed the transitional impairment test of goodwill related to
domestic operations and indefinite lived intangible assets and concluded that
those assets were not impaired.

In the second quarter 2002, AEP completed testing for goodwill impairment on
AEP's U.K. and Australian retail electricity and supply operations. The fair
values of the U.K. and Australian retail electricity and supply operations were
estimated using a combination of market values based on recent market
transactions and cash flow projections. As a result of this testing, AEP
determined that there was a net transitional impairment loss of $350 million,
which was reported in AEP's Consolidated Statements of Operations as a
Cumulative Effect of Accounting Change.

SFAS 142 also requires that intangible assets with finite useful lives be
amortized over their respective estimated lives to the estimated residual
values. In accordance with SFAS 142, for all business combinations initiated
before July 1, 2001, AEP amortized goodwill and intangible assets with
indefinite lives through December 2001, and then ceased amortization. The
goodwill associated with those business combinations with acquisition dates
before July 1, 2001 was amortized on a straight-line basis generally over 40
years except for the portion of goodwill associated with gas trading and
marketing activities, which was amortized on a straight-line basis over 10
years. Also, in accordance with SFAS 142, for all business combinations with
acquisition dates after June 30, 2001, AEP has not amortized goodwill and
intangible assets with indefinite lives. Intangible assets with finite lives
continue to be amortized over their respective estimated lives ranging from 5 to
10 years.

New reporting requirements imposed by SFAS 142 include the disclosures shown
below.



Goodwill

The changes in AEP's the carrying amount of goodwill for the twelve months ended
December 31, 2002 by operating segment are:

<TABLE>
<CAPTION>


                                                                                      Energy                        AEP
                                                                     Wholesale       Delivery       Other      Consolidated
                                                                     ---------       --------       -----      ------------
                                                                                         (in millions)
<S>                                                                    <C>            <C>           <C>           <C>
  Balance January 1, 2002                                               $340           $37           $15           $392
  Goodwill acquired                                                        2            -             -               2
  Changes to Goodwill due to purchase price
   adjustments                                                           181            -             -             181
  Non-transitional impairment losses                                    (173)           -            (12)          (185)
  Foreign currency exchange rate changes                                   6            -             -               6
                                                                        ----           ---           ---           ----
  Balance December 31, 2002                                             $356           $37           $ 3           $396
                                                                        ====           ===           ===           ====

</TABLE>

Accumulated amortization of goodwill was approximately $22 million and $25
million at December 31, 2002 and 2001, respectively. A decrease of $3 million
related principally to the non-transitional impairment of goodwill on Gas Power
Systems (see Note 13a).

The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as a cumulative effect of an accounting change, is excluded
from the above schedule. Under SFAS 144, the assets of SEEBOARD and CitiPower,
including goodwill and acquired intangible assets no longer subject to
amortization, are reported as Assets of Discontinued Operations in AEP's
Consolidated Balance Sheets. See Note 12 related to the sale of SEEBOARD and
CitiPower.

Changes to goodwill due to purchase price adjustments of $181 million was
primarily due to purchase price adjustments related to AEP's acquisition of U.K.
Generation. The purchase price adjustments also include adjustments related to
the acquisition of Houston Pipe Line Company, MEMCO, Nordic Trading and AEP Coal
(see Note 12).

In the first quarter of 2002, AEP recognized a goodwill impairment loss of $12
million for all goodwill related to the acquisition of Gas Power Systems (see
Note 13a).

In the fourth quarter of 2002, AEP prepared its annual goodwill impairment
tests. The fair values of the operations were estimated using cash flow
projections. There were no goodwill impairments as a result of the annual
goodwill impairment tests. However, in the fourth quarter, AEP recognized
goodwill impairment losses totaling $173 million related to impairment studies
performed on the U.K. Generation assets ($166 million), AEP Coal ($3 million),
and Nordic Trading ($4 million). These goodwill impairment studies were
triggered by the SFAS 144 asset impairment losses recognized on these operations
in the fourth quarter (refer to Note 13). The fair values of these operations
were estimated using cash flow projections.

The following tables show the transitional disclosures to adjust AEP's reported
net income (loss) and earnings (loss) per share to exclude amortization expense
recognized in prior periods related to goodwill and intangible assets that are
no longer being amortized.

<TABLE>
<CAPTION>


  Net Income (Loss)                                                                               Year Ended December 31,
                                                                                                  -----------------------
                                                                                              2002         2001        2000
                                                                                              ----         ----        ----
                                                                                                      (in millions)
<S>                                                                                         <C>          <C>           <C>
  Reported Net Income (Loss)                                                                 $(519)       $  971        $267
  Add back: Goodwill amortization (a)                                                          -              39          39
  Add back: Amortization for intangibles with indefinite
   lives under SFAS 142 (b)                                                                    -               8           9
                                                                                             -----        ------        ----
  Adjusted Net Income (Loss)                                                                 $(519)       $1,018        $315
                                                                                             =====        ======        ====
</TABLE>
<TABLE>
<CAPTION>


                                                                                                    Twelve Months Ended
  Earnings (Loss) Per Share (Basic and Dilutive)                                                        December 31,
                                                                                                    -------------------

                                                                                             2002          2001         2000
                                                                                             ----          ----         ----
<S>                                                                                        <C>           <C>          <C>
  Reported Earnings (Loss) per Share                                                        $(1.57)       $3.01        $0.83
  Add back: Goodwill amortization (c)                                                          -           0.12         0.12
  Add back: Amortization for intangibles with
   indefinite lives under SFAS 142 (d)                                                         -           0.02         0.03
                                                                                            ------        -----        -----
  Adjusted Earnings (Loss) per Share                                                        $(1.57)       $3.15        $0.98
                                                                                            ======        =====        =====
</TABLE>


(a)    This amount includes $34 million and $37 million in 2001 and 2000 related
       to Seeboard and CitiPower amortization expense included in Discontinued
       Operations on AEP's Consolidated Statements of Operations.
(b)    The amounts shown for 2001 and 2000 relate to CitiPower amortization
       expense included in Discontinued Operations on AEP's Consolidated
       Statements of Operations.
(c)    This amount includes $0.10 and $0.11 in 2001 and 2000 related to Seeboard
       and CitiPower amortization expense included in Discontinued Operations on
       AEP's Consolidated Statements of Operations.
(d)    The amounts shown for 2001 and 2000 relate to CitiPower amortization
       expense included in Discontinued Operations on AEP's Consolidated
       Statements of Operations.

Acquired Intangible Assets

Acquired intangible assets subject to amortization are $37 million at December
31, 2002 and $33 million at December 31, 2001, net of accumulated amortization.
Of those amounts, $25 million and $33 million at December 31, 2002 and 2001,
relate to SWEPCo. The gross carrying amount, accumulated amortization and
amortization life by major asset class are:

<TABLE>
<CAPTION>


                                                    December 31, 2002                        December 31, 2001
                                                           Gross                          Gross
                                      Amortization       Carrying  Accumulated           Carrying       Accumulated
                                           Life           Amount   Amortization           Amount        Amortization
                                      ------------       --------  ------------          -------        ------------
                                       (in years)            (in millions)                       (in millions)
<S>                                         <C>             <C>           <C>             <C>                  <C>
   Dolet Hills    Advanced
    Royalties (SWEPCo)                      10              $35           $5              $35                  $2
   Less: Adjustment   Due to
   Purchase   Price
   Reallocation
    (SWEPCo)                                                  6            1                -                   -
   Trade name and
    Administration of
   Contracts                                 7                2            -                -                   -
   Unpatented
    Technology                              10               10            -                -                   -
                                                            ---           --              ---                  --
   Totals                                                   $41           $4              $35                  $2
                                                            ===           ==              ===                  ==

</TABLE>


Amortization of intangible assets (primarily SWEPCo) was $2 million for the
twelve months ended December 31, 2002. AEP's estimated aggregate amortization
expense is $4 million for each year 2003 through 2008. SWEPCo's estimated
aggregate amortization expense (included in AEP's estimated amount) is $3
million for each year 2003 through 2008.

AEP's acquired intangible assets no longer subject to amortization were
comprised of retail and wholesale distribution licenses for CitiPower operating
franchises. The licenses were being amortized on a straight-line basis over 20
and 40 years for the retail and wholesale licenses, respectively. In accordance
with SFAS 144, the assets of CitiPower, including acquired intangible assets no
longer subject to amortization, are reported as Assets of Discontinued
Operations on one line in AEP's Consolidated Balance Sheets. See Note 12 related
to the sale of CitiPower.

4. Merger:

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9
million shares of AEP Common Stock were issued in exchange for all the
outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share
of AEP Common Stock for each share of CSW Common Stock.

The merger was accounted for as a pooling of interests. Accordingly, AEP's
consolidated financial statements give retroactive effect to the merger, with
all periods presented as if AEP and CSW had always been combined. Certain
reclassifications have been made to conform the historical financial statement
presentation of AEP and CSW. Effective January 2003, the legal name of CSW was
changed to AEP Utilities, Inc.

In connection with the merger, $10 million ($7 million after tax), $21 million
($14 million after tax) and $203 million ($180 million after tax) of
non-recoverable merger costs were expensed in 2002, 2001 and 2000. Such costs
included transaction and transition costs not recoverable from ratepayers. Also
included in the merger costs were non-recoverable changes in control payments.
Merger transaction and transition costs of $52 million recoverable from
ratepayers were deferred pursuant to state regulator approved settlement
agreements through December 31, 2002. The deferred merger costs are being
amortized over five to eight year recovery periods, depending on the specific
terms of the settlement agreements, with the amortization ($8 million, $8
million and $4 million for the years 2002, 2001 and 2000) included in
depreciation and amortization expense.

The following tables show the deferred merger cost and amortization expense of
the applicable subsidiary registrants:

                              Amortization
            Merger Cost       Expense for the
            Deferral at       Year Ended
           December 31, 2002    December 31, 2002
           -----------------    -----------------
                           (in millions)
I&M              $8.2                $1.7
KPCo              2.9                 0.6
PSO               5.0                 1.6
SWEPCo            3.9                 1.1
TCC               9.1                 2.6
TNC               2.7                 0.8

                              Amortization
            Merger Cost       Expense for the
            Deferral at       Year Ended
           December 31, 2001    December 31, 2001
           -----------------    -----------------
                           (in millions)
I&M              $ 9.1               $1.7
KPCo               3.2                0.6
PSO                6.6                1.2
SWEPCo             5.0                1.1
TCC               11.8                2.6
TNC                3.5                0.8

                              Amortization
            Merger Cost       Expense for the
            Deferral at       Year Ended
           December 31, 2000    December 31, 2000
           -----------------    -----------------
                           (in millions)
I&M              $ 6.9               $0.7
KPCo               2.5                0.3
PSO                7.9                0.5
SWEPCo             6.1                0.5
TCC               14.4                1.3
TNC                4.2                0.4

Merger transition costs are expected to continue to be incurred for several
years after the merger and will be expensed or deferred for amortization as
appropriate. As hereinafter summarized, the state settlement agreements provide
for, among other things, a sharing of net merger savings with certain regulated
customers over periods of up to eight years through rate reductions which began
in the third quarter of 2000.

Summary of key provisions of Merger Rate Agreements:

State/Company Ratemaking Provisions

Texas - SWEPCo, TCC, TNC   $221 million rate reduction over 6 years.
                           No base rate increases for 3 years post merger.

Indiana - I&M              $67 million rate reduction over 8 years.  Extension
                           of base rate freeze until January 1, 2005.  Requires
                           additional annual deposits of $6 million to the
                           nuclear decommissioning  trust  fund  for the
                           years 2001 through 2003.

Michigan - I&M             Customer billing credits of approximately $14
                           million over 8 years. Extension of base rate freeze
                           until January 1, 2005.

Kentucky - KPCo            Rate reductions of approximately $28 million over
                           8 years. No base rate increases for 3 years post
                           merger.

Oklahoma - PSO             Rate reductions of approximately $28 million over
                           5 years. No base rate increase before January 1,
                           2003.

Arkansas - SWEPCo          Rate reductions of $6 million
                           over 5 years.

Louisiana - SWEPCo         Rate reductions to share merger savings estimated
                           to be $18 million over 8 years. Base rate
                           cap until June 2005.

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

See Note 9, "Commitments and Contingencies" for information on a court decision
concerning the merger.

5. Nuclear Plant Restart:

I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant
is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted
by the NRC. I&M shut down both units of the Cook Plant, in September 1997, due
to questions regarding the operability of certain safety systems that arose
during a NRC architect engineer design inspection.

Settlement agreements in the Indiana and Michigan retail jurisdictions that
address recovery of Cook Plant related outage costs were approved in 1999. The
IURC approved a settlement agreement that resolved all matters related to the
recovery of replacement energy fuel costs and all outage/restart costs and
related issues during the extended outage of the Cook Plant. The MPSC approved
a settlement agreement for two open Michigan power supply cost recovery
reconciliation cases that resolved all issues related to the Cook Plant
extended outage. The settlement agreements allowed:

o    Deferral of $200 million of non-fuel nuclear operation and maintenance
     (O&M) costs for amortization over five years ending December 31, 2003,
o    Deferral of certain unrecovered fuel and power supply costs for
     amortization over five years ending December 31, 2003,
o    A freeze in base rates through December 31, 2003 and a fixed fuel
     recovery charge through March 1, 2004 in the Indiana
     jurisdiction,
o    A freeze in base rates and fixed power supply costs recovery factors
     until January 1, 2004 for the Michigan jurisdiction.

The amount of costs and deferrals charged to other operation and maintenance
expenses were as follows:

                                    Year Ended December 31,
                                    2002     2001     2000
                                    ----     ----     ----

Costs Incurred                       $-       $ 1      $297
Amortization of Deferrals             40       40        40
                                   -  --   -   --   --   --

Charged to O&M Expense               $40      $41      $337
                                     ===      ===      ====

At December 31, 2002 and 2001, deferred O&M costs of $40 million and $80
million, respectively, remained in Regulatory Assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million were amortized as a reduction of revenues in each of 2002, 2001
and 2000. At December 31, 2002 and 2001, fuel-related revenues of $37 million
and $75 million, respectively, were included in Regulatory Assets and will be
amortized through December 31, 2003 for both jurisdictions.

The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements will adversely affect
results of operations through December 31, 2003 when the amortization period
ends. The annual amortization of O&M costs and fuel-related revenue deferrals is
approximately $78 million.


6. Rate Matters:

Texas Fuel - Affecting AEP, SWEPCo, TCC and TNC

Prior to the start of retail competition in ERCOT on January 1, 2002, fuel
recovery for Texas utilities was a multi-step procedure. When fuel costs
changed, utilities filed with the PUCT for authority to adjust fuel factors. If
a utility's prior fuel factors resulted in material over-recovery or
under-recovery of fuel costs, the utility would also request a refund or
surcharge factor to refund or collect those amounts. While fuel factors were
intended to recover fuel costs, final settlement of these amounts was subject to
reconciliation and approval by the PUCT.

Fuel reconciliation proceedings determine whether fuel costs incurred during the
reconciliation period were reasonable and necessary. All fuel costs incurred
since the prior reconciliation date are subject to PUCT review and approval. If
material amounts are determined to be unreasonable and ordered to be refunded to
customers, results of operations and cash flows would be negatively impacted.

According to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 is no longer subject to PUCT review and reconciliation.
During 2002, TCC and TNC filed final fuel reconciliations with the PUCT to
reconcile their fuel costs through the period ending December 31, 2001. The
ultimate recovery of deferred fuel balances at December 31, 2001 will be decided
as part of their 2004 true-up proceedings. See discussion of TCC and TNC fuel
reconciliations below.

In October 2001, the PUCT delayed the start of customer choice in the SPP area
of Texas. All of SWEPCo's Texas service territory and a small portion of TNC's
service territory are in SPP. SWEPCo's existing Texas fuel cost recovery
procedures will continue until competition begins. SWEPCo will continue to set
fuel factors and determine final fuel costs in fuel reconciliation proceedings
during the SPP delay period. The PUCT has ruled that TNC fuel factors in the SPP
area will be based upon the price-to-beat fuel factors offered by the retail
electric provider in the ERCOT portion of TNC's service territory. TNC
transferred its SPP customers to Mutual Energy SWEPCo effective December 1,
2002. TNC filed in 2002 with the PUCT to determine the most appropriate method
to reconcile fuel costs in TNC's SPP area and a decision is expected by mid
2003.

Under Texas restructuring, customer choice to select a retail electric provider
began January 1, 2002. Sales to customers using 1 MW or less will be at fixed
base rates during a transition period from 2002 through 2006. As discussed in
Note 12 "Acquisitions, Dispositions and Discontinued Operations", AEP sold its
Texas retail electric providers (REP) and their retail customers in December
2002.

The former AEP subsidiaries serving as REPs for the ERCOT area filed with the
PUCT in May 2002 to increase the fuel portion of their price-to-beat rate in
compliance with the Texas Restructuring Legislation and the PUCT's rules. The
Texas legislation provides for the adjustment of the fuel portion of the rate up
to twice annually to reflect significant changes in the market price of natural
gas and purchased energy used to serve retail customers using NYMEX natural gas
prices. On July 15, 2002, the PUCT required further hearings to reconsider the
validity of their existing rules for fuel factor adjustments. On July 24, 2002,
the Texas REPs filed a petition with the District Court seeking an injunction
commanding the PUCT to proceed to a final order based on the existing rules and
prohibiting the PUCT from conducting a remand proceeding. The District Court
issued an order on August 9, 2002 requiring the PUCT to comply with the existing
rules. On August 26, 2002, the PUCT issued an order approving a 22% increase to
the fuel portion of the price-to-beat rates effective immediately for both REPs.
The PUCT order approving the 22% increase has been appealed by parties opposing
the price-to-beat adjustment. With the sale of the REPs to Centrica in December
2002, Centrica is responsible for these appeals. Any adverse ruling from the
appeal could impact TCC and TNC by requiring refunds for the time period AEP
served the retail customers prior to the sale to Centrica (January 2002 to
December 2002).


TCC Fuel Reconciliation  - Affecting AEP and TCC

In December 2002, TCC filed with the PUCT to reconcile fuel costs and to defer
its over-recovery of fuel for inclusion in the 2004 true-up proceeding. This
reconciliation for the period of July 1998 through December 2001 will be the
final fuel reconciliation. At December 31, 2001, the over-recovery balance for
TCC was $63.5 million including interest. During the reconciliation period, TCC
incurred $1.6 billion of eligible fuel and fuel-related expenses.
Recommendations from intervening parties are expected in April 2003 with
hearings scheduled in May 2003. A final order is expected in late 2003. An
adverse ruling from the PUCT could have a material impact on future results of
operations, cash flows and financial condition. Additional information regarding
the 2004 true-up proceeding for TCC can be found in Note 8 "Customer Choice and
Industry Restructuring".

TNC Fuel Reconciliation - Affecting AEP and TNC

In June 2002, TNC filed with the PUCT to reconcile fuel costs and to defer any
unrecovered portion applicable to retail sales within its ERCOT service area for
inclusion in the 2004 true-up proceeding. This reconciliation for the period of
July 2000 through December 2001 will be the final fuel reconciliation for TNC's
ERCOT service territory. At December 31, 2001, the under-recovery balance
associated with TNC's ERCOT service area was $27.5 million including interest.
During the reconciliation period, TNC incurred $293.7 million of eligible fuel
costs serving both ERCOT and SPP retail customers. TNC also requested authority
to surcharge its SPP customers. TNC's SPP customers will continue to be subject
to fuel reconciliations until competition begins in SPP. The under-recovery
balance at December 31, 2001 for TNC's service within SPP was $0.7 million
including interest.

In October 2002, the filing was split into two phases for hearing purposes. The
first phase examined all components of the filing except for AEP trading
activities and the associated margins that flow back to customers as an offset
to fuel costs consistent with the PUCT - approved Texas merger settlement.
Intervenors filed testimony in the first phase recommending that up to $25
million of TNC's requested retail eligible fuel recovery be disallowed and
hearings were held on October 23, 2002. TNC disputed the recommendations. On
October 21, 2002, the PUCT Staff and Office of Public Utility Counsel (OPC)
filed a joint Motion for Summary Decision related to the second phase issue and
requested that approximately $18.5 million of TNC's retail eligible fuel
recovery be disallowed without a hearing. On November 8, 2002, the
administrative law judges (ALJs) in the case denied the motion. The intervenors
filed testimony on October 29, 2002 in the second phase recommending that up to
$34 million of TNC's requested retail eligible fuel recovery be disallowed. The
intervenors recommended disallowance includes the amount sought in the October
21 Motion for Summary Decision. The total intervenor recommended retail
disallowance is approximately $59 million. Hearings for the second phase were
held on November 13-14, 2002. On February 3, 2003, TNC filed a motion to reopen
the evidentiary record and include a decrease to retail eligible fuel costs of
$1.3 million, including interest, to reflect final resettlement revenues and
expenses from ERCOT for the period August through December 2001 (see discussion
in Fuel and Purchased Power below). The PUCT is expected to issue a final order
in this case by mid 2003. An adverse ruling from the PUCT could have a material
impact on future results of operations, cash flows and financial condition.

ERCOT Over-scheduling - Affecting AEP, TCC and TNC

ERCOT began serving as a central control center for all of ERCOT at the end of
July 2001 when ERCOT became a single control area. Qualified scheduling entities
(QSE) schedule loads and resources for ERCOT market participants including power
generation companies and retail electric providers. In August 2001, ERCOT
incurred substantial costs for managing transmission in its north zone. The
costs incurred by ERCOT to manage congestion are shared by all ERCOT QSEs. In
late 2001, the PUCT initiated an investigation of the impact of scheduling of
electric loads and resources by QSEs during August 2001. The PUCT's
investigation determined that a substantial amount of the congestion charges
were the result of QSEs, including AEP's QSE, scheduling more resources than
required to meet their actual load requirements in the ERCOT north zone. AEP's
QSE over-scheduled resources due to an error in the allocation of estimated load
requirements between ERCOT congestion zones. Pursuant to the PUCT's
investigation, QSEs, including AEP's QSE, agreed to a settlement that provides
for the refund of payments received for adjusting resource schedules for
congestion. The settlement was approved by the PUCT in November 2002. The
settlement recognizes that the scheduling errors were associated with the start
up of the ERCOT competitive market. AEP's QSE paid $3.2 million to ERCOT and
received $1.7 million from ERCOT in congestion refunds for a net payment of $1.5
million. Payments were assigned to TNC and the refunds were allocated to TCC and
TNC. TNC incurred a net cost of $2.8 million and TCC received a refund of $1.3
million. The TNC payment and TCC refund have been reflected in the final fuel
reconciliation filings for each company. However, intervening parties have
objected to the inclusion of the TNC payment in its final fuel reconciliation.
Recommendations from intervening parties in the TCC proceeding are not expected
until April 2003. An adverse ruling from the PUCT would impact future results of
operations, cash flows and financial condition.

Texas Transmission Rates - Affecting AEP, TCC and TNC

On June 28, 2001, the Supreme Court of Texas ruled that the transmission pricing
mechanism created by the PUCT in 1996 and used for the period January 1, 1997
through August 31, 1999 was invalid. The court upheld an appeal filed by
unaffiliated Texas utilities that the PUCT exceeded its statutory authority to
set such rates during that period. TCC and TNC were not parties to the case.
However, the companies' transmission sales and purchases were priced using the
invalid rates. It is unclear what action the PUCT will take to respond to the
court's ruling. If the PUCT changes rates retroactively, the result could have a
material unfavorable impact on results of operations and cash flows for TCC and
TNC.

FERC Wholesale Fuel Complaints - Affecting AEP and TNC

In May 2000, certain TNC wholesale customers filed a complaint with FERC
alleging that TNC had overcharged them through the fuel adjustment clause for
certain purchased power costs related to 1999 unplanned outages at TNC's
Oklaunion generation station. In November 2001, certain TNC wholesale customers
filed an additional complaint at FERC asserting that since 1997 TNC had billed
wholesale customers for not only the 1999 Oklaunion outage costs, but also
certain additional costs that are not permissible under the fuel adjustment
clause.

In December 2001, FERC issued an order requiring TNC to refund, with interest,
amounts associated with the May 2000 complaint that were previously billed to
wholesale customers. The effects of this order were recorded in 2001. In
response to the November 2001 complaint, negotiations to settle the complaint
and update the contracts are continuing. In March 2002, TNC recorded a provision
for refund of $2.2 million before income taxes. The actual refund and final
resolution of this matter could differ materially from this estimate and may
have a negative impact on future results of operations, cash flows and financial
condition.

FERC Transmission Rates - Affecting AEP, PSO, SWEPCo, TCC and TNC

In November 2001, FERC issued an order resulting from a remand by an appeals
court of a tariff compliance filing order issued in 1998 that had been appealed
by certain customers. The order required PSO, SWEPCo, TCC and TNC to submit
revised open access transmission tariffs and calculate and issue refunds for
overcharges from January 1, 1997. In July 2002, FERC approved a revised open
access transmission tariff and refunds of $1.3 million were issued to
unaffiliated entities.

Under FERC rules, the new tariffs resulted in a reallocation of previously
received transmission revenues among affiliates resulting in the following
income statement impact:

                              Increase (Decrease) Revenues
                              ----------------------------
                              2001        2002      Total
                                     (in millions)

PSO                         $ 2.8        $ 2.5     $ 5.3

SWEPCo                        3.2          2.8       6.0

TCC                          (6.0)        (2.8)     (8.8)

TNC                          (2.6)        (1.2)     (3.8)
                            -----        -----     -----

AEP Total                   $(2.6)       $ 1.3     $(1.3)
                            =====        =====     =====


Fuel and Purchased Power - Affecting AEP, PSO, SWEPCo, TCC and TNC

PSO has Under-Recovered Fuel Costs of $75.7 million at December 31, 2002,
representing fuel and purchased power costs recorded but not yet collected from
retail customers in Oklahoma. The first significant item causing the
under-recovery is approximately $44 million in reallocation of purchased power
costs for periods prior to January 1, 2002, as described below. The other
significant item impacting the under-recovered fuel costs are natural gas price
increases that were not expected when PSO set its quarterly factors during 2002.
The Corporation Commission of the State of Oklahoma (OCC) is currently reviewing
the reasons for the large under-recovered balance.

The AEP West electric operating companies' power is dispatched real-time on an
economic basis and is later allocated among the AEP West electric operating
companies using the Interchange Cost Reconstruction (ICR) system based on
dispatch information from internal and external sources. ICR is designed to
allocate the cost of power under the terms and conditions of the AEP West
Operating Agreement. During 2002, two ICR adjustments were made. The adjustments
were related to a 2002 true-up and a reallocation of years prior to 2002.

During the third quarter of 2002, AEP reallocated purchased power costs among
the four AEP West electric operating companies for the periods prior to January
1, 2002 (the ICR Adjustments). The effects of the reallocation on pre-tax income
were insignificant to PSO and TCC and increased pre-tax income at SWEPCo and TNC
by $2.4 million and $1.9 million, respectively.

The formation of the ERCOT single control zone increased the need for data
estimation and true-up which has resulted in extended true-up periods associated
with allocations being performed on estimated data. ERCOT can make adjustments
to companies' settlements for up to six months. A true-up process for 2002 was
completed and recorded in the fourth quarter of 2002 resulting in insignificant
changes in PSO's and SWEPCo's pre-tax income. TCC's pre-tax income was reduced
by $3.7 million and TNC's pre-tax income was increased by $4.8 million. As ERCOT
notifies TCC and TNC of further adjustments, they will be recorded.

PSO implemented new fuel rates in December 2002 following the OCC's review and
approval. The new fuel factors were designed to recover estimated fuel costs for
the next three months and to begin recovery of the under-recovered amount.
Recovery of the under-recovered amount is expected to occur over several months
and is subject to OCC review and approval.

For SWEPCo, the true-up process described above and the ICR Adjustments resulted
in a net increase in fuel costs recoverable from customers of $8 million
included in Regulatory Assets on AEP's and SWEPCo's Consolidated Balance Sheets.
The amount is recoverable from customers pursuant to the applicable fuel
recovery mechanisms and review of the state regulatory commissions in Arkansas,
Louisiana and Texas.

To the extent the OCC and/or the AEP West Commissions regulating SWEPCo do not
permit recovery of the revised fuel and purchased power costs, there could be an
adverse effect on results of operations and cash flows.

PSO Rate Review - Affecting AEP and PSO

In February 2003, the Director of the OCC filed an application requiring PSO to
file all documents necessary for a general rate review before August 1, 2003.
Management is unable to predict the result of this review as the documents and
data have not been assembled.

Louisiana Compliance Filing - Affecting AEP and SWEPCo

On October 15, 2002, SWEPCo filed with the Louisiana Public Service Commission
(LPSC) detailed financial information typically utilized in a revenue
requirement filing, including a jurisdictional cost of service. This filing was
required by the LPSC as a result of their order approving the merger between AEP
and CSW. The LPSC's merger order also provides that SWEPCo's base rates are
capped at the present level through mid 2005. The filing indicates that SWEPCo's
current rates should not be reduced. If the LPSC disagrees with our conclusion,
they could order SWEPCo to file all documents for a full cost of service revenue
requirement review in order to determine whether SWEPCo's capped rates should be
reduced which would adversely impact results of operations and cash flows.

FERC Long-term Contracts - Affecting AEP and AEP East and AEP West companies

In September 2002, the FERC voted to hold hearings to consider requests from
certain wholesale customers located in Nevada and Washington to break long-term
contracts which they allege are "high-priced". At issue are long-term contracts
entered during the California energy price spike in 2000 and 2001. The
complaints allege that AEP sold power at unjust and unreasonable prices. The
FERC delayed hearings to allow the parties to hold settlement discussions. In
January 2003, the FERC settlement judge assigned to the case indicated that the
parties' settlement efforts were not progressing and he recommended that the
complaint be placed back on the schedule for a hearing. In February 2003, AEP
and one of our customers agreed to terminate their contract with the customer
withdrawing its FERC complaint.

In a similar complaint, a FERC administrative law judge (ALJ) ruled in favor of
AEP and dismissed, in December 2002, a complaint filed by two Nevada utilities.
In 2000 and 2001, AEP agreed to sell power to the utilities for future delivery.
In late 2001, the utilities filed complaints that the prices for power supplied
under those contracts should be lowered because the market for power was
allegedly dysfunctional at the time such contracts were entered. The ALJ
rejected the utilities' complaint, held that the markets for future delivery
were not dysfunctional, and that the utilities had failed to demonstrate that
the public interest required that changes be made to the contracts. The ALJ's
order is preliminary and is subject to review by the FERC. The FERC will likely
rule on the ALJ's order in 2003. Management is unable to predict the outcome of
these proceedings or their impact on results of operations.

Environmental Surcharge Filing - Affecting AEP and KPCo

In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff to recover the cost of emissions control equipment being
installed at Big Sandy Plant. See NOx Reductions in Note 9 "Commitments and
Contingencies".

The surcharge request, as filed, would increase annual revenues by approximately
$21 million and must be approved by the KPSC before its inclusion in customers'
bills. If the KPSC does not approve an increase in the environmental surcharge,
results of operations and cash flows would be negatively impacted.

7. Effects of Regulation:

In accordance with SFAS 71 the consolidated financial statements include
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) recorded in accordance with regulatory actions in order to match
expenses and revenues from cost-based rates in the same accounting period.
Regulatory assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to reduce future
cost recoveries. Among other things, application of SFAS 71 requires that the
AEP System's regulated rates be cost-based and the recovery of regulatory assets
be probable. Management has reviewed all the evidence currently available and
concluded that the requirements to apply SFAS 71 continue to be met for all
electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and
Tennessee.

When the generation portion of the business in Arkansas, Ohio, Texas, Virginia
and West Virginia no longer met the requirements to apply SFAS 71, net
regulatory assets were written off for that portion of the business unless they
were determined to be recoverable as a stranded cost through regulated
distribution rates or wire charges in accordance with SFAS 101 and EITF 97-4. In
the Ohio and West Virginia jurisdictions generation-related regulatory assets
that are recoverable through transition rates have been transferred to the
distribution portion of the business and are being amortized as they are
recovered through charges to regulated distribution customers. These assets are
classified as "transition regulatory assets". As discussed in Note 8, "Customer
Choice and Industry Restructuring" the Virginia SCC ordered the
generation-related regulatory assets in the Virginia jurisdiction to remain with
the generation portion of the business. Generation-related regulatory assets in
the Virginia jurisdiction are being amortized concurrent with their recovery
through capped rates. These assets are also classified as "transition regulatory
assets." The Texas jurisdiction generation-related regulatory assets that are
eligible for recovery through securitization have been classified as "regulatory
assets designated for or subject to securitization." See Note 8 "Customer Choice
and Industry Restructuring" for further details.

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

                                               December 31,
                                               -----------
                                             2002       2001
                                             ----       ----
                                             (in millions)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes                 $  791     $  814
  Transition Regulatory Assets                743        847
  Regulatory Assets
   Designated for or Subject to
   Securitization                             336        959
  Texas Wholesale Clawback (a)                262        -
  Deferred Fuel Costs                         143        139
  Unamortized Loss on
   Reacquired Debt                             83         99
  Cook Plant Restart Costs                     40         80
  DOE Decontamination and
   Decommissioning
   Assessment                                  26         31
  Other                                       264        193
                                           ------     ------
Total Regulatory Assets                    $2,688     $3,162
                                           ======     ======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                             $  455     $ 491
  Texas Retail Clawback (a)                    66       -
  Other                                       419       393
                                           ------     -----
Total Regulatory Liabilities               $  940     $ 884
                                           ======     =====

(a) See "Texas Restructuring" section of Note 8.


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:
<TABLE>

                                             AEGCo                            APCo
                                ------------------------------   ------------------------------
                                                     Recovery/                        Recovery/
                                                      Refund                           Refund
                                   2002      2001     Period       2002       2001     Period
                                   ----      ----    --------      ----       ----    --------
                                                          (in thousands)
<S>                             <C>      <C>         <C>       <C>         <C>       <C>
Regulatory Assets:
  Amounts Due From
   Customers For Future
   Income Taxes                                                $209,884    $189,794  Note 1
  Transition - Regulatory
   Assets Virginia                                               39,670      46,981  Jun. 2007
  Transition - Regulatory
   Assets West Virginia                                         119,038     127,998  Jun. 2011
  Deferred Fuel Costs                                             5,367      11,732
  Unamortized Loss on
   Reacquired Debt              $ 4,970  $ 5,207     Note 2       9,147      10,421  Note 2
  Deferred Storm Damage                                            -              6
  Other                                                          12,447      10,451  Note 3
                                -------  -------               --------    --------
Total Regulatory Assets         $ 4,970  $ 5,207               $395,553    $397,383
                                =======  =======               ========    ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $52,943  $56,304     Note 4       $ 33,691 $ 38,328  Note 4
  WV Rate Stabilization                                             75,601   75,601  Note 5
  Amounts Due To Customers
   For Future Income Taxes       16,670   22,725     Note 1
  Other                                                                 72      112  Note 3
                                -------  -------                  -------- --------
Total Regulatory Liabilities    $69,613  $79,029                  $109,364 $114,041
                                =======  =======                  ======== ========

</TABLE>

Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortization will be determined by the WVPSC to offset market prices.

<TABLE>
<CAPTION>


                                             CSPCo                           I&M
                               -------------------------------  -------------------------------
                                                     Recovery/                        Recovery/
                                                      Refund                           Refund
                                   2002      2001     Period       2002      2001      Period
                                   ----      ----    --------      ----      ----     --------
                                                        (in thousands)
<S>                            <C>        <C>                   <C>          <C>       <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes     $ 26,290   $ 28,361  Note 1      $163,928     $171,605  Note 1
  Transition - Regulatory
   Assets                       204,961    223,830  Dec. 2008
  Deferred Fuel Costs                                             37,501       75,002  Dec. 2003
  Unamortized Loss on
   Reacquired Debt                5,978      7,010  Note 2        14,994       16,255  Note 2
  Cook Plant Restart Costs                                        40,000       80,000  Dec. 2003
  Incremental Nuclear Refueling
   Outage Expenses (Net)                                          29,572        2,995  Note 5
  DOE Decontamination and
   Decommissioning Assessment                                     23,375       27,784  Dec. 2008
  Other                          20,453      3,066  Note 3        38,842       35,286  Note 3
                               --------   --------              --------     --------
Total Regulatory Assets        $257,682   $262,267              $348,212     $408,927
                               ========   ========              ========     ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                 $ 33,907  $ 37,176   Note 4      $ 97,709     $105,449  Note 4
  Other                            -           31   Note 3        65,983       52,479  Note 3
                               --------  --------               --------     --------
Total Regulatory Liabilities   $ 33,907  $ 37,207               $163,692     $157,928
                               ========  ========               ========     ========

</TABLE>

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-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Amortized over the period beginning with the commencement of an outage and
ending with the beginning of the next outage.

<TABLE>
<CAPTION>


                                              KPCo                             OPCo
                                  ------------------------------   ----------------------------
                                                     Recovery/                        Recovery/
                                                      Refund                           Refund
                                   2002      2001     Period       2002       2001     Period
                                   ----      ----    --------      ----       ----    --------
                                                        (in thousands)
<S>                             <C>        <C>        <C>        <C>        <C>       <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $ 87,261   $83,027    Note 1     $165,106   $186,740  Note 1
  Transition - Regulatory
   Assets                                                         375,409    442,707  Dec. 2007
  Deferred Fuel Costs               -        1,542
  Unamortized Loss on
   Reacquired Debt                   152        51    Note 2        4,899      5,502  Note 2
  Other                           14,563    13,072    Note 3       23,227      9,676  Note 3
                                --------   -------               --------   --------
Total Regulatory Assets         $101,976   $97,692               $568,641   $644,625
                                ========   =======               ========   ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $  9,165   $10,405    Note 4     $ 18,748   $ 21,925  Note 4
  Other                           12,152     6,551    Note 3        1,237      1,237  Note 3
                                --------   -------               --------   --------
Total Regulatory Liabilities    $ 21,317   $16,956               $ 19,985   $ 23,162
                                ========   =======               ========   ========

</TABLE>

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-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.

<TABLE>
<CAPTION>


                                              PSO                             SWEPCo
                                  -----------------------------   ------------------------------
                                                     Recovery/                        Recovery/
                                                      Refund                          Refund
                                   2002      2001     Period       2002       2001    Period
                                   ----      ----    --------      ----       ----   --------
                                                        (in thousands)
<S>                             <C>         <C>       <C>        <C>        <C>       <C>
Regulatory Assets:
  Amounts Due From
   Customers For Future
   Income Taxes                                                  $ 19,855   $ 16,532  Note 1
  Deferred Fuel Costs           $ 76,470    $   756   Note 1        2,865      8,839  Note 1
  Unamortized Loss on
   Reacquired Debt                11,138     12,381   Note 2       17,031     20,045  Note 2
  Other                           15,012     22,683   Note 3       12,347     15,731  Note 3
                                --------    -------              --------   --------
Total Regulatory Assets         $102,620    $35,820              $ 52,098   $ 61,147
                                ========    =======              ========   ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $ 32,201    $33,992   Note 4     $ 44,190   $ 48,714  Note 4
  Ammounts Due To Customers
   For Future Income Taxes        27,893     26,085   Note 1
  Deferred Fuel Costs               -         9,476   Note 1       17,226      5,487  Note 1
  Other                            4,391     22,444   Note 3        7,094     10,889  Note 3
                                --------    -------              --------   --------
Total Regulatory Liabilities    $ 64,485    $91,997              $ 68,510   $ 65,090
                                ========    =======              ========   ========

</TABLE>


Note 1: This amount fluctuates from month to month and has no fixed
recovery/refund period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-six years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions.

<TABLE>
<CAPTION>


                                              TCC                             TNC
                                  ----------------------------   -------------------------------
                                                     Recovery/                        Recovery/
                                                      Refund                          Refund
                                   2002      2001     Period       2002       2001    Period
                                   ----      ----    --------      ----       ----   --------
                                                        (in thousands)

<S>                              <C>      <C>        <C>          <C>       <C>       <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes       $162,247 $  200,496 Note 1
  Regulatory Assets -
   Designated For or Subject
   To Securitization              336,444    959,294 Note 5
  Deferred Fuel Costs                                             $26,680   $ 40,389  Note 5
  Texas Wholesale Clawback        262,000       -    Note 5
  Unamortized Loss on
   Reacquired Debt                  8,661     11,186 Note 2         3,283      8,272  Note 2
  Deferred Debt - Restructuring    13,324       -    Note 2        10,134       -     Note 2
  DOE Decontamination and
   Decommissioning Assessment       3,170      3,170 Dec. 2004
  Other                             9,150     11,960 Note 3         5,000      5,461  Note 3
                                 -------- ----------              -------   --------
Total Regulatory Assets          $794,996 $1,186,106              $45,097   $ 54,122
                                 ======== ==========              =======   ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $117,686 $ 122,892  Note 4      $21,510   $ 22,781   Note 4
   Deferred Fuel Costs             69,026    52,572  Note 5
   Texas Retail Clawback           51,926      -     Note 5       14,328       -      Note 5

  Over - Recovery of
   Transition Changes              20,870      -      Jan. 2016
  Purchased Power Conservation      9,560      -      Note 1
  Excess Earnings                  46,111     62,852  Note 5      17,419     17,300   Note 4
  Ammounts Due To Customers
   For Future Income Taxes                                        12,280     13,591   Note 1
  Other                                 6          6  Note 3       7,285      5,775   Note 3
                                 -------- ----------             -------   --------
Total Regulatory Liabilities     $315,185 $  238,322             $72,822   $ 59,447
                                 ======== ==========             =======   ========

</TABLE>

Note 1: This amount fluctuates from month to month or year to year and has no
fixed recovery/refund 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/refund periods. Note 4: Generally amortized over the life
of the related plant assets as approved by the various state commissions. Note
5: Includable in TCC's and TNC's PUCT 2004 true-up proceedings. See "Texas
Restructuring" section of Note 8.


8. Customer Choice and Industry
    Restructuring:

Customer choice allowing retail customers to select alternative generation
suppliers began on January 1, 2001 in Ohio and on January 1, 2002 in Michigan,
Virginia and in the ERCOT area of Texas. Customer choice in the SPP area of
Texas, also scheduled to begin on January 1, 2002, was delayed by the PUCT.
AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.

Implementation of legislation enacted in Arkansas, Oklahoma and West Virginia to
allow retail customers to choose their electricity supplier has been delayed or
repealed. In 2001, Oklahoma delayed implementation of customer choice
indefinitely. In February 2003, the Arkansas General Assembly passed legislation
that repealed customer choice legislation, which is currently awaiting signature
by the Govenor of Arkansas. Before West Virginia's choice plan can be effective,
tax legislation must be passed to continue consistent funding for state and
local governments. No further legislation has been introduced related to
restructuring in West Virginia.

In general, state restructuring legislation provides for a transition from
cost-based rate regulated bundled electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier.

Ohio Restructuring - Affecting AEP, CSPCo and OPCo

Customer choice of electricity supplier and restructuring began on January 1,
2001, under the Ohio Act. At January 1, 2003, virtually all customers continue
to receive supply service from CSPCo and OPCo with a legislatively required
residential generation rate reduction of 5%. All customers continue to be served
by CSPCo and OPCo for transmission and distribution services.

The Ohio Act provided for a five-year transition period to move from cost-based
rates to market pricing for electric generation supply services. It granted the
PUCO broad oversight responsibility for promulgation of rules for competitive
retail electric generation service and approval of a transition plan for each
electric utility company, changed the taxation of electric companies and
addressed certain major transition issues including unbundling of rates and the
recovery of stranded costs including regulatory assets and transition costs.

In 1999 CSPCo and OPCo filed transition plans. After negotiations with
interested parties including the PUCO staff, the PUCO approved a stipulation
agreement for CSPCo's and OPCo's transition plans. The approved plans included,
among other things, recovery of generation-related regulatory assets over seven
years for OPCo and over eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and through a wires charge for
the remaining years. At December 31, 2002, the remaining amount of regulatory
assets to be amortized as recovered was $375 million for OPCo and $205 million
for CSPCo.

By provisions of the Ohio Act on May 1, 2001, electric distribution companies
became subject to an excise tax based on KWH sold to Ohio customers. The last
tax year for which Ohio electric utilities paid the excise tax based on gross
receipts was May 1, 2001 through April 30, 2002. As required by law, the gross
receipts tax is paid in advance of the tax year for which the utility exercises
its privilege to conduct business. CSPCo and OPCo treated the tax payment as a
prepaid expense and amortized it to expense during the privilege year.

The stipulation agreement also required the PUCO to consider implementation of a
gross receipts tax credit rider as the parties could not reach an agreement.
Following a hearing on the gross receipts tax issue, the PUCO ordered the gross
receipts tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as
proposed by the companies. On April 3, 2002, the Ohio Supreme Court rejected the
companies' arguments and affirmed the PUCO's order which established the
effective date of tax credit riders in rates. This ruling had no impact on 2002
results of operations as the companies had recorded an extraordinary loss ($30
million for CSPCo and $18 million for OPCo, both amounts net of tax) in 2001.

On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users - Ohio
and American Municipal Power - Ohio filed a complaint with the PUCO alleging
that CSPCo and OPCo have violated the PUCO's orders regarding implementation of
their transition plan and violated other applicable law by failing to
participate in an RTO.

The complainants seek, among other relief, an order from the PUCO suspending
collection of transition charges by CSPCo and OPCo until transfer of control of
their transmission assets has occurred, pricing standard offer electric
generation effective January 1, 2006 at the market price used by the companies
in their 1999 transition plan filings to estimate transition costs and imposing
a $25,000 per company forfeiture for each day AEP fails to comply with its
commitment to transfer control of transmission assets to an RTO.

Due to the FERC's reversal of its previous approval of our RTO filings, CSPCo
and OPCo have been delayed in the implementation of their RTO participation
plans. We continue to pursue integration of CSPCo, OPCo and other AEP East
companies into PJM. In this regard on December 19, 2002, the companies filed an
application with PUCO for approval of the transfer of functional control over
certain of their transmission facilities to PJM. Management is unable to predict
the timing of FERC's final approval of RTOs, the timing of an RTO being
operational or the outcome of these proceedings before the PUCO.

In October 2002, the PUCO initiated an investigation of the financial condition
of Ohio's regulated public utilities. The PUCO's goal is to identify measures
available to the PUCO to ensure that the regulated operations of Ohio's public
utilities are not impacted by adverse financial consequences of parent or
affiliate company unregulated operations and take appropriate corrective action,
if necessary. The utilities and other interested parties were requested to
provide comments and suggestions by November 12, 2002, with reply comments by
November 22, 2002, on the type of information necessary to accomplish the stated
goals, the means to gather the required information from the public utilities
and potential courses of action that the PUCO could take. Management is unable
to predict the outcome of the PUCO's investigation or its impact on results of
operations and business practices, if any.

Virginia Restructuring - Affecting AEP and APCo

In Virginia, choice of electricity supplier for retail customers began on
January 1, 2002 under its restructuring law. Presently, APCo continues to
service all its previous customers under capped rates. A finding by the Virginia
SCC that an effective competitive market exists would be required to end the
transition period prior to its scheduled end on June 30, 2007.

The restructuring law provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate
change request was made by the utility. APCo did not request new rates.
Virginia's restructuring law does not permit the Virginia SCC to change
generation rates during the transition period except for changes in fuel costs,
changes in state gross receipts taxes, or to address financial distress of the
utility.

In July 2002, APCo filed with the Virginia SCC requesting an increase in fuel
rates effective January 1, 2003. A public hearing was held on September 23, 2002
related to this filing. On November 8, 2002, a decision was issued in this
proceeding approving an annual increase of approximately $24 million.

The Virginia restructuring law also required filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. In January 2001 APCo filed its corporate separation plan
and rate unbundling plan with the Virginia SCC. The Virginia SCC approved
settlement agreements that resolved most issues except the assignment of
generation-related regulatory assets among functionally separated generation,
transmission and distribution organizations. The Virginia SCC determined that
generation-related regulatory assets and related amortization expense should be
assigned to APCo's generation function. Presently, capped rates are sufficient
to recover generation-related regulatory assets. Therefore, management
determined that recovery of APCo's generation-related regulatory assets remains
probable. APCo did not and will not collect a wires charge in 2002 or 2003,
respectively. The settlement agreements and related Virginia SCC order addressed
functional separation leaving decisions related to corporate separation for
later consideration.

Texas Restructuring - Affecting AEP, SWEPCo, TCC and TNC

In preparation for the start of competition in Texas, CPL, SWEPCo, and WTU, the
integrated electric utility companies operating in Texas, were required to make
PUCT filings and legal and operational changes to their business. AEP formed new
subsidiaries, Mutual Energy CPL L.P. and Mutual Energy WTU L.P., to act as
retail electric providers (REP) in Texas beginning on January 1, 2002, the
effective date of customer choice in Texas. The CPL and WTU names continued to
be used by the registrant subsidiaries which owned the generation, transmission
and distribution assets located in the ERCOT areas of Texas and WTU's entire
operations in SPP throughout most of 2002. In December 2002, WTU transferred its
SPP retail customers to Mutual Energy SWEPCO L.P. AEP sold the new subsidiaries
that serve ERCOT retail customers to Centrica in December 2002, along with the
Central Power and Light and West Texas Utilities brand names. CPL and WTU
changed their names to AEP Texas Central Company (TCC) and AEP Texas North
Company (TNC), respectively.

On January 1, 2002, customer choice of electricity supplier began in the ERCOT
area of Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a small
portion of TNC's service territory are located in the SPP. TCC operates entirely
in the ERCOT area of Texas.

Texas restructuring legislation, among other things:
o    provides for the recovery of regulatory assets and other stranded costs
     through securitization and non-bypassable wires charges;
o    requires reductions in NOx and sulfur dioxide emissions;
o    provides for an earnings test for each of the years 1999 through 2001 which
     will reduce stranded cost recoveries or if there is no stranded cost,
     provides for a refund or their use to fund certain capital expenditures;
o    requires each utility to structurally unbundle into a retail electric
     provider, a power generation company and a transmission and distribution
     utility;
o    provides for certain limits for ownership and control of generating
     capacity by companies and;
o    provides for a 2004 true-up proceeding to quantify and reconcile the amount
     of stranded costs, final fuel balances, net regulatory assets, certain
     environmental costs, accumulated excess earnings, excess of price-to-beat
     revenues over market prices subject to certain conditions and limitations
     (Retail clawback), and the difference between the price of power obtained
     through the legislatively-mandated capacity auctions and the power costs
     used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and
     other issues.

Under the Texas Legislation, electric utilities were required to submit a plan
to structurally unbundle business activities into a retail electric provider, a
power generation company and a transmission and distribution (T&D) utility. In
2000, SWEPCo, TCC and TNC filed their business separation plans with the PUCT.
The PUCT approved the plans for TCC and TNC but determined that competition in
the SPP areas of Texas should be delayed indefinitely and abated SWEPCo's plan.

Operations for TCC and TNC have been functionally separated consistent with the
approved plans. The delivery of electricity in ERCOT continues to be the
responsibility of TCC and TNC at regulated prices.

Texas Legislation provides electric utilities an opportunity to recover
regulatory assets and stranded costs resulting from the unbundling of the T&D
utility from the generation facilities. Stranded costs are the difference
between regulatory net book value of generation assets and the market value of
the assets based on one of several methodologies authorized by the Texas
Legislation. Stranded costs can be refinanced through securitization (a
financing structure designed to provide lower financing costs than are available
through conventional financings).

In 1999, TCC filed with the PUCT to securitize $1.27 billion of its retail
generation-related regulatory assets and $47 million in other qualified
restructuring costs. The PUCT authorized the issuance of up to $797 million of
securitization bonds ($949 million of generation-related regulatory assets and
$33 million of qualified refinancing costs offset by $185 million of customer
benefits for accumulated deferred income taxes). TCC issued its securitization
bonds in February 2002. The annual cost of the bonds are recovered through a
PUCT approved transition charge in distribution rates.

TCC included regulatory assets not approved for securitization in its request
for recovery of $1.1 billion of stranded costs. The $1.1 billion request
included $800 million of STP costs included in Property, Plant and
Equipment-Electric Production on AEP's Consolidated Balance Sheets. These STP
costs had previously been identified as excess cost over market (ECOM) by the
PUCT for regulatory purposes. They were earning a lower return and being
amortized on an accelerated basis for rate-making purposes.

After hearings on the issue of stranded costs, the PUCT ruled, in October 2001,
that its current estimate of TCC's stranded costs was negative $615 million. TCC
disagreed with the ruling (see discussion of appeal ruling below). The ruling
indicated that TCC's costs were below market after securitization of regulatory
assets. The final amount of TCC's stranded costs including regulatory assets and
ECOM will be established by the PUCT in the 2004 true-up proceeding. If TCC's
total stranded costs determined in the 2004 true-up are less than the amount of
securitized regulatory assets, the PUCT can implement an offsetting credit to
transmission and distribution rates.

The Texas Legislation allows for several alternative methods to be used to value
stranded costs in the final 2004 true-up proceeding including the sale or
exchange of generation assets, stock valuation or the use of an ECOM model.

TCC decided to obtain a market value of generating assets for purposes of
determining stranded costs for the 2004 true-up proceeding and filed a plan of
divestiture with the PUCT, in December 2002, seeking approval of a sales process
for all of its generating facilities. Such sales quantify the actual stranded
costs. The amount of stranded costs under this market valuation methodology will
be the amount by which net book value of TCC's generating assets, including
regulatory assets and liabilities that were not securitized, exceeds the market
value of the generation assets as measured by the net proceeds from the sale of
the assets. It is anticipated that any such sale will result in significant
stranded costs for purposes of the 2004 true-up proceeding. The filing included
a request for the PUCT to issue a declaratory order that TCC's 25% ownership
interest in its nuclear plant, STP, can be sold to value stranded costs.
Intervenors to this proceeding, including the PUCT Staff, have made filings to
dismiss TCC's filing claiming that the PUCT does not have the authority to issue
a declaratory order. The intervenors also argued that the proper time to address
the sales process is after the plants are sold during the 2004 true-up
proceeding. Since the bidding process is not expected to be completed before mid
2004, TCC requested that the 2004 true-up proceeding be scheduled after
completion of the divestiture of the generating assets.

Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) sell at auction in 2002 and 2003 at least 15%
of the PGC's Texas jurisdictional installed generation capacity in order to
promote competitiveness in the wholesale market through increased availability
of generation and liquidity. Actual market power prices received in the state
mandated auctions wil replace the PUCT's earlier estimates of those market
prices used in the ECOM model to calculate the stranded cost for the 2004
true-up proceeding.

The decision to determine stranded costs using market prices, instead of using
the PUCT's ECOM model estimates, enabled TCC to record a $262 million regulatory
asset and related revenues which represents the quantifiable amount of stranded
costs for the year 2002 related to the wholesale prices. Prior to the decision
to pursue a sale of TCC's generating assets, the PUCT's ECOM estimate prohibited
the recognition of the regulatory assets and revenues as there was no way to
quantify stranded costs. As discussed above, a defined process is required in
order to determine the amount of stranded costs related to generation facility
for the 2004 true-up proceedings. TCC's plan of divestiture filed with the PUCT
during December 2002 provided such a process.

When the divestiture and the 2004 true-up processing is completed, TCC will
securitize stranded costs which exceed current securitized amounts. The annual
costs of securitization will be recovered through a non-bypassable rate
surcharge by the regulated T&D utility over the life of the securitization
bonds. Any stranded costs and other true-up amounts not recovered through the
sale of securitization bonds may be recovered through a separate non-bypassable
competitive transition charge to T&D utility customers.

The Texas Legislation provides for an earnings test each year 1999 through 2001
and requires PUCT approval of the annual earnings test calculation.

The PUCT issued final orders for the 1999 earnings test in February 2001 and for
the 2000 earnings test in September 2001. The 1999 excess earnings were none for
SWEPCo, $24 million for TCC and $1 million for TNC. Excess earnings for 2000
were $1 million for SWEPCo, $23 million for TCC and $17 million for TNC.
Adjustments were recorded in results of operations as the orders were received.

The PUCT issued its final order for the 2001 earnings test in December 2002. An
estimate of 2001 excess earnings of $8 million for TCC, $2 million for SWEPCo
and none for TNC had been recorded in 2001. Adjustments to reflect the PUCT
staff's estimate of excess earnings ($2 million for SWEPCo, $0.7 million for TNC
and none for TCC) were recorded prior to September 30, 2002. The PUCT's final
order regarding 2001 excess earnings required only minor adjustments to prior
estimates.

Due to TCC's and TNC's disagreement with the PUCT's final order for the 2000
excess earnings, the companies filed an appeal in district court in 2001 seeking
judicial review of the PUCT's determination of excess earnings. The district
court upheld the PUCT's order and the companies appealed that decision. A ruling
on the appeal is expected in 2003.

On January 28, 2003, the TCC and TNC filed an appeal in District Court seeking
judicial review of the PUCT order for the 2001 excess earnings.

The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of stranded costs authorized by the PUCT to be
securitized. Final stranded cost amounts and the treatment of excess earnings
will be determined in the 2004 true-up proceeding. To the extent that the final
2004 true-up proceeding determines that TCC should recover additional stranded
costs, the additional amount recoverable can also be securitized. The PUCT also
ruled that excess earnings for the period 1999-2001 should be refunded through
distribution rates to the extent of any over-mitigation of stranded costs
represented by negative ECOM. In 2001 the PUCT issued an order requiring TCC to
reduce distribution rates by approximately $54.8 million plus accrued interest
over a five-year period beginning January 1, 2002 in order to return estimated
excess earnings for 1999, 2000 and 2001. Since excess earnings amounts were
expensed in 1999, 2000 and 2001, the order has no additional effect on reported
net income but will reduce cash flows for the five year refund period. The
amount to be refunded is recorded as a regulatory liability.

Management believes that TCC will have stranded costs in 2004. TCC has appealed
the PUCT's refund of excess earnings to the Travis County District Court and,
depending on the outcome of that appeal (and the final outcome of the rulemaking
challenge discussed below), the PUCT may revise the treatment of excess earnings
in the final calculation of the stranded cost balance. In the same appeal, TCC
and certain unaffiliated parties also challenged various elements of the PUCT's
order determining the estimated stranded costs of TCC, with the unaffiliated
parties contending, among other things, that the entire $615 million of negative
stranded costs should be refunded presently. Prior to the Court hearing on this
issue, however, TCC agreed to give up its claims concerning errors in the
calculation of the stranded cost estimate, while the unaffiliated parties agreed
to give up claims that there should be a refund of negative stranded costs. The
Travis County District Court subsequently heard oral arguments concerning the
remaining issues in the appeal, but has not yet issued a decision. The PUCT's
stranded cost estimate that is the subject of this appeal will be superceded by
a final determination of stranded costs to be accomplished as part of the 2004
true-up proceeding.

In a separate appeal challenging the PUCT's substantive rule governing the 2004
true-up proceeding, the Texas Third Court of Appeals ruled in February 2003,
that the Texas Legislation does not contemplate the refunding of negative
stranded costs to customers. The Court of Appeals held that the PUCT was
justified in using any negative stranded cost balance determined in the 2004
true-up proceeding only as an offset to prevent an over-recovery of stranded
costs via securitization. In addition, the Court of Appeals ruled that negative
stranded costs cannot be offset against other true-up balances, including final
under-recovered fuel amounts. This ruling may be further appealed to the Supreme
Court of Texas.

Beginning January 1, 2002, fuel costs are not subject to PUCT fuel
reconciliation proceedings for TCC and TNC's ERCOT retail customers. Due to the
delay of competition for SWEPCo's SPP area of Texas, SWEPCo continues to record
and request recovery of fuel costs subject to Texas fuel proceedings. Final
deferred fuel balances related to ERCOT customers of TCC and TNC at December 31,
2001 will be included in the 2004 true-up proceeding. If the final fuel balances
or any amount incurred but not yet reconciled are not recovered, they could have
a negative impact on results of operations.

Under the Texas Legislation, retail electric providers (REPs) associated with
integrated utilities are required to offer residential and small commercial
customers (with a peak usage of less than 1000 KW) a price-to-beat rate until
January 1, 2007. In December 2001 the PUCT approved price-to-beat rates for the
AEP REPs in TCC's and TNC's ERCOT area. Customers with a peak usage of more than
1000 KW are subject to market rates. The Texas Restructuring Legislation also
provides that a REP associated with integrated utilities may request an
adjustment of its fuel portion of the price-to-beat rate up to two times
annually to reflect changes in market prices of fuel and purchased energy costs
based upon changes in NYMEX gas prices.

As part of the 2004 true-up proceedings the price-to-beat rates charged by AEP
REPs for 2002 and 2003 will be compared to the market rates for the same period.
If market rates are lower, the excess of the price-to-beat, reduced by non-
bypassable delivery charges, over the prevailing market prices must be returned
to the distribution company, subject to a per customer maximum. During 2002, AEP
provided for such potential liabilities at the maximum amount via a charge to
revenues, and recorded a regulatory liability for TCC and TNC. These amounts
were $52 million for TCC and $14 million for TNC.

West Virginia Restructuring - Affecting AEP and APCo

In 2000 the WVPSC issued an order approving an electricity restructuring plan
which the WV Legislature approved by joint resolution. The joint resolution
provides that the WVPSC cannot implement the plan until the legislature makes
tax law changes necessary to preserve the revenues of state and local
governments. Since the WV Legislature has not passed the required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.

A Joint Stipulation approved by the WVPSC in 2000 in connection with a base rate
filing, allowed for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions: o Frozen
transition rates and a wires charge of 0.5 mills per KWH.
o     The retention, as a regulatory liability, on the books of a net cumulative
      deferred ENEC over-recovery balance of $66 million to be used to offset
      the cost of deregulation when generation is deregulated in WV.
o     The retention of net merger savings prior to December 31, 2004
      resulting from the merger of AEP and CSW.
o     A 0.5 mills per KWH wires charge for departing customers provided
      for in the WV Restructuring Plan.

Management expects that the approved Joint Stipulation provides for the recovery
of existing regulatory assets and other stranded costs.

In order for customer choice to become effective in WV, the WV Legislature
needed to enact additional legislation to preserve the revenues of state and
local government. In the subsequent two legislative sessions, which usually end
in March each year, the West Virginia Legislature has not enacted the required
legislation. Due to the lack of legislative activity, the WVPSC closed two
proceedings related to electricity restructuring in the summer of 2002.

The two closed proceedings related to the respective dockets intended originally
to determine whether West Virginia should deregulate the generation business,
and to develop the WVPSC's Deregulation Plan and related rules to implement the
Plan.

Management has reviewed these two proceedings and has concluded that at this
time it is not clear that APCo meets the requirements to reapply SFAS 71.
Management will monitor developments to determine when it is appropriate to
reapply SFAS 71 to APCo's generation business.

Arkansas Restructuring - Affecting AEP and SWEPCo

In 1999, Arkansas enacted legislation to restructure its electric utility
industry.

In February 2003, the Arkansas General Assembly passed legislation that repealed
customer choice legislation, which is currently awaiting signature by the
Governor of Arkansas.

Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC

The enactment of restructuring legislation and the ability to determine
transition rates, wires charges and any resultant gain or loss under
restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia
resulted in AEP and certain subsidiaries discontinuing regulatory accounting
under SFAS 71 for the generation portion of their business in those states.
Under the provisions of SFAS 71, regulatory assets and regulatory liabilities
are recorded to reflect the economic effects of regulation by matching expenses
with related regulated revenues.

The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas,
Virginia and West Virginia resulted in recognition of extraordinary gains or
losses. The discontinuance of SFAS 71 can require the write-off of regulatory
assets and liabilities related to the deregulated operations, unless their
recovery is provided through cost-based regulated rates to be collected in a
portion of operations which continues to be rate regulated. Additionally, a
company must determine if any plant assets are impaired when they discontinue
SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis
showed that there was no accounting impairment of generation assets.

As a result of deregulation of generation, the application of SFAS 71 for the
generation portion of the business in Arkansas, Ohio, Texas, Virginia and West
Virginia was discontinued. Remaining generation-related regulatory assets will
be amortized as they are recovered under terms of transition plans. Management
believes that substantially all generation-related regulatory assets and
stranded costs will be recovered under terms of the transition plans. If future
events including the 2004 true-up proceeding in Texas were to make their
recovery no longer probable, the companies would write-off the portion of such
regulatory assets and stranded costs deemed unrecoverable as a non-cash
extraordinary charge to earnings. If any write-off of regulatory assets or
stranded costs occurred, it could have a material adverse effect on future
results of operations, cash flows and possibly financial condition.

Michigan Restructuring - Affecting AEP and I&M

Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Effective with that date the rates on I&M's Michigan customers' bills for retail
electric service were unbundled to allow customers the opportunity to evaluate
the cost of generation service for comparison with other offers. I&M's total
rates in Michigan remain unchanged and reflect cost of service. At December 31,
2002, none of I&M's customers have elected to change suppliers and no
alternative electric suppliers are registered to compete in I&M's Michigan
service territory.

Management has concluded that as of December 31, 2002 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan continue
to be cost-based regulated.

9. Commitments and Contingencies:

Construction and Other Commitments - Affecting AEP, AEGCo, APCo, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, TCC and TNC

The AEP System has substantial construction commitments to support its
operations. Aggregate construction expenditures for 2003-2005 for consolidated
domestic and foreign operations are estimated to be $4.7 billion.

The following table shows the estimated construction expenditures of the
subsidiary registrants for 2003 - 2005:



                    (in millions)

     AEGCo             $ 70.9
     APCo             1,005.7
     CSPCo              418.9
     I&M                601.5
     KPCo               148.3
     OPCo               733.4
     PSO                262.3
     SWEPCo             351.3
     TCC                419.6
     TNC                130.8

APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the West Virginia Public
Service Commission and the Virginia State Corporation Commission authorizing
construction and operation of the line. On December 31, 2002, the U.S. Forest
Service issued a final environmental impact statement and record of decision to
allow the use of federal lands in the Jefferson National Forest for construction
of a portion of the line. We expect additional state and federal permits to be
issued in the first half of 2003. Through December 31, 2002, we had invested
approximately $51 million in this effort. The line is estimated to cost $287
million including amounts spent to date with completion scheduled in 2006. If
the required permits are not obtained and the line is not constructed, the $51
million investment would be written off adversely affecting future results of
operations and cash flows.

Long-term contracts to acquire fuel for electric generation have been entered
into for various terms, the longest of which extends to the year 2014 for the
AEP System. The expiration date of the longest fuel contract is 2007 for APCo,
2005 for CSPCo, 2007 for I&M, 2005 for KPCo, 2012 for OPCo, 2014 for PSO, 2006
for SWEPCo and 2006 for TNC. The contracts provide for periodic price
adjustments and contain various clauses that would release the subsidiaries from
their obligations under certain force majeure conditions.

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

Power Generation Facility - Affecting AEP and OPCo

AEP has entered into agreements with Katco Funding L.P. (Katco) an unrelated
unconsolidated special purpose entity. Katco has an aggregate financing
commitment of $525 million and a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. Katco was formed to develop, construct, finance and
lease a power generation facility to AEP. Katco will own the power generation
facility and lease it to AEP after construction is completed. The lease will be
accounted for as an operating lease (see Note 22), therefore neither the
facility nor the related obligations are reported on AEP's balance sheet.
Payments under the operating lease are expected to commence in the first quarter
of 2004. AEP will in turn sublease the facility to Dow Chemical Company (DOW),
which will use the energy produced by the facility and sell excess energy. AEP
has agreed to purchase the excess energy from DOW for resale. The use of Katco
allows AEP to limit its risk associated with the power generation facility once
the construction phase has been completed.

AEP is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.

In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.

The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.

As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.

It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.

OPCo has entered into a 30-year power purchase agreement for electricity
produced by an unaffiliated entity's three-unit natural gas fired plant. The
plant was completed in 2002 and the agreement will terminate in 2032. Under the
terms of the agreement, OPCo has the option to run the plant until December 31,
2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at $1.2 million per month.
For the remainder of the 30-year contract term, OPCo will pay the variable costs
to generate the electricity it purchases (up to 20% of the plant's capacity).

Nuclear Plants - Affecting AEP, I&M and TCC

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

Nuclear Incident Liability - Affecting AEP, I&M and TCC

The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $9.5 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear incident payable in annual installments of $20 million. TCC could be
assessed $44 million per nuclear incident payable in annual installments of $5
million as its share of a STPNOC assessment. The number of incidents for which
payments could be required is not limited. Under an industry-wide program
insuring workers at nuclear facilities, I&M and TCC are also obligated for
assessments of up to $6.2 million and $1.6 million, respectively, for potential
claims. These obligations will remain in effect until December 31, 2007.

Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for
property damage, decommissioning and decontamination. Additional insurance
provides coverage for extra costs resulting from a prolonged accidental outage.
I&M and STPNOC utilize an industry mutual insurer for the placement of this
insurance coverage. Participation in this mutual insurer requires a contingent
financial obligation of up to $36 million for I&M and $3 million for TCC which
is assessable if the insurer's financial resources would be inadequate to pay
for losses.

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

SNF Disposal - Affecting AEP, I&M and TCC

Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $224 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2002, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and exceed the liability amount. TCC is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, I&M
and TCC

Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. After expiration of the licenses, Cook Plant is expected to be
decommissioned using the prompt decontamination and dismantlement (DECON)
method. The estimated cost of decommissioning and low level radioactive waste
accumulation disposal costs for Cook Plant ranges from $783 million to $1,481
million in 2000 nondiscounted dollars. The wide range is caused by variables in
assumptions including the estimated length of time SNF may need to be stored at
the plant site subsequent to ceasing operations. This, in turn, depends on
future developments in the federal government's SNF disposal program. Continued
delays in the federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated Cook Plant decommissioning
costs in its three rate-making jurisdictions based on at least the lower end of
the range in the most recent decommissioning study at the time of the last rate
proceeding. The amount recovered in rates for decommissioning the Cook Plant and
deposited in the external fund was $27 million in 2002 and 2001 and $28 million
in 2000.

The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
DECON method. TCC estimates its portion of the costs of decommissioning STP to
be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering
these decommissioning costs through rates based on the service life of STP at a
rate of $8 million per year.

Decommissioning costs recovered from customers are deposited in external trusts.
In 2002 and 2001 I&M deposited in its decommissioning trust an additional $12
million each year related to special regulatory commission approved funding for
decommissioning of the Cook Plant. Trust fund earnings increase the fund assets
and the recorded liability and decrease the amount needed to be recovered from
ratepayers. Decommissioning costs including interest, unrealized gains and
losses and expenses of the trust funds are recorded in Other Operation expense
for Cook Plant. For STP, nuclear decommissioning costs are recorded in Other
Operation expense, interest income of the trusts are recorded in Nonoperating
Income and interest expense of the trust funds are included in Interest Charges.

On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in Other Assets and a corresponding nuclear decommissioning liability
is included in Other Noncurrent Liabilities. On TCC's balance sheets, the
nuclear decommissioning liability of $98 million is included in Electric Utility
Plant-Accumulated Depreciation and Amortization. The decommissioning liability
for both nuclear plants combined totals $719 million and $699 million at
December 31, 2002 and 2001, respectively.

Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo

Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA and a
number of states alleged that AEP System companies and eleven unaffiliated
utilities modified certain units at coal fired generating plants in violation of
the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S.
District Court for the Southern District of Ohio. A separate lawsuit initiated
by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year period.

Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In 2001 the
District Court ruled claims for civil penalties based on activities that
occurred more than five years before the filing date of the complaints cannot be
imposed. There is no time limit on claims for injunctive relief.

Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.

Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
unable to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined by
the Court. In the event the AEP System companies do not prevail, any capital and
operating costs of additional pollution control equipment that may be required
as well as any penalties imposed would adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates and market prices for electricity.

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

NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCC

Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions
in a number of eastern states, including certain states in which the AEP
System's generating plants are located. The NOx Rule has been upheld on appeal.
The compliance date for the NOx Rule is May 31, 2004.

In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under the Clean Air Act. The rule
imposed emissions reduction requirements comparable to the NOx Rule beginning
May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities,
including certain AEP operating companies, petitioned the D.C. Circuit Court to
review the Section 126 Rule.

After review, the D.C. Circuit Court instructed Federal EPA to justify the
methods it used to allocate allowances and project growth for both the NOx Rule
and the Section 126 Rule. AEP subsidiaries and other utilities requested that
the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. In August 2001 the D.C. Circuit Court issued an order tolling
the compliance schedule until Federal EPA responded to the Court's remand. On
April 30, 2002, Federal EPA announced that May 31, 2004 is the compliance date
for the Section 126 Rule. Federal EPA published a notice in the Federal Register
in May 2002 advising that no changes in the growth factors used to set the NOx
budgets were warranted. In June 2002 AEP subsidiaries joined other utilities and
industrial organizations in seeking a review of Federal EPA's action in the D.C.
Circuit Court. This action is pending.

In 2000 the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including SWEPCo and TCC. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.

AEP is installing a variety of emission control technologies to reduce NOx
emissions to comply with the applicable state and Federal NOx requirements. This
includes selective catalytic reduction (SCR) technolocy on certain units and
non-SCR technologies on a larger number of units. During 2001 SCR technology
commenced operations on OPCo's Gavin Plant. Installation of SCR technology on
Amos and Mountaineer plants was completed and commenced operation in May 2002.
Construction of SCR technology at certain other AEP generating units continues.
Non-SCR technologies have been installed and commenced operation on a number of
units across the AEP System and additional units will be equipped with these
technologies.

The AEP NOx compliance plan is a dynamic plan that is continually reviewed and
revised as new information becomes available on the performance of installed
technologies and the cost of planned technologies. Certain compliance steps may
or may not be necessary as a result of this new information. Consequently, the
plan has a range of possible outcomes. Our current estimates indicate that
compliance with the NOx Rule, the Texas Commission on Environmental Quality rule
and the Section 126 Rule could result in required capital expenditures in the
range of $1.3 billion to $2 billion of which $843 million has been spent through
December 31, 2002 for the AEP System. The range of cost estimate reflects the
uncertainty over the need for certain SCR projects. Estimated compliance cost
ranges and amounts spent by registrant subsidiaries at December 31, 2002, are as
follows:

                            Estimated          Amount Spent
                        Compliance Costs
                        ----------------       ------------
                                      (in millions)

AEGCo                         $30 - 198                $  1
APCo                             445                    234
CSPCo                             93                     45
I&M                            42 - 210                   5
KPCo                             163                    135
OPCo                          535 - 864                 387
SWEPCo                            40                     24
TCC                                5                      5

Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the estimates depending upon the
compliance alternatives selected to achieve reductions in NOx emissions. Unless
any capital and operating costs of additional pollution control equipment are
recovered from customers, they will have an adverse effect on results of
operations, cash flows and possibly financial condition.

Merger Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
TCC and TNC

On January 18, 2002, the U.S. Court of Appeals for the District of Columbia
ruled that the SEC failed to prove that the June 15, 2000 merger of AEP with CSW
meets the requirements of the PUHCA and sent the case back to the SEC for
further review. Specifically, the court told the SEC to revisit its conclusion
that the merger met PUHCA requirements that utilities be "physically
interconnected" and confined to a "single area or region."

In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUCHA's single
region requirement because it is now technically possible to centrally control
the output of power plants across many states. In its ruling, the appeals court
said that the SEC failed to support and explain its conclusions that the
integration and single region requirements are satisfied.

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

Enron Bankruptcy -  Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and
its subsidiaries in the bankruptcy proceeding filed by the Enron entities which
are pending in the U.S. Bankruptcy Court for the Southern District of New York.
At the date of Enron's bankruptcy AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1, 2001, we
purchased Houston Pipe Line Company (HPL) from Enron. Various HPL related
contingencies and indemnities remained unsettled at the date of Enron's
bankruptcy. The timing of the resolution of the claims by the Bankruptcy Court
is not certain.

In connection with the 2001 acquisition of HPL, we acquired exclusive rights to
use and operate the underground Bammel gas storage facility pursuant to an
agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
exclusive right to use the referenced facility is for a term of 30 years, with a
renewal right for another 20 years and includes the use of the Bammel storage
reservoir and the related compression, treating and delivery systems. We have
engaged in preliminary discussions with Enron concerning the possible purchase
of the residual interest held by Enron in the Bammel storage facility and the
possible resolution of outstanding issues between AEP and Enron relating to our
acquisition of its interest in the Bammel storage facility. We are unable to
predict whether these discussions will lead to an agreement on these subjects.
If these discussions do not lead to an agreement, there may be a dispute with
Enron concerning our ability to continue utilization of the Bammel storage
facility under the existing agreement.

We also entered into an agreement with BAM Lease Company which grants HPL the
right to use approximately 65 billion cubic feet of cushion gas (or pad gas)
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet of the
gas, had entered into a financing arrangement in 1997 with Enron and a group of
banks. These banks purported to have certain rights to the gas in certain events
of default. In connection with AEP's acquisition of HPL, the banks entered into
an agreement granting HPL's use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was thereafter
informed by the banks of a purported default by Enron under the terms of the
referenced financing arrangement. In July 2002 the banks filed a lawsuit against
HPL seeking a declaratory judgment that they have a valid and enforceable
security interest in this cushion gas which would permit them to cause the
withdrawal of this gas from the storage facility. In September 2002 HPL filed a
general denial and certain counterclaims against the banks. Management is unable
to predict the outcome of this lawsuit or its impact on results of operations
and cash flows.

In 2001 AEP expensed $47 million ($31 million net of tax) for our estimated loss
from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million for a
cumulative loss of $53 million ($34 million net of tax). The amounts for certain
subsidiary registrants were:

                                                     Amounts
                                 Amounts              Net of
Registrant                      Expensed               Tax
                                --------              -----
                                           (in millions)

APCo                              $5.3                $3.4
CSPCo                              2.7                 1.8
I&M                                2.8                 1.8
KPCo                               1.1                 0.7
OPCo                               3.6                 2.3

The additional 2002 expense did not materially change the cumulative expense per
registrant subsidiary. The amounts expensed were based on an analysis of
contracts where AEP and Enron entities are counterparties, the offsetting of
receivables and payables, the application of deposits from Enron entities and
management's analysis of the HPL related purchase contingencies and
indemnifications.

Enron has recently instituted proceedings against other energy trading
counter-parties challenging the practice of utilizing offsetting receivables and
payables and related collateral across various Enron entities. We believe that
we have the right to utilize similar procedures in dealing with payables,
receivables and collateral with Enron entities by offsetting approximately $110
million of trading payables owed to various Enron entities against trading
receivables due to us. We believe we have legal defenses to any challenge that
may be made to the utilization of such offsets but at this time are unable to
predict the ultimate resolution of this issue.

Shareholder Lawsuits - Affecting AEP

In the fourth quarter of 2002 lawsuits alleging securities law violations and
seeking class action certification were filed in federal District Court,
Columbus, Ohio against AEP, certain AEP executives, and in some of the lawsuits,
members of the AEP Board of Directors and certain investment banking firms. The
lawsuits claim that AEP failed to disclose that alleged "round trip" trades
resulted in an overstatement of revenues, that AEP failed to disclose that AEP
traders falsely reported energy prices to trade publications that published gas
price indices and that AEP failed to disclose that it did not have in place
sufficient management controls to prevent round trip trades or false reporting
of energy prices. The plaintiffs seek recovery of an unstated amount of
compensatory damages, attorney fees and costs. The cases are presently pending a
decision by the Court on competing motions by certain plaintiffs and groups of
plaintiffs' for designation as lead plaintiff. Once the Court selects a lead
plaintiff, that lead plaintiff will file an amended complaint. AEP intends to
vigorously defend against these actions. Also in the fourth quarter of 2002, two
shareholder derivative actions were filed in state court in Columbus, Ohio
against AEP and its Board of Directors alleging a breach of fiduciary duty for
failure to establish and maintain adequate internal controls over AEP's gas
trading operations; and, a lawsuit was filed against AEP, certain AEP executives
and AEP's ERISA Plan Administrator in federal District Court for the Southern
District of New York (subsequently transferred to federal District Court in
Columbus, Ohio) alleging violations of the Employee Retirement Income Security
Act in the selection of AEP stock as a investment alternative and in the
allocation of assets to AEP stock. These cases are in the initial pleading
stage. AEP intends to vigorously defend against these actions.

California Lawsuit - Affecting AEP

In November 2002, Cruz Bustamante, Lieutenant Governor of California, filed a
lawsuit in Los Angeles County, California Superior Court against forty energy
companies including AEP and two publishing companies alleging violations of
California law through alleged fraudulent reporting of false natural gas price
and volume information with an intent to affect the market price of natural gas
and electricity. This case is in the initial pleading stage. AEP intends to
vigorously defend against this action.

Arbitration of Williams Claim - Affecting AEP

In October 2002, AEP filed its demand for arbitration with the American
Arbitration Association to initiate formal arbitration proceedings in a dispute
with the Williams Companies (Williams). The proceeding results from Williams'
repudiation of its obligations to provide physical power deliveries to AEP and
Williams' failure to provide the monetary security required for natural gas
deliveries by AEP. Consequently, both parties claimed default and terminated all
outstanding natural gas and electric power trading deals among the various
Williams and AEP affiliates. Williams claimed that AEP owes approximately $130
million in connection with the termination and liquidation of all trading deals.
AEP believes it has valid claims arising from Williams' actions and is seeking,
in part, a determination that either no amount is due or that a lesser amount is
due from AEP to Williams (which is fully reserved by AEP) and the extent of any
other damages and legal or equitable relief available. Although management is
unable to predict the outcome of this matter, it is not expected to have a
material impact on results of operations, cash flows or financial condition.

Energy Market Investigations - Affecting AEP

In February 2002, the FERC issued an order directing its Staff to conduct a
fact-finding investigation into whether any entity, including Enron, manipulated
short-term prices in electric energy or natural gas markets in the West or
otherwise exercised undue influence over wholesale prices in the West, for the
period January 1, 2000, forward. In April 2002 AEP furnished certain information
to the FERC in response to their related data request.

Pursuant to the FERC's February order, on May 8, 2002, the FERC issued further
data requests, including requests for admissions, with respect to certain
trading strategies engaged in by Enron and, allegedly, traders of other
companies active in the wholesale electricity and ancillary services markets in
the West, particularly California, during the years 2000 and 2001. This data
request was issued to AEP as part of a group of over 100 entities designated by
the FERC as all sellers of wholesale electricity and/or ancillary services to
the California Independent System Operator and/or the California Power Exchange.

The May 8, 2002 FERC data request required senior management to conduct an
investigation into our trading activities during 2000 and 2001 and to provide an
affidavit as to whether we engaged in certain trading practices that the FERC
characterized in the data request as being potentially manipulative. Senior
management complied with the order and denied our involvement with those trading
practices.

On May 21, 2002, the FERC issued a further data request with respect to this
matter to us and over 100 other market participants requesting information for
the years 2000 and 2001 concerning "wash", "round trip" or "sale/buy back"
trading in the Western System Coordinating Council (WSCC), which involves the
sale of an electricity product to another company together with a simultaneous
purchase of the same product at the same price (collectively, "wash sales").
Similarly, on May 22, 2002, the FERC issued an additional data request with
respect to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas. After reviewing our records, we responded to the FERC
that we did not participate in any "wash sale" transactions involving power or
gas in the relevant market. We further informed the FERC that certain of our
traders did engage in trades on the Intercontinental Exchange, an electronic
electricity trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of the
September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a
"wash sale" but do have certain characteristics in common with such sales. In
response to a request from the California attorney general for a copy of AEP's
responses to the FERC inquires, we provided the pertinent information.

The PUCT also issued similar data requests to AEP and other power marketers. AEP
responded to such data request by the July 2, 2002 response date. The U.S.
Commodity Futures Trading Commission (CFTC) issued a subpoena to us on June 17,
2002 requesting information with respect to "wash sale" trading practices. AEP
responded to CFTC. In addition, the U.S. Department of Justice made a civil
investigation demand to AEP and other electric generating companies concerning
their investigation of the Intercontinental Exchange. AEP has completed a review
of our trading activities in the United States for the last three years
involving sequential trades with the same terms and counterparties. The revenue
from such trading is not material to our financial statements. AEP believes that
substantially all these transactions involve economic substance and risk
transference and do not constitute "wash sales".

In August 2002, AEP received an informal data request from the SEC asking us to
voluntarily provide documents related to "round trip" or "wash" trades. AEP has
provided the requested information to the SEC.

In September 2002, AEP received a subpoena from FERC requesting information
about our natural gas transactions and their potential impact on gas commodity
prices in the New York City area. AEP responded to the subpoena in October 2002.

In October 2002, AEP dismissed several employees involved in natural gas
marketing and trading after the Company determined that they provided inaccurate
price information for use in indexes compiled and published by trade
publications. AEP, subsequently, instituted measures that require all price
information for use in market indexes be verified and reported through AEP's
chief risk officer's organization. AEP has and will continue to provide to the
FERC, the SEC and the CFTC information relating to price data given to energy
industry publications.

FERC Proposed Standard Market Design  - Affecting AEP System

In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, one of the most sweeping rulemaking proposals in its
history. The proposed SMD rule seeks to standardize the structure and operation
of wholesale electricity markets across the country. Key elements of FERC's
proposal include standard rules and processes for all users of the electricity
transmission grid, new transmission rules and policies, and the creation of
certain markets to be operated by independent administrators of the grid in all
regions. The FERC recently indicated that it would issue a white paper on the
proposal in April 2003, in response to the numerous comments FERC received on
its proposal. The FERC is expected to issue its final rule in mid to late 2003.
Because the rule is not yet finalized, management cannot predict the effect of
the final rule on cash flows and results of operations.

FERC Proposed Security Standards - Affecting AEP System

The FERC published for comment its proposed security standards as part of the
SMD. These standards are intended to ensure all market participants have a basic
security program that effectively protects the electric grid and related market
activities. They require compliance by January 1, 2004. The impact of these
proposed standards is far-reaching and includes significant penalties for
non-compliance. These standards apply to market operations and transmission
owners. For the AEP System this includes: power generation plants, transmission
systems, distribution systems and related areas of business. FERC is considering
new proposals to modify the scope and timetable for compliance with the
standards. Unless FERC changes the scope and timing of the original proposed
standards, those standards could result in significant expenditures and
operational changes in a compressed time frame, and may adversely affect results
of operations and cash flows if such costs are not recovered from customers.

FERC Market Power Mitigation  - Affecting AEP System

A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. No such
conference has been held and management is unable to predict the timing of any
further action by the FERC or its affect on future results of operations and
cash flows.

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

10. Guarantees:

In November 2002, the FASB issued FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" (FIN 45) which clarifies the accounting to
recognize a liability related to issuing a guarantee, as well as additional
disclosures of guarantees. This new guidance is an interpretation of SFAS 5, 57,
and 107 and a rescission of FIN 34. The initial recognition and initial
measurement provisions of FIN 45 is effective on a prospective basis to
guarantees issued or modified after December 31, 2002. The disclosure
requirements of FIN 45 are effective for financial statements of interim or
annual periods ending after December 15, 2002.

There are no liabilities recorded for all of the guarantees described below in
accordance with FIN 45 as these guarantees were entered into prior to December
31, 2002. There is no collateral held in relation to these guarantees and there
is no recourse to third parties in the event these guarantees are drawn.

Certain AEP subsidiaries have entered into standby letters of credit (LOC) with
third parties. These LOCs cover gas and electricity trading contracts,
construction contracts, insurance programs, security deposits, debt service
reserves, drilling funds and credit enhancements for issued bonds. All of these
LOCs were issued at a subsidiary level of AEP in the subsidiaries' ordinary
course of business. TCC issued one of the LOCs for credit enhancement of issued
bonds. The maximum future payments of all the LOCs are approximately $166
million with maturities ranging from January 2003 to December 2007. TCC's LOC
was for $40.9 million with a maturity date of November 2003. Since AEP is the
parent to all these subsidiaries, it holds all assets of the subsidiary as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.

The following AEP subsidiaries have entered into guarantees of third parties
obligations:

CSW Energy and CSW International have guaranteed 50% of the required debt
service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a
50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve
as a part of financing. In the event that Sweeny does not make the required debt
payments, CSW Energy and CSW International have a maximum future payment
exposure of approximately $3.7 million, which expires June 2020.

Additionally, CSW guaranteed 50% of the required debt service reserve for Polk
Power Partners, another IPP of which CSW Energy owns 50%. In the event that Polk
Power does not make the required debt payments, CSW has a maximum future payment
exposure of approximately $4.7 million, which expires July 2010.

In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to
assume the revolving credit agreement, capital lease obligations, and term loan
payments of the mining contractor. In the event the mining contractor defaults
under any of these agreements, SWEPCo's total future maximum payment exposure is
approximately $74 million with maturity dates ranging from April 2003 to
February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At December 31, 2002 the cost to reclaim the mine is estimated to
be approximately $36 million. This guarantee ends upon depletion of reserves
estimated at 2035 plus 6 years to complete reclamation.

In connection with the ability for Mutual Energy CPL L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002) to compete in the CPL territory and
to secure transition charges, AEP provided a guarantee that AEP would pay
transition charges if Mutual Energy CPL failed to meet certain obligations. At
the time of sale this guarantee (matures in February 2003) was not revoked. The
future maximum payment exposure is $12.2 million. In February 2003, the
guarantee matured and no payments under the guarantee were required.

In connection with the ERCOT transmission congestion auction, AEP has guaranteed
the obligations of Mutual Energy CPL L.P. (former subsidiary of AEP sold to
Centrica on December 23, 2002) and Mutual Energy WTU L.P. (former subsidiary of
AEP sold to Centrica on December 23, 2002). At the time of sale these guarantees
were not revoked. The total future maximum payment exposure for both companies
is approximately $0.6 million. In January 2003 these guarantees matured and no
payments under the guarantees were required.

See Note 26 "Minority Interest in Finance Subsidiary" for disclosure for the
guaranteed support of AEP for Caddis Partners, LLC.

AEP and all its registrant and non-registrant subsidiaries enter into several
types of contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease agreements,
purchase agreements and financing agreements. Generally these agreements may
include, but are not limited to, indemnifications around certain tax,
contractual and environmental matters. At this time AEP cannot estimate the
maximum potential payment for any of these indemnifications due to the
uncertainty of future events. In addition, as of December 31, 2002, there are no
liabilities required for any indemnifications.

AEP and its regulated and non-regulated subsidiaries lease certain equipment
under a master operating lease. Under the lease agreement, the lessor is
guaranteed to receive up to 87% of the unamortized balance of the equipment at
the end of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have committed to
pay the difference between the fair market value and the unamortized balance,
with the total guarantee not to exceed 87% of the unamortized balance. At
December 31, 2002, the maximum potential loss for these lease agreements was
approximately $50 million assuming the fair market value of the equipment is
zero at the end of the lease term. The maximum potential loss by registrant is
as follows:


Registrant                     Maximum Potential Loss
- ----------                     ----------------------
                                    (in millions)

APCo                                  $ 0.7
CSPCo                                   0.8
I&M                                     2.0
KPCo                                    -
OPCo                                    0.7
PSO                                     3.3
SWEPCo                                  3.4
TCC                                     6.7
TNC                                     2.5
Other AEP non-registrant
  Subsidiaries                         29.9
                                      -----

Total                                 $50.0
                                      =====

11. Sustained Earnings Improvement Initiative:

In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. Of this amount, AEP paid $9.5 million to these terminated employees in the
fourth quarter of 2002. The termination benefits expense was classified as
Maintenance and Other Operation expense on AEP's Consolidated Statements of
Operations and as Other Operation expense on the other registrant's statements
of operations. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits".
The following table shows the staff reductions, termination benefits expense and
the remaining termination benefits expense accrual as of December 31, 2002:




                     Total                          Total
                    Number         Total        Termination
                      of          Expense        Benefits
                  Terminated     Recorded in     Accrued at
                   Employees        2002         12/31/02
                   ---------     ---------      -----------
                               (in millions)   (in millions)

AEGCo                    -          $ 0.3           $ 0.3
APCo                    93           13.1            12.2
CSPCo                   19            5.0             4.5
I&M                    146           15.0            13.1
KPCo                    16            2.6             2.5
OPCo                    33            7.5             7.1
PSO                     17            3.1             3.0
SWEPCo                   8            3.3             3.1
TCC                     37            6.0             5.5
TNC                     20            2.0             1.6
Other AEP
 Subsidiaries          731           17.5            13.0
                     -----          -----           -----
  Totals             1,120          $75.4           $65.9
                     =====          =====           =====

Approximately $48 million of severance expense associated with 701 AEP Service
Corporation employees (included in the 731 figure above) was allocated among all
AEP subsidiaries. AEGCo has no employees but receives allocated expenses.

In addition, certain buildings and corporate aircraft are being sold in an
effort to reduce ongoing operating expenses.

12. Acquisitions, Dispositions and Discontinued Operations:

Acquisitions

SFAS 141 "Business Combinations" applies to all business combinations initiated
and consummated after June 30, 2001.

2002

Acquisition of Nordic Trading
In January 2002 AEP acquired for $2.2 million and other assumed liabilities the
trading operations, including key staff, of Enron's Norway and Sweden-based
energy trading businesses (Nordic Trading). Results of operations are included
in AEP's Consolidated Statements of Operations from the date of acquisition. The
excess of cost over fair value of the net assets acquired was approximately $4.0
million which was recorded as Goodwill. Subsequently in the fourth quarter of
2002, a decision was made to exit the non-core trading business in Europe and to
close or sell Nordic Trading as discussed under the "Discontinued Operations"
section of this note.

Acquisition of USTI
In January 2002, AEP acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both AEP affiliates and
external customers. Results of operations are included in AEP's Consolidated
Statements of Operations from the date of acquisition.

2001

On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe
Line Company and Lodisco LLC for $727 million from Enron. The acquired assets
include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a
gas storage facility and certain gas marketing contracts. The purchase method of
accounting was used to record the acquisition. According to APB Opinion No. 16
"Business Combinations" AEP recorded the assets acquired and liabilities assumed
at their estimated fair values determined by independent appraisal or by
Company's management based on information currently available and on current
assumptions as to future operations. Based on a final purchase price allocation
the excess of cost over fair value of the net assets acquired was approximately
$153 million and is recorded as Goodwill. SFAS 142 "Goodwill and Other
Intangible Assets" treats goodwill as a non-amortized, non-wasting asset
effective January 1, 2002. Therefore, Goodwill was amortized for only seven
months in 2001 on a straight-line basis over 30 years. The purchase method
results in the assets, liabilities and earnings of the acquired operations being
included in AEP's consolidated financial statements from the purchase date.

AEP also purchased the following assets or acquired the following businesses
from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651
million:
o        SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining operations
         and assumed the existing mine reclamation liabilities at its jointly
         owned lignite reserves in Louisiana.
o        Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
         also assumed additional liabilities of approximately $58 million. The
         acquisition includes property, coal reserves, mining operations and
         royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West
         Virginia. AEP continues to operate the mines and facilities which
         employ over 800 individuals. See Note 13b "Asset Impairments and
         Investment Value Losses".
o        MEMCO Barge Line added 1,200 hopper barges and 30 towboats to AEP's
         existing barging fleet. MEMCO's 450 employees operate the barge line.
         MEMCO added major barging operations on the Mississippi and Ohio rivers
         to AEP's barging operations on the Ohio and Kanawha rivers.
o        U.K. Generation added 4,000 megawatts of coal-fired generation from
         Fiddler's Ferry, a four-unit, 2,000-megawatt station on the River
         Mersey in northwest England, approximately 200 miles from London and
         Ferrybridge, a four-unit, 2,000-megawatt station on the River Aire in
         northeast England, approximately 200 miles from London and related coal
         stocks. See Note 13b "Asset Impairments and Investment Value Losses".
o        A 20% equity interest in Caiua, a Brazilian electric operating company
         which is a subsidiary of Vale. See Note 21, "Power and Distribution
         Projects". AEP converted a total of $66 million on an existing loan and
         accrued interest on that loan into Caiua equity. See Note 13b "Asset
         Impairments and Investment Value Losses".
o        Indian Mesa Wind Project consisting of 160 megawatts of wind
         generation located near Fort Stockton, Texas.
o        Acquired existing contracts and hired key staff from Enron's
         London-based international coal trading group.

Regarding the 2002 and 2001 acquisitions, management has recorded the assets
acquired and liabilities assumed at their estimated fair values in accordance
with APB Opinion No. 16 and SFAS 141 as appropriate based on currently available
information and on current assumptions as to future operations.

Dispositions

2002

In 2002, AEP completed a number of disposals of assets determined to be
non-core:

Disposal of SEEBOARD
On June 18, 2002, AEP, through a wholly owned subsidiary, entered into an
agreement, subject to European Union (EU) approval, to sell its consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
AEP received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. In
accordance with SFAS 144 the results of operations of SEEBOARD have been
classified as Discontinued Operations for all years presented. A net loss of $22
million was classified as Discontinued Operations in the second quarter of 2002.
The remaining $323 million of the net loss has been classified as a transitional
impairment loss from the adoption of SFAS 142 (see Notes 2 and 3) and has been
reported as a Cumulative Effect of Accounting Change retroactive to January 1,
2002. A $59 million reduction of the net loss was recognized in the second half
of 2002 to reflect changes in exchange rates to closing, settlement of working
capital true-up and selling expenses. The net total loss recognized on the
disposal of SEEBOARD was $286 million. Proceeds from the sale of SEEBOARD were
used to pay down bank facilities and short-term debt.

The assets and liabilities of SEEBOARD were aggregated on AEP's Consolidated
Balance Sheets as Assets of Discontinued Operations and Liabilities of
Discontinued Operations as of December 31, 2001. The major classes of SEEBOARD's
assets and liabilities of discontinued operations were:


                                               December 31,
                                                  2001
                                               -----------
                                              (in millions)
        Assets:
         Current Assets                           $  324
         Plant,Property and Equipment, Net         1,283
         Goodwill                                  1,129
         Other Assets                                 96
                                                  ------
          Total Assets of Discontinued
           Operations                             $2,832

        Liabilities:
         Current Liabilities                      $  752
         Long-term Debt                              701
         Deferred Income
          Taxes                                      268
         Other Liabilities                            77
                                                  ------
          Total Liabilities of Discontinued
          Operations                              $1,798


Disposal of CitiPower
On July 19, 2002, AEP, through a wholly owned subsidiary entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. AEP completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. AEP recorded a net charge totaling
$125 million as of June 30, 2002. The charge included an impairment loss of $98
million on the remaining carrying value of an intangible asset related to a
distribution license for CitiPower. The remaining $27 million of net loss was
classified as a transitional goodwill impairment loss from the adoption of SFAS
142 (see Notes 2 and 3) and was recorded as a Cumulative Effect of Accounting
Change retroactive to January 1, 2002.

The loss on the sale of CitiPower increased $24 million to $149 million in the
second half of 2002 based on actual closing amounts and exchange rates.

CitiPower's results of operations have been reclassified as Discontinued
Operations in accordance with SFAS 144. The assets and liabilities of CitiPower
have been aggregated on the December 31, 2001, AEP balance sheet as Assets of
Discontinued Operations and Liabilities of Discontinued Operations. The major
classes of CitiPower's assets and liabilities of discontinued operations are:

                                            December 31,   2001
                                            -------------------
                                                (in millions)
   Assets:
    Current Assets                                 $  138
    Plant, Property and
   Equipment, Net                                     495
    Goodwill/Intangibles                              466
    Other Assets                                       23
                                                   ------
     Total Assets of
   Discontinued
      Operations                                   $1,122
                                                   ======


   Liabilities:
    Current Liabilities                       $ 83
    Long-term Debt                             612
    Deferred Income Taxes                       55
    Other Liabilities                           34
                                              ----
     Total Liabilities of    Discontinued
      Operations
                                              $784


Total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD and CitiPower were:

                           SEEBOARD
                         (in millions)
Revenues:

12 months ended
  12/31/02                      $  694
12 months ended
  12/31/01                       1,451
12 months ended
  12/31/00                       1,596

Pretax Profit:

12 months ended
  12/31/02                     $   180
12 months ended
  12/31/01                         104
12 months ended
  12/31/00                          91

                           CitiPower
                         (in millions)
Revenues:

12 months ended
  12/31/02                     $   204
12 months ended
  12/31/01                         350
12 months ended
  12/31/00                         338

Pretax Profit (Loss):

12 months ended
  12/31/02                     $  (190)
12 months ended
  12/31/01                          (4)
12 months ended
  12/31/00                          20

Disposition of Texas REPs

In April 2002, AEP reached a definitive agreement, subject to regulatory
approval, to sell two of its Texas retail electric providers (REPs) to Centrica,
a provider of retail energy and other consumer services. PUCT regulatory
approval for the sale was obtained in December 2002. On December 23, 2002 AEP
sold to Centrica, the general partner interests and the limited partner
interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a base
purchase price paid in cash at closing and certain additional payments,
including a net working capital payment. Centrica paid a base purchase price of
$145.5 million which was based on a fair market value per customer established
by an independent appraiser and an agreed customer count. AEP recorded a net
gain totaling $83.7 million in Other Income. AEP (through TCC and TNC) will
provide Centrica with a power supply contract for the two REPs and back-office
services related to these customers for a two-year period. In addition, AEP
retained the right to share in earnings from the two REPs above a threshold
amount through 2006 in the event the Texas retail market develops increased
earnings opportunities. Under the Texas Legislation, REPs are subject to a
clawback liability if customer change does not attain thresholds required by the
legislation. AEP is responsible for a portion of such liability, if any, for the
period it operated the REPs in the Texas competitive retail market (January 1,
2002 through December 23, 2002). In addition, AEP retained responsibility for
regulatory obligations arising out of operations before closing. AEP's
wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an
up-front payment of approximately $30 million from Centrica associated with the
back-office service agreement, and MESC deferred its right to receive payment of
an additional amount of approximately $9 million to secure certain contingent
obligations. These prepaid service revenues were deferred on the books of MESC
to be amortized over the two-year term of the back office service agreement.

2001

In March 2001, CSWE, a subsidiary company, completed the sale of Frontera, a
generating plant that the FERC required to be divested in connection with the
merger of AEP and CSW. The sale proceeds were $265 million and resulted in an
after tax gain of $46 million.

In July 2001, AEP, through a wholly owned subsidiary, sold its 50% interest in a
120-megawatt generating plant located in Mexico. The sale resulted in an after
tax gain of approximately $11 million.

In July 2001, OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia
and agreed to purchase approximately 34 million tons of coal from the purchaser
of the mines through 2008. The sale is expected to have a nominal impact on the
results of operations and cash flows of OPCo and AEP.

In December 2001, AEP completed the sale of its ownership interests in the
Virginia and West Virginia PCS (personal communications services) Alliances for
stock, resulting in an after tax gain of approximately $7 million. During 2002,
due to decreasing market value of the shares, AEP reduced the value of them to
zero.

2000

In December 2000, AEP, through a wholly owned subsidiary, committed to negotiate
a sale of its 50% investment in Yorkshire, a U.K. electricity supply and
distribution company. As a result a $43 million writedown ($30 million after
tax) was recorded in the fourth quarter of 2000 to reflect the net loss from the
expected sale in the first quarter of 2001. The writedown is included in Other
Income on AEP's Consolidated Statements of Operations. On February 26, 2001 an
agreement to sell the Company's 50% interest in Yorkshire was signed. On April
2, 2001, following the approval of the buyer's shareholders, the sale was
completed without further impact on AEP's consolidated earnings.

In December 2000, CSW International, a subsidiary company sold its investment in
a Chilean electric company for $67 million. A net loss on the sale of $13
million ($9 million after tax) is included in Other Income, and includes $26
million ($17 million net of tax) of losses from foreign exchange rate changes
that were previously reflected in Accumulated Other Comprehensive Income. In the
second quarter of 2000 AEP management determined that the then existing decline
in market value of the shares was other than temporary. As a result the
investment was written down by $33 million ($21 million after tax) in June 2000.
The total loss from both the write down of the Chilean investment to market in
the second quarter and from the sale in the fourth quarter was $46 million ($30
million net of tax).


Discontinued Operations

The operations shown below, affecting AEP, were discontinued or classified as
held for sale in 2002. Results of operations of these businesses have been
reclassified as shown in the following table:

<TABLE>
<CAPTION>


                                SEE-BOARD       CitiPower      Pushan       Eastex        Total
                                ---------       ---------      ------       ------        -----
   (in millions)
<S>                              <C>               <C>           <C>         <C>           <C>
   2002 Revenue                  $   694           $204          $57         $  73         $1,028
   2001 Revenue                    1,451            350           57          -             1,858
   2000 Revenue                    1,596            338           57          -             1,991
   2002 Earnings  (Loss)
   After Tax                          96           (123)          (7)         (156)          (190)
   2001 Earnings
    (Loss) After Tax                  88             (6)           4          -                86
   2000 Earnings  (Loss)
   After Tax                          99             17            7            (1)           122

</TABLE>

13. Asset Impairments and Investment Value Losses:

In 2002 AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.426 billion (consisting of approximately $866.6 million
related to Asset Impairments, $321.1 million related to Investment Value and
Other Impairment Losses, and $238.7 million related to Discontinued Operations)
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, and other factors. These impairments exclude
the transitional impairment loss from adoption of SFAS142 (see Notes 2 and 3).
The categories of impairments included:

                                                  2002 Pre-Tax Estimated Loss
                                                              ----
                                                         (in millions)

        Asset Impairments Held for Sale                   $   483.1
        Asset Impairments Held and Used                       651.4
        Investment Value Losses                               291.9
                                                          ----------

                                Total                      $1,426.4
                                                           ========


a. Assets Held for Sale

In 2002, AEP (and its registrant subsidiaries, as applicable) recorded the
following estimated loss on disposal of assets (including Goodwill) held for
sale:

<TABLE>
<CAPTION>

                                           2002 Pre-Tax
                   Assets                 Estimated Loss
               Held for Sale               on Disposal            Business             Registrant
               -------------               -----------            --------             ----------
                                          (in millions)
<S>                                          <C>                 <C>               <C>
        Eastex                               $218.7              Wholesale                AEP
        Pushan Power                           20.0                 Other                 AEP
                                            -------
        Total Impairment   Losses
          Included in   Discontinued
          Operations                         $238.7
        Telecommunication -   AEPC/C3        $158.5                 Other                 AEP
        Newgulf Facility                       11.8              Wholesale                AEP
        Nordic Trading                          5.3              Wholesale                AEP
        Excess Equipment                       23.9              Wholesale                AEP
        Excess Real Estate                     15.7              Wholesale                AEP
                                           --------
        Total Included in
          Asset  Impairment   Losses         $215.2
        Telecommunications   - AFN          $  13.8                 Other                 AEP
        Water Heater                                                                  AEP, APCo, CSPCo,
          Program                               3.2              Wholesale           I&M, KPCo and OPCo
        Gas Power Systems                      12.2              Wholesale                AEP
                                           --------
        Total Included in
          Investment  Value
          and Other Impairment
          Losses                            $  29.2
                                            -------

        Total-All Held for Sale
          Losses                             $483.1
                                             ======
</TABLE>

Eastex
In 1998, CSW began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, AEP requested that the FERC allow it to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002 AEP solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. A sale of assets is expected to be completed by the end of 2003
with an estimated pre-tax loss on sale of $218.7 million included in
Discontinued Operations in AEP's Consolidated Statements of Operations. The
estimated loss was based on the estimated fair value of the facility and
indicative bids by interested buyers.

Results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 as shown in Note 12. The assets and
liabilities of Eastex have been included on AEP's Consolidated Balance Sheets as
held for sale. The major classes of assets and liabilities held for sale are:

                                                      2002            2001
                                                      ----            ----
                                                          (in millions)
Assets:
Current Assets                                        $15            $  -
Property, Plant and Equipment, Net                     -               217
Other Assets                                           -                 3
                                                   ------           ------
  Total Assets Held for Sale                          $15             $220
                                                      ===             ====

Liabilities:
Current Liabilities                                  $  8           $    5
Other Liabilities                                       4                1
                                                    -----            ------
  Total Liabilities Held for Sale                     $12           $    6
                                                      ===           ======


Pushan Power Plant
In the fourth quarter of 2002, AEP began active negotiations to sell its
interest in the Pushan Power Plant (Pushan) in Nanyang, China to the minority
interest partner. Negotiations are expected to be completed by the second
quarter of 2003 with an estimated pre-tax loss on disposal of $20.0 million,
based on an indicative price expression. The estimated pre-tax loss on disposal
is classified in Discontinued Operations in AEP's Consolidated Statements of
Operations.

Results of operations of Pushan have been reclassified as Discontinued
Operations in accordance with SFAS 144 as discussed in Note 12. The assets and
liabilities of Pushan have been classified on AEP's Consolidated Balance Sheets
as held for sale. The major classes of assets and liabilities held for sale are:

                                                    2002            2001
                                                    ----            ----
                                                        (in millions)
Assets:
Current Assets                                    $  19             $  17
Property, Plant and Equipment, Net                  132               161
                                                  -----             -----
  Total Assets Held for Sale                       $151              $178
                                                   ====              ====

Liabilities:
Current Liabilities                               $  28             $  27
Long-term Debt                                       25                30
Other Liabilities                                    26                24
                                                 ------             -----
  Total Liabilities Held for Sale                 $  79             $  81
                                                  =====             =====

Telecommunications
AEP had developed businesses to provide telecommunication services to businesses
and to other telecommunication companies through broadband fiber optic networks
operated in conjunction with AEP's electric transmission and distribution lines.
The businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN Networks, LLC (AFN), a joint venture. Due to the
difficult economic conditions in these businesses and the overall
telecommunications industry, and other operating problems, the AEP Board
approved in December 2002 a plan to cease operations of these businesses. AEP
took steps to market the assets of the businesses to potential interested buyers
in the fourth quarter of 2002. A number of potential buyers have made offers for
the assets of C3. Potential buyers have indicated interest in the assets of AFN.
A formal offering of the assets of AEPC will begin early in 2003. The complete
sale of all telecommunication assets is expected to be completed by the end of
2003 with an estimated pre-tax impairment loss of $158.5 million (related to
AEPC and C3) classified in Asset Impairments in AEP's Consolidated Statements of
Operations and an estimated pre-tax loss in value of the investment in AFN of
$13.8 million classified in Investment Value and Other Impairment Losses in
AEP's Consolidated Statements of Operations. The estimated losses are based on
indicative bids by potential buyers.

$6 million and $182 million of Property, Plant and Equipment, net of accumulated
depreciation of the telecommunication businesses have been classified on AEP's
Consolidated Balance Sheets as held for sale in 2002 and 2001, respectively.

Newgulf Facility
In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002 AEP began negotiations
with a likely buyer of the facility. A sale is now expected to be completed by
the end of 2003 with an estimated pre-tax loss on sale of $11.8 million based on
an indicative bid by the likely buyer. The estimated loss on disposal is
classified in Asset Impairments on AEP's Consolidated Statements of Operations.
Newgulf's Property, Plant and Equipment, net of accumulated depreciation, of $6
million in 2002 and $17 million in 2001 has been classified on AEP's
Consolidated Balance Sheets as held for sale.


Nordic Trading
In October 2002 AEP announced that its ongoing energy trading operations would
be centered around its generation assets. As a result, AEP took steps to exit
its coal, gas, and electricity trading activities in Europe, except for those
activities necessary to support the U.K. Generation operations. The Nordic
Trading business acquired earlier in 2002 (see Note 12) was made available for
sale to potential buyers. The estimated pre-tax loss on disposal in 2002 of $5.3
million, consisted of impairment of goodwill of $4.0 million (see Note 3) and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments on AEP's Consolidated Statements of Operations.
Management's determination of a zero fair value was based on discussions with a
potential buyer. There are no assets and liabilities of Nordic Trading to be
classified on AEP's Consolidated Balance Sheets as held for sale.

Excess Equipment
In November 2002, as a result of a cancelled development project, AEP obtained
title to a surplus gas turbine generator. AEP has been unsuccessful in finding
potential buyers of the unit, including its own internal generation operators,
due to an over-supply of generation equipment available for sale. Sale of the
turbine is now projected before the end of 2003 with an estimated 2002 pre-tax
loss on disposal of $23.9 million, based on market prices of similar equipment.
The loss is included in Asset Impairments on AEP's Consolidated Statements of
Operations. The Other asset of $12 million in 2002 and $31 million in 2001 has
been classified on AEP's Consolidated Balance Sheets as held for sale.


Excess Real Estate
In the fourth quarter of 2002, AEP began to market an under-utilized office
building in Dallas, TX obtained through the merger with CSW. One prospective
buyer has executed an option to purchase the building. Sale of the facility is
projected by second quarter 2003 and an estimated 2002 pre-tax loss on disposal
of $15.7 million has been recorded, based on the option sale price. The
estimated loss is included in Asset Impairments on AEP's Consolidated Statements
of Operations. The Property asset of $18 million in 2002 and $36 million in 2001
has been classified on AEP's Consolidated Balance Sheets as held for sale.


<PAGE>



Water Heater Program
AEP, APCo, CSPCo, I&M, KPCo and OPCo operated a program to lease electric water
heaters to residential and commercial customers until a decision was reached in
the fourth quarter of 2002 to discontinue the program and to offer the assets
for sale. Negotiations are underway with a qualified buyer, and sale of the
assets is projected by the end of the first quarter of 2003. AEP's estimated
2002 pre-tax loss on disposal of $3.20 million ($50 thousand for APCo, $615
thousand for CSPCo, $643 thousand for I&M, $11 thousand for KPCo, $1.757 million
for OPCo and $126 thousand for other AEP non-registrant subsidiaries) was based
on the expected contract sales price. The loss is included in Investment Value
and Other Impairment Losses on AEP's Consolidated Statements of Operations and
in Nonoperating Expenses on the statements of income of the registrant
subsidiaries. The assets and liabilities have been classified on AEP's
Consolidated Balance Sheets as held for sale. The major classes of assets held
for sale are:

                                                 2002            2001
                                                 ----            ----
                                                     (in millions)
Assets:
Current Assets                                  $  1              $  2
Property, Plant and Equipment, Net                38                48
                                                ----              ----
  Total Assets Held for Sale                     $39               $50
                                                 ===               ===

Gas Power Systems
AEP acquired in 2001 a 75% interest in a startup company seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. The
first quarter of 2002, AEP recognized a goodwill impairment loss of $12.2
million due to technological and operating problems (See Note 3). The loss was
recorded in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations. The fair values of the remaining assets and
liabilities were excluded from AEP's Consolidated Balance Sheets as held for
sale, as the impact was insignificant. AEP's remaining interest was sold in
January 2003.

b. Assets Held and Used

In 2002, AEP recorded the following impairments related to assets (including
Goodwill) held and used to Asset Impairments on AEP's Consolidated Statements of
Operations:


           Assets                                   Business
       Held and Used       2002 Pre-Tax Loss        Segment         Registrant
       -------------       ------------------       -------         ----------
                            (in millions)
U.K. Generation                $548.7               Wholesale          AEP
AEP Coal                         59.9               Wholesale          AEP
Texas Plants                     38.1               Wholesale      AEP and TNC
Ft. Davis Wind Farm
                                  4.7               Wholesale      AEP and TNC
                              -------
      Total - ALL
        Held and Used
        Losses                  $51.4
                                =====

U.K. Generation Plants
In December 2001, AEP acquired two coal-fired generation plants (U.K.
Generation) in the U.K. for a cash payment of $942.3 million and assumption of
certain liabilities. Subsequently and continuing through 2002, wholesale U.K.
electric power prices declined sharply as a result of domestic over-capacity and
static demand. External industry forecasts and AEP's own projections made during
the fourth quarter of 2002 indicate that this situation may extend many years
into the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million, including a goodwill
impairment of $166.1 million as discussed in Note 3. The cash flow analysis used
a discount rate of 6% over the remaining life of the assets and reflected
assumptions for future electricity prices and plant operating costs. This
impairment loss is included in Asset Impairments on AEP's Consolidated
Statements of Operations.

AEP Coal
In October 2001, AEP acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and re-identified as "AEP Coal". During 2002 the coal operations suffered
a decline in forward prices and adverse mining factors that culminated in the
fourth quarter of 2002 and significantly reduced mine productivity and revenue.
Based on an extensive review of economically accessible reserves and other
factors, future mine productivity and production is expected to continue to be
below historical levels. In December 2002, a probability-weighted discounted
cash flow analysis of fair value of the mines was performed which indicated a
2002 pre-tax impairment loss of $59.9 million including a goodwill impairment of
$3.6 million as discussed in Note 3. This impairment loss is included in Asset
Impairments on AEP's Consolidated Statements of Operations.

Texas Plants
In September 2002, AEP proposed closing 16 gas-fired power plants in the ERCOT
control area of Texas (8 TNC plants and 8 TCC plants). ERCOT indicated that it
may designate some of those plants as "reliability must run" (RMR) status. In
October ERCOT designated seven RMR plants (3 TNC plants and 4 TCC plants) and
approved AEP's plan to inactivate nine other plants (5 TNC plants and 4 TCC
plants). The process of moving the plants to inactive status took approximately
two months. Employees of the plants moved to inactive status (approximately 180)
were eligible for severance and outplacement services.

As a result of the decision to inactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments expense during the third quarter 2002 on AEP's and TNC's Statements
of Operations. The decision to inactivate the TCC plants resulted in a
write-down of utility assets of approximately $95.6 million (pre-tax), which was
deferred and recorded in Regulatory Assets during the third quarter 2002 in
AEP's Consolidated Balance Sheets (in Regulatory Assets Designated For or
Subject to Securitization on TCC's Consolidated Balance Sheets).

During the fourth quarter 2002, evaluations continued as to whether assets
remaining at the inactivated plants, including materials, supplies and fuel oil
inventories, could be utilized elsewhere within the AEP System. As a result of
such evaluations, TNC recorded an additional asset impairment charge to Asset
Impairments expense of $3.9 million (pre-tax) in the fourth quarter 2002. In
addition TNC recorded related inventory write-downs of $2.6 million [$1.2
million in Fuel and Purchased Energy: Electricity on AEP (Fuel Expense on TNC)
and $1.4 million in Maintenance and Other Operation expense on AEP (Other
Operation on TNC)]. Similarly, TCC recorded an additional asset impairment
write-down of $6.7 million (pre-tax), which was deferred and recorded in
Regulatory Assets on AEP (in Regulatory Assets Designated For or Subject to
Securitization on TCC's Consolidated Balance Sheets) in the fourth quarter 2002.
TCC also recorded related inventory write-downs of $14.9 million which was
deferred and recorded in Regulatory Assets on AEP (in Regulatory Assets
Designated For or Subject to Securitization on TCC's Consolidated Balance
Sheets) in the fourth quarter 2002.

The total Texas plant asset impairment of $38.1 million in 2002 (all related to
TNC) is included in Asset Impairments on AEP's and TNC's Consolidated Statements
of Operations.

RMR plants are required to ensure the reliability of the power grid, even if
electricity from those plants is not required to meet market needs. ERCOT and
AEP negotiated interim contracts for the seven RMR plants through December 2003,
however, ERCOT has the right to terminate the plants from RMR status upon 90
days written notice.

In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either inactivated or designated as RMR status. See
Texas Restructuring section of the "Customer Choice and Industry Restructuring"
Note 8 for further discussion of the divestiture plan and anticipated timeline.

Ft. Davis Wind Farm
In the 1990's, CSW developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 AEP engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility will be complete by the end of 2003 with an estimated 2002
pre-tax loss on abandonment of $4.7 million. The loss was recorded in Asset
Impairments on AEP's Consolidated Statements of Operations and TNC's Statements
of Operations. The facility will continue to be classified as held and used
until disposal is complete.

c. Investment Values

In 2002, AEP recorded the following declines in fair value on investments
accounted for under APB 18 that were considered to be other than temporarily
impaired as shown in the table below:



            Investment Value
               Impairment           2002 Pre-Tax       Business
               Loss Items          Estimated Loss      Segment       Registrant
               ----------          --------------      -------       ----------
                                   (in millions)

  Grupo Rede Investment - Brazil      $217.0           Other            AEP
  South Coast Power                     63.2           Other            AEP
  Misc. Technology Investments          11.7           Other            AEP
                                      ------
               Total                  $291.9

Grupo Rede Investment
In December 2002, AEP recorded an other than temporary impairment totaling
$141.0 million ($217.0 million net of federal income tax benefit of $76.0
million) of its 44% equity investment in Vale and its 20% equity interest in
Caiua, both Brazilian electric operating companies (referred to as Grupo Rede).
This amount is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations. As of September 30, 2002, AEP had not
recognized its cumulative equity share of operating and foreign currency
translation losses of approximately $88 million and $105 million, respectively,
due to the existence of a put option that permits AEP to require Grupo Rede to
purchase our equity at a minimum price equal to the U.S. dollar equivalent of
the original purchase price. In January 2002 AEP evaluated through an
independent credit assessment the ability of Grupo Rede to fulfill its
responsibilities under the put option and concluded that the carrying value of
the original investment was reasonable.

During 2002, there has been a continuing decline in the Brazilian power industry
and the value of the local currency. Events in the fourth quarter of 2002 led us
to change our view that Grupo Rede would be able to fulfill its responsibilities
under the put option. These events included two downgrades of Caiua debt by
Moody's, resulting in a rating of Caa1. Caiua is an intermediate holding company
which owns substantially all of the utility companies in the Grupo Rede system.
The downgrading of Caiua's credit ratings to a level well below investment grade
casts significant doubt on the ability of Grupo Rede to honor the put option.
Grupo Rede is in the process of restructuring some of its debt s, and as a
condition for participating in the restructuring, during November 2002 a
creditor of Grupo Rede requested that AEP agree not to exercise the put option
prior to March 31, 2007. AEP agreed and in exchange received an extension of the
put option from the previous end date of 2009 through 2019. Based on the factors
noted above, AEP could no longer reasonably believe that our investment could be
recovered, resulting in the recording of the impairment.

South Coast Power Investment
South Coast Power is a 50% owned joint venture that was formed in 1996 to build
and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K..
South Coast Power is subject to the same adverse wholesale electric power rates
described for U.K. Generation above. A December 2002 projected cash flow
estimate of the fair value of the investment indicated a 2002 pre-tax other than
temporary impairment of the equity interest (which included the fair value of
supply contracts held by South Coast Power and accounted for in accordance with
SFAS 133) in the amount of $63.2 million. This loss of investment value is
included in Investment Value and Other Impairment Losses on AEP's Consolidated
Statements of Operations.

Technology Investments
AEP previously made investments totaling $11.7 million in four early-stage or
startup technologies involving pollution control and procurement. An analysis in
December 2002 of the viability of the underlying technologies and the projected
performance of the investee companies indicated that the investments were
unlikely to be recovered, and an other than temporary impairment of the entire
amount of the equity interest under APB 18 was recorded. The loss of investment
value is included in Investment Value and Other Impairment Losses on AEP's
Consolidated Statements of Operations.

14. Benefit Plans:

Pension and Other Postretirement Benefits

In the U.S. AEP sponsors two qualified pension plans and two nonqualified
pension plans. Substantially all employees in the U.S. are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit (OPEB) plans are sponsored by the AEP System to provide
medical and death benefits for retired employees in the U.S.

AEP also has a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. Genco employees participate in their
existing pension plan acquired as part of AEP's purchase of two generation
plants in the U.K. in December 2001.

The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending
December 31, 2002, and a statement of the funded status as of December 31 for
both years:
                                      U.S.                      U.S.
                                  Pension Plans             OPEB Plans
                                  -------------             ----------
                                2002        2001         2002       2001
                                ----        ----         ----       ----
                                              (in millions)
Reconciliation of Benefit
 Obligation:
Obligation at January 1        $3,292      $3,161       $ 1,645     $1,668
Service Cost                       72          69            34         30
Interest Cost                     241         232           114        114
Participant Contributions        -           -               13          8
Plan Amendments                    (2)       -             -             7  (a)
Actuarial (Gain) Loss             258         121           152        192
Divestitures                     -           -             -          (287) (b)
Benefit Payments                 (278)       (291)          (81)       (88)
Curtailments                     -           -             -             1
                               ------      ------       -------     ------
Obligation at December 31      $3,583      $3,292       $ 1,877     $1,645
                               ======      ======       =======     ======

Reconciliation of Fair Value
 of Plan Assets:
Fair Value of Plan Assets at
 January 1                     $3,438      $3,911       $   711     $  704
Actual Return on Plan Assets     (371)       (182)          (57)       (31)
Company Contributions               6        -              137        118
Participant Contributions           -        -               13          8
Benefit Payments                 (278)       (291)          (81)       (88)
                               ------      ------       -------     ------
Fair Value of Plan Assets at
 December 31                   $2,795      $3,438       $   723     $  711
                               ======      ======       =======     ======

Funded Status:
Funded Status at December 31   $ (788)     $  146       $(1,154)    $ (934)
Unrecognized Net Transition
 (Asset) Obligation                (7)        (15)          233        263
Unrecognized Prior-Service Cost   (13)        (12)            6          7
Unrecognized Actuarial
 (Gain) Loss                    1,020          35           896        649
                               ------      ------       -------     ------
Prepaid Benefit (Accrued
 Liability)                    $  212      $  154       $   (19)    $  (15)
                               ======      ======       =======     ======

(a) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line.
(b) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company
and Windsor Coal Company.


The following table provides the amounts for prepaid benefit costs and accrued
benefit liability recognized in the Consolidated Balance Sheets as of December
31 of both years. The amounts for additional minimum liability, intangible asset
and Accumulated Other Comprehensive Income for 2001 and 2002 were recorded in
2002.
                                      U.S.                    U.S.
                                  Pension Plans            OPEB Plans
                                  -------------            ----------
                                2002        2001        2002        2001
                                ----        ----        ----        ----
                                             (in millions)

Prepaid Benefit Costs           $ 255       $ 205       $ -         $   1
Accrued Benefit Liability         (44)        (51)       (19)         (16)
Additional Minimum Liability     (944)        (15)       N/A          N/A
Intangible Asset                   45           9        N/A          N/A
Accumulated Other
 Comprehensive Income             900           6        N/A          N/A
                                -----       -----       ----        ------
Net Asset (Liability)           $ 212       $ 154       $(19)       $ (15)
                                =====       =====       ====        =====

Other Comprehensive (Income)
 Expense Attributable to
 Change in Additional Pension
 Liability Recognition          $ 894         $(4)       N/A          N/A
                                =====         ===       ====        ======

N/A = Not Applicable

The value of our qualified plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The qualified plans
paid $272 million in benefits to plan participants during 2002 (nonqualified
plans paid $6 million in benefits). The investment returns and declining
discount rates have changed the status of our qualified plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
qualified plans currently being underfunded, the Company recorded a charge to
Other Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax
Asset of $315 million, offset by a Minimum Pension Liability of $662 million and
reduction to prepaid costs and intangible assets of $238 million. The charge to
OCI does not affect earnings or cash flow. The OCI charge for each AEP
subsidiary registrant is recorded in Minimum Pension Liability in the respective
registrant's Consolidated Statements of Comprehensive Income. Also, because of
the recent reductions in the funded status of our qualified plans, we expect to
make cash contributions to our qualified plans of approximately $66 million in
2003 increasing to approximately $108 million per year by 2005.

The AEP System's qualified pension plans had accumulated benefit obligations in
excess of plan assets of $661 million at December 31, 2002.

The AEP System's nonqualified pension plans had accumulated benefit obligations
in excess of plan assets of $72 million at December 31, 2002 and $66 million at
December 31, 2001. There are no assets in the nonqualified plans.

The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $1,154 million and $934 million at December 31, 2002 and 2001,
respectively.

The Genco pension plan had $7 million and $10 million at December 31, 2002 and
2001, respectively, of accumulated benefit obligations in excess of plan assets.



The following table provides the components of AEP's net periodic benefit cost
(credit) for the plans for fiscal years 2002, 2001 and 2000:

                                         U.S.                      U.S.
                                     Pension Plans             OPEB Plans
                                     -------------             ----------
                                 2002   2001   2000        2002    2001   2000
                                 ----   ----   ----        ----    ----   ----
                                                 (in millions)

Service Cost                    $  72  $  69   $  60       $ 34    $ 30   $ 29
Interest Cost                     241    232     227        114     114    106
Expected Return on Plan Assets   (337)  (338)   (321)       (62)    (61)   (57)
Amortization of
 Transition (Asset) Obligation     (9)    (8)     (8)        29      30     41
Amortization of Prior-service
 Cost                              (1)    -       13         -       -      -
Amortization of Net Actuarial
 (Gain) Loss                      (10)   (24)    (39)        27      18      4
                                 ----  -----   -----       ----    ----   ----
Net Periodic Benefit Cost
 (Credit)                         (44)   (69)    (68)       142     131    123
Curtailment Loss (a)               -      -      -           -        1     79
                                 ----  -----   -----       ----    ----   ----
Net Periodic Benefit
 Cost (Credit) After
 Curtailments                   $ (44) $ (69)  $ (68)      $142    $132   $202
                                =====  =====   =====       ====    ====   ====

(a) Curtailment  charges were recognized during 2000 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 and other non-registrant subsidiaries for
fiscal years 2002, 2001 and 2000:

<TABLE>
<CAPTION>

                                         U.S.                          U.S.
                                    Pension Plans                   OPEB Plans
                                    -------------                   ----------
                              2002      2001      2000     2002      2001      2000
                              ----      ----      ----     ----      ----      ----
                                                  (in thousands)
<S>                       <C>         <C>       <C>       <C>       <C>       <C>
APCo                      $ (9,988)   $(13,645) $(14,047) $ 25,107  $ 22,810  $ 22,139
CSPCo                       (8,328)    (10,624)  (10,905)   11,494    10,328     9,643
I&M                         (4,206)     (7,805)   (8,565)   17,608    15,077    14,155
KPCo                        (1,406)     (1,922)   (2,075)    2,986     2,438     2,364
OPCo                       (11,360)    (14,879)  (15,041)   22,608    34,444   116,205
PSO                         (3,819)     (2,480)   (2,196)    8,436     6,187     4,277
SWEPCo                      (2,245)     (3,051)   (2,606)    8,371     6,399     4,152
TCC                         (4,786)     (3,411)   (2,986)   10,733     8,214     6,656
TNC                         (1,104)     (1,644)   (1,585)    4,798     3,729     2,929
Other Non-Registrant
  Subsidiaries               3,657      (9,139)   (7,546)   29,722    22,278    19,798
                          --------    --------  --------  --------  --------  --------
Total                     $(43,585)   $(68,600) $(67,552) $141,863  $131,904  $202,318
                          ========    ========  ========  ========  ========  ========

</TABLE>

The weighted-average assumptions as of December 31, used in the measurement of
AEP's benefit obligations are shown in the following tables:

                                 U.S.                     U.S.
                             Pension Plans             OPEB Plans
                             -------------             ----------
                        2002    2001    2000       2002   2001    2000
                        ----    ----    ----       ----   ----    ----
                          %       %        %        %       %       %
 Discount Rate          6.75    7.25     7.50     6.75    7.25    7.50
 Expected Return on
  Plan Assets           9.00    9.00     9.00     8.75    8.75    8.75
 Rate of Compensation
  Increase              3.7     3.7      3.2      N/A     N/A     N/A



In determining the discount rate in the calculation of future pension
obligations we review the interest rates of long-term bonds that receive one of
the two highest ratings given by a recognized rating agency. As a result of a
decrease in this benchmark rate during 2002, we determined that a decrease in
our discount rate from 7.25% at December 31, 2001 to 6.75% at December 31, 2002
was appropriate.

For OPEB measurement purposes, a 10% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2003. The rate was assumed
to decrease gradually each year to a rate of 5% through 2008 and remain at that
level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:

                                  1% Increase     1% Decrease
                                  -----------     -----------
                                         (in millions)
Effect on total  service
 and interest cost
 components of  net
 periodic postretirement
 health care benefit cost              $ 21          $ (17)

Effect on the health care
 component of the
 accumulated
 postretirement
 benefit obligation                     237          (193)

AEP Savings Plans

AEP sponsors various defined contribution retirement savings plans eligible to
substantially all non-United Mine Workers of America (UMWA) U.S. employees.
These plans include features under Section 401(k) of the Internal Revenue Code
and provide for company matching contributions. Beginning in 2001, AEP's
contributions to the two largest plans increased to 75 cents for every dollar of
the first 6% of eligible employee compensation from the previous rate of 50
cents. The cost for contributions to these plans totaled $60.1 million in 2002,
$55.6 million in 2001 and $36.8 million in 2000.

The following table provides the cost for contributions to the savings plans by
the following AEP registrant and other non-registrant subsidiaries for fiscal
years 2002, 2001 and 2000:

                          2002         2001           2000
                          ----         ----           ----


                                   (in thousands)

APCo                   $ 6,722          $7,031        $ 3,988
CSPCo                    2,784           2,789          1,638
I&M                      8,039           7,833          4,231
KPCo                     1,043           1,016            544
OPCo                     5,785           6,398          3,713
PSO                      2,260           2,235          2,306
SWEPCo                   2,765           2,776          2,880
TCC                      3,054           3,046          3,161
TNC                      1,574           1,558          1,708
Other Non-
  Registrant
  Subsidiaries          26,094          20,869         12,677
                       -------         -------         ------
   Total               $60,120         $55,551        $36,846
                       =======         =======        =======

On January 1, 2003, the two major AEP Savings Plans merged into a single plan.

Other UMWA Benefits

AEP and OPCo provide UMWA pension, health and welfare benefits for certain
unionized mining employees, retirees, and their survivors who meet eligibility
requirements. The benefits are administered by UMWA trustees and contributions
are made to their trust funds. Contributions are expensed as paid as part of the
cost of active mining operations and were not material in 2002, 2001 and 2000.
In July 2001, OPCo sold certain coal mines in Ohio and West Virginia.



15. Stock-Based Compensation:

The American Electric Power System 2000 Long-Term Incentive Plan (the Plan) was
approved by shareholders at AEP's annual meeting in 2000 and authorizes the use
of 15,700,000 shares of AEP common stock for various types of stock-based
compensation awards, including stock option awards, to key employees. The Plan
was adopted in 2000.

Under the Plan, the exercise price of all stock option grants must equal or
exceed the market price of AEP's common stock on the date of grant. AEP
generally grants options that have a ten-year life and vest, subject to the
participant's continued employment, in approximately equal 1/3 increments on
January 1st following the first, second and third anniversary of the grant date.

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


<PAGE>



A summary of AEP stock option transactions in fiscal periods 2002, 2001 and
2000 is as follows:

<TABLE>
<CAPTION>


                               2002                    2001                    2000
                               ----                    ----                    ----
                                   Weighted                Weighted                Weighted
                                   Average                 Average                 Average
                        Options    Exercise     Options    Exercise     Options    Exercise
                    (in thousands)  Price   (in thousands)  Price   (in thousands)  Price
<S>                      <C>         <C>        <C>          <C>         <C>         <C>
Outstanding at
 beginning of year       6,822       $37        6,610        $36           825       $40
  Granted                2,923       $27          645        $45         6,046       $36
  Exercised               (600)      $36         (216)       $38           (26)      $36
  Forfeited               (358)      $41         (217)       $37          (235)      $39
                         -----                  -----                    -----
Outstanding at
 end of year             8,787       $34        6,822        $37         6,610       $36
                         =====                  =====                    =====

Options exercisable
 at end of year          2,481       $36          395        $43           588       $41
                         =====                    ===                      ===

Weighted average Exercise price of options:
 -Granted above Market Price         $27                     N/A                     N/A
 -Granted at Market Price            $27                     $45                     $36


</TABLE>



The following table summarizes information about AEP stock options outstanding
at December 31, 2002:

             Options Outstanding
- ----------------------------------------------

Range of
Exercise          Number    Life in  Exercise
Prices          Outstanding  Years     Price
- ---------------------------------------------
$27.06-35.625    8,047,058    8.4    $ 32.54
 40.69-49.00       739,483    7.1      44.84
- ---------------------------------------------
$27.06-49.00     8,786,541    8.3    $ 33.58
- ---------------------------------------------

             Options Exercisable

Range of
Exercise           Number    Weighted-Average
Prices           Outstanding  Exercise Price

$27.06-35.625     2,230,000       $35.51
 40.69-49.00        251,327        43.66
- ---------------------------------------------
$27.06-49.00      2,481,327       $36.33
- ---------------------------------------------

If compensation expense for stock options had been determined based on the fair
value at the grant date, AEP net income and earnings per share would have been
the pro forma amounts shown in the following table:


- -------------------------------------------------------------
                                   2002       2001     2000
                                   ----       ----     ----
                                         (in millions
                                  except per share amounts)
Net (loss) income:

  As reported                    $ (519)     $ 971    $ 267
  Pro forma                        (528)       959      264
Basic (loss) earnings per share:
  As reported                    $(1.57)     $3.01    $0.83
  Pro forma                       (1.59)      2.98     0.82
Diluted (loss) earnings per share:
  As reported                    $(1.57)     $3.01    $0.83
  Pro forma                       (1.59)      2.97     0.82

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

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

The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of AEP options granted:


                                 2002     2001     2000
- -------------------------------------------------------------
Risk Free Interest
 Rate                            3.53%      4.87%    5.02%
Expected Life                  7 years    7 years  7 years
Expected Volatility             29.78%     28.40%   24.75%
Expected Dividend
 Yield                           6.15%      6.05%    6.02%

Weighted average fair value of options:

 -Granted above
Market Price                    $4.58       N/A       N/A
 -Granted at Market   Price
                                $4.37      $8.01    $5.50
- ---------------------------- ---------- ---------- ----------

16. Business Segments:

In 2000, AEP reported the following four business segments: Domestic Electric
Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and Other.
With this structure, our regulated domestic utility companies were considered
single, vertically-integrated units, and were reported collectively in the
Domestic Electric Utilities segment.

In 2001 and 2002, we moved toward a goal of functionally and structurally
separating our businesses. The ensuing realignment of our operations resulted in
our current business segments, Wholesale, Energy Delivery and Other. The
business activities of each of these segments are as follows:

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

Energy Delivery
o        Domestic electricity transmission
o        Domestic electricity distribution

Other
o        Energy services

Segment results of operations for the twelve months ended December 31, 2002,
2001 and 2000 are shown below. These amounts include certain estimates and
allocations where necessary.

We have used earnings before interest and income taxes (EBIT) as a measure of
segment operating performance. The EBIT measure is total operating revenues net
of total operating expenses and other income and deductions from income. It
differs from net income in that it does not take into account interest expense,
income taxes and the effect of discontinued operations, extraordinary items and
the cumulative effect of a change in accounting principle. EBIT is believed to
be a reasonable gauge of results of operations. By excluding interest expense
and income taxes, EBIT does not give guidance regarding the demand of debt
service or other interest requirements, or tax liabilities or taxation rates.
The effects of interest expense and taxes on overall corporate performance can
be seen in the Consolidated Statements of Operations. By excluding discontinued
operations, extraordinary items, and the cumulative effect of changes in
accounting principles, EBIT gives more focused guidance on segment operating
performance.

<TABLE>
<CAPTION>



                                          Energy             Reconciling           AEP
Year                         Wholesale    Delivery   Other   Adjustments       Consolidated
- ----                         ---------    --------   -----   -----------       ------------
                                              (in millions)
2002
<S>                            <C>        <C>        <C>      <C>               <C>
  Revenues from:
    External unaffiliated
     customers                 $10,988    $ 3,551    $  16    $    -            $14,555
    Transactions with other
     operating segments          2,314         20       46       (2,380)           -
  Segment EBIT                     645        970     (549)        -              1,066
  Depreciation, depletion and
    amortization expense           842        519       16         -              1,377
  Total assets                  22,622     11,624      248          247(a)       34,741
  Investments in equity method
    subsidiaries                   115       -          57         -                172
  Gross property additions       1,072        638       12         -              1,722

2001

  Revenues from:
    External unaffiliated
     customers                 $ 9,297    $ 3,356   $  114    $    -            $12,767
    Transactions with other
     operating segments          2,708         20    1,155       (3,883)           -
  Segment EBIT                   1,302        986       42         -              2,330
  Depreciation, depletion and
    amortization expense           597        632       14         -              1,243
  Total assets                  21,947     12,455      220        4,675(a)       39,297
  Investments in equity method
    subsidiaries                   242       -         370         -                612
  Gross property additions         610        844      200         -              1,654

2000

  Revenues from:
    External unaffiliated
     customers                 $ 7,834     $3,174   $  105    $    -            $11,113
    Transactions with other
     operating segments          1,726          2      750       (2,478)           -
  Segment EBIT                     686      1,017       89         -              1,792
  Depreciation, depletion and
    amortization expense           556        506       29         -              1,091
  Total assets                  24,172     14,876    2,625        4,960(a)       46,633
  Investments in equity method
    subsidiaries                   140       -         296         -                436
  Gross property additions         366        961      141         -              1,468

(a) Reconciling adjustments for Total Assets include Assets Held for Sale and/or
Assets of Discontinued Operations

</TABLE>


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.

<TABLE>
<CAPTION>




                                         Twelve Months Ended                         Twelve Months Ended
                                          December 31, 2002                           December 31, 2001
                                          -----------------                           -----------------

                                             Segment                                       Segment         Total
                               Revenues        EBIT      Total Assets       Revenues        EBIT           Assets
                               --------      -------     ------------       --------       -------         ------
                                           (in thousands)                              (in thousands)


<S>                          <C>            <C>          <C>               <C>            <C>            <C>
Wholesale Segment
APCo                         $1,220,381     $215,735     $2,586,966        $1,189,223     $164,844       $2,505,877
CSPCo                           907,882      282,974      1,762,074           867,100      232,372        1,742,328
I&M                           1,205,043       42,410      3,160,575         1,212,587      117,396        3,027,509
KPCo                            246,629        6,568        591,655           247,842        4,935          507,516
OPCo                          1,523,452      364,071      2,861,415         1,545,392      240,128        2,820,995
PSO                             518,100       34,322        840,374           695,123       52,086          827,235
SWEPCo                          736,484       70,547      1,082,251           768,322       82,409        1,127,331
TCC                           1,135,946      395,060      3,117,447         1,265,655      303,966        2,847,743
TNC                             377,387      (58,930)       376,308           387,422        7,930          371,031

Energy Delivery Segment
APCo                         $  594,089     $217,360     $2,040,881        $  595,036     $213,733       $1,976,908
CSPCo                           492,278       63,071        991,166           483,219      130,503          980,060
I&M                             321,721      170,342      1,426,616           314,410      111,206        1,366,553
KPCo                            132,054       51,697        573,021           131,183       54,033          491,532
OPCo                            589,673       71,225      1,595,617           552,713      118,261        1,573,078
PSO                             275,547       69,543        936,316           261,877       79,787          921,676
SWEPCo                          348,236      107,081      1,126,424           333,004      107,197        1,173,345
TCC                             554,547      148,918      2,238,991           473,182      109,587        2,045,287
TNC                              73,353       53,995        500,867           169,036       33,226          493,844

Registrant Subsidiaries
Company Total
APCo                         $1,814,470     $433,095     $4,627,847        $1,784,259     $378,577       $4,482,785
CSPCo                         1,400,160      346,045      2,753,240         1,350,319      362,875        2,722,388
I&M                           1,526,764      212,752      4,587,191         1,526,997      228,602        4,394,062
KPCo                            378,683       58,265      1,164,676           379,025       58,968          999,048
OPCo                          2,113,125      435,296      4,457,032         2,098,105      358,389        4,394,073
PSO                             793,647      103,865      1,776,690           957,000      131,873        1,748,911
SWEPCo                        1,084,720      177,628      2,208,675         1,101,326      189,606        2,300,676
TCC                           1,690,493      543,978      5,356,438         1,738,837      413,553        4,893,030
TNC                             450,740       (4,935)       877,175           556,458       41,156          864,875


</TABLE>

<TABLE>
<CAPTION>

                                                                     Twelve Months Ended
                                                                      December 31, 2000
                                                                     -------------------
                                              Revenues                   Segment EBIT                 Total Assets
                                               --------                   ------------                 ------------
                                                                         (in thousands)
<S>                                          <C>                            <C>                         <C>
        Wholesale Segment

        APCo                                 $1,184,335                     $154,525                    $3,674,081
        CSPCo                                   906,363                      235,860                     2,481,594
        I&M                                   1,177,190                     (146,297)                    3,978,360
        KPCo                                    268,529                       22,379                       759,228
        OPCo                                  1,672,744                      289,084                     3,976,532
        PSO                                     711,274                       54,072                     1,011,474
        SWEPCo                                  773,324                       27,055                     1,302,611
        TCC                                   1,291,588                      273,650                     3,182,202
        TNC                                     394,860                       13,910                       466,539

        Energy Delivery Segment

        APCo                                   $574,918                     $191,560                    $2,898,514
        CSPCo                                   398,046                       81,896                     1,395,897
        I&M                                     311,019                      126,241                     1,795,748
        KPCo                                    121,346                       49,770                       735,315
        OPCo                                    467,587                      138,418                     2,217,443
        PSO                                     245,124                       85,524                     1,126,949
        SWEPCo                                  344,950                      129,842                     1,355,778
        TCC                                     478,814                      136,069                     2,285,499
        TNC                                     176,204                       50,201                       620,965

        Registrant Subsidiaries
        Company Total

        APCo                                 $1,759,253                     $346,085                    $6,572,595
        CSPCo                                 1,304,409                      317,756                     3,877,491
        I&M                                   1,488,209                      (20,056)                    5,774,108
        KPCo                                    389,875                       72,149                     1,494,543
        OPCo                                  2,140,331                      427,502                     6,193,975
        PSO                                     956,398                      139,596                     2,138,423
        SWEPCo                                1,118,274                      156,897                     2,658,389
        TCC                                   1,770,402                      409,719                     5,467,701
        TNC                                     571,064                       64,111                     1,087,504


</TABLE>



17.  Risk Management, Financial
       Instruments and Derivatives:

Risk Management

We are subject to market risks in our day to day operations. Our risk policies
have been reviewed with the Board of Directors, approved by a Risk Executive
Committee and are administered by the Chief Risk Officer. The Risk Executive
Committee establishes risk limits, approves risk policies, assigns
responsibilities regarding the oversight and management of risk and monitors
risk levels. This committee receives daily, weekly, and monthly reports
regarding compliance with policies, limits and procedures. The committee meets
monthly and consists of the Chief Risk Officer, Chief Credit Officer, V.P. of
Market Risk Oversight, and senior financial and operating managers.

The risks and related strategies that management can employ are:

Risk                  Description             Strategy
- ----                  -----------             --------
Price Risk            Volatility in           Trading and
                       commodity prices        hedging

Interest Rate Risk    Changes in
                       interest rates         Hedging

Foreign Exchange      Fluctuations in
 Risk                  foreign currency       Trading and
                       rates                   hedging

Credit Risk           Non-performance         Guarantees
                       on contracts            and
                            with               collateral
                       counterparties

We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Chief Risk Officer and his
staff. If the risk from trading activities exceeds certain pre-determined
limits, the positions are modified or hedged to reduce the risk to be within the
limits unless specifically approved by the Risk Executive Committee.

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

We enter into currency and interest rate forward and swap transactions to hedge
the currency and interest rate exposures created by commodity transactions.
These transactions are marked-to-market to match the change in value in the
transactions they hedge which are also marked-to-market. We employ forward
contracts as cash flow hedges and swaps as cash flow or fair value hedges to
mitigate changes in interest rates or fair values on Short-Term Debt and
Long-term Debt when management deems it necessary. We do not hedge all interest
rate risk.

We employ cash flow forward hedge contracts to lock-in prices on transactions
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations in debt
denominated in foreign currencies. We do not hedge all foreign currency
exposure.

Our open trading contracts, including structured transactions, are
marked-to-market daily using the price model and price curve(s) corresponding to
the instrument. Forwards, futures and swaps are generally valued by subtracting
the contract price from the market price and then multiplying the difference by
the contract volume and adjusting for net present value and other impacts.
Significant estimates in valuing such contracts include forward price curves,
volumes, seasonality, weather, and other factors.

Forwards and swaps are valued based on forward price curves which represent a
series of projected prices at which transactions can be executed in the market.
The forward price curve includes the market's expectations for prices of a
delivered commodity at that future date. The forward price curve is developed
from the market bid price, which is the highest price which traders are willing
to pay for a contract, and the ask or offer price, which is the lowest price
traders are willing to receive for selling a contract.

Option contracts, consisting primarily of options on forwards and spread
options, are valued using models, which are variations on Black-Scholes option
models. The market-related inputs are the interest rate curve, the underlying
commodity forward price curve, the implied volatility curve and the implied
correlation curve. Volatility and correlation prices may be quoted in the
market. Significant estimates in valuing these contracts include forward price
curves, volumes, and other volatilities.

Futures and options traded on exchanges (primarily oil and gas on NYMEX) are
valued at the exchange price.

Electricity and gas markets in particular have primary trading hubs or delivery
points/regions and less liquid secondary delivery points. In North American
natural gas markets, the primary delivery points are generally traded from Henry
Hub, Louisiana. The less liquid gas or power trading points may trade as a
spread (based on transportation costs, constraints, etc.) from the nearest
liquid trading hub. Also, some commodities trade more often and therefore are
more liquid than others. For example, peak electricity is a more liquid product
than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36
months and after that only trades in seasonal or calendar blocks. When this
occurs, we use our best judgment to estimate the curve values. The value used
will be based on various factors such as last trade price, recent price trend,
product spreads, location spreads (including transportation costs), cross
commodity spreads (e.g., heat rate conversion of gas to power), time spreads,
cost of carry (e.g., cost of gas storage), marginal production cost, cost of new
entrant capacity, and alternative fuel costs. Also, an energy commodity
contract's price volatility generally increases as it approaches the delivery
month. Spot price volatility (e.g., daily or hourly prices) can cause contract
values to change substantially as open positions settle against spot prices.
When a portion of a curve has been estimated for a period of time and market
changes occur, assumptions are updated to align the curve to the market. All
fair value amounts are net of adjustments for items such as credit quality of
the counterparty (credit risk) and liquidity risk.

We also mark-to-market derivatives that are not trading contracts in accordance
with generally accepted accounting principles. There may be unique models for
these transactions, but the curves the Company inputs into the models are the
same forward curves, which are described above.

We have developed independent controls to evaluate the reasonableness of our
valuation models and curves. However, there are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. Therefore, there could be a significant favorable or adverse effect
on future results of operations and cash flows if market prices at settlement
differ from the price models and curves.

Results of Risk Management Activities

The amounts of net revenue margins (sales less purchases) in 2002, 2001, and
2000 for trading activities were:

                    2002        2001        2000
                    ----        ----        ----
                            (in millions)
Net Revenue
 Margins            $53         $402        $233

The amounts of revenues recorded in 2002, 2001 and 2000 for the registrant
subsidiaries were:
                      2002         2001        2000
                      ----         ----        ----
                               (in thousands)

APCo              $29,044     $ 52,871     $ 27,924
CSPCo              24,503       36,120       16,999
I&M                11,833       19,130       26,575
KPCo                3,801        6,150       10,704
OPCo               39,114       43,789       26,840
PSO                (1,357)      (7,345)       5,233
SWEPCo             (4,999)       2,317        1,562
TCC                (7,708)      10,500       (1,752)
TNC                (1,098)       1,508          222
                  -------     --------     --------
  Total           $93,133     $165,040     $114,307
                  =======     ========     ========


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 internally developed price
curves for open long-term trading contracts. The following table does not
reflect derivative contracts designated as hedges or firm transmission rights
contracts. As a result, the totals will not agree to the Consolidated Balance
Sheets. The fair values of trading contracts at December 31 are:

                                           2002                 2001
                                  ------------------     -------------------
                                           Fair                 Fair
                                          Value                Value
                                      (in millions)        (in millions)
Trading Assets

Electricity and Other
               Physicals                 $  846               $   966
               Financials                   226                   170
                                         ------               -------
             Total Trading Assets        $1,072               $ 1,136
                                         ======               =======

Gas
               Physicals                 $  105               $   196
               Financials                   685                 1,587
                                         ------               -------
             Total Trading Assets        $  790               $ 1,783
                                         ======               =======

Trading Liabilities

Electricity and Other
               Physicals                 $ (534)              $  (760)
               Financials                  (126)                  (87)
                                         ------               -------
             Total Trading Liabilities   $ (660)              $  (847)
                                         ======               =======

Gas
               Physicals                 $ (191)              $   (38)
               Financials                  (761)               (1,586)
                                         ------               -------
             Total Trading Liabilities   $ (952)              $(1,624)
                                         ======               =======

The fair values of trading contracts for the registrant subsidiaries at December
31 are:

                                           2002                  2001
                                    -----------------     -----------------
                                           Fair                  Fair
                                          Value                 Value
                                      (in thousands)        (in thousands)
APCo
Trading Assets

Electricity and Other
               Physicals                 $ 168,687            $ 217,914
               Financials                   39,585               39,466

Trading Liabilities

Electricity and Other
               Physicals                 $(100,045)           $(164,624)
               Financials                  (11,375)             (17,055)


CSPCo
Trading Assets

Electricity and Other
               Physicals                 $ 113,397            $ 133,425
               Financials                   26,611               24,206

Trading Liabilities

Electricity and Other
               Physicals                 $ (67,244)           $ (98,749)
               Financials                   (7,647)             (10,433)


I&M
Trading Assets

Electricity and Other
               Physicals                 $ 121,706            $ 165,162
               Financials                   28,474               26,630

Trading Liabilities

Electricity and Other
               Physicals                 $ (70,061)           $(117,795)
               Financials                   (9,258)             (12,652)

                                           2002                  2001
                                    ----------------      ------------------
                                           Fair                  Fair
                                           Value                 Value
                                      (in thousands)         (in thousands)

KPCo
Trading Assets

Electricity and Other
               Physicals                 $  43,532            $  53,651
               Financials                   10,216                9,732

Trading Liabilities

Electricity and Other
               Physicals                 $ (25,815)           $ (46,476)
               Financials                   (2,935)              (4,178)


OPCo
Trading Assets

Electricity and Other
               Physicals                 $ 158,473            $ 180,989
               Financials                   35,304               32,997

Trading Liabilities

Electric and Other
               Physicals                 $ (89,526)           $(132,603)
               Financials                  (10,145)             (15,937)


PSO
Trading Assets

Electricity
               Physicals                 $   8,165            $  47,613

Trading Liabilities

Electricity
               Physicals                 $  (4,620)           $ (45,179)


SWEPCo
Trading Assets

Electricity
               Physicals                 $   9,329            $  54,647
Trading Liabilities

Electricity
               Physicals                 $  (5,278)           $ (51,747)


TCC
Trading Assets

Electricity
               Physicals                 $  26,752            $  62,520


Trading Liabilities

Electricity
               Physicals                 $ (21,136)           $ (58,663)
               Financials                     (202)                -


TNC
Trading Assets

Electricity
               Physicals                 $   6,323            $  18,567

Trading Liabilities

Electricity
               Physicals                 $  (4,047)           $ (17,652)
               Financials                     (233)                -




Credit Risk

AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. AEP uses Moody's Investor Service, Standard and Poor's and
qualitative and quantitative data to independently assess the financial health
of counterparties on an ongoing basis. This data, in conjunction with the
ratings information, is used to determine appropriate risk parameters. AEP also
requires cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.

We trade electricity and gas contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty are not material to our financial
condition at December 31, 2002. At December 31, 2002, less than 7% of our
exposure was below investment grade as expressed in terms of Net Mark to Market
Assets. Net Mark to Market Assets represents the aggregate difference between
the forward market price for the remaining term of the contract and the
contractual price per counterparty. The following table approximates
counterparty credit quality and exposure for AEP based on netting across AEP
entities, commodities and instruments at December 31, 2002:


                      Futures,
                    Forward and
Counterparty            Swap
 Credit Quality       Contracts     Options       Total
                    -----------     -------       -----
                                (in millions)

AAA/Exchanges         $    26     $    2     $   28
AA                        307         33         340
A                         448         26         474
BBB                       700        101         801
Below   Investment
 Grade                    107         11         118
                      -------      ------     ------

  Total                $1,588      $ 173      $1,761
                       ======      =====      ======


We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electricity and gas transactions are executed
over-the-counter with counterparties or through brokers. Gas transactions are
also executed through brokerage accounts with brokers who are registered with
the U.S. Commodity Futures Trading Commission. Brokers and counterparties
require cash or cash-related instruments to be deposited on these transactions
as margin against open positions. The combined margin deposits at December 31,
2002 and 2001 were $109 million and $55 million. These margin accounts are
restricted and therefore are not included in Cash and Cash Equivalents on the
Consolidated Balance Sheets. AEP and its subsidiaries can be subject to further
margin requirements should related commodity prices change.

The margin deposits at December 31, 2002 for the registrants were:

                                           (in thousands)

         APCo                                  $1,010
         CSPCo                                    673
         I&M                                      727
         KPCo                                     261
         OPCo                                   1,400
         PSO                                       91
         SWEPCo                                   105
         TCC                                      121
         TNC                                       37

Financial Derivatives and Hedging

In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. AEP recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income of $27 million
at January 1, 2001 in connection with the adoption of SFAS 133. Derivatives
included in the transition adjustment are interest rate swaps, foreign currency
swaps and commodity swaps, options and futures.

Most of the derivatives identified in the trans-ition adjustment were designated
as cash flow hedges and relate to foreign operations.

Certain derivatives may be designated for accounting purposes as a hedge of
either the fair value of an asset, liability, firm commitment, or a hedge of the
variability of cash flows related to a variable-priced asset, liability,
commitment, or forecasted trans-action. To qualify for hedge accounting, the
relationship between the hedging instrument and the hedged item must be
documented to include the risk management objective and strategy for use of the
hedge instrument. At the inception of the hedge and on an ongoing basis, the
effectiveness of the hedge is assessed to determine whether the hedge will be or
is highly effective in offsetting changes in fair value or cash flows of the
item being hedged. Changes in the fair value that result from the
ineffectiveness of a hedge under SFAS 133 are recognized currently in earnings
through mark-to-market accounting. Changes in the fair value of effective cash
flow hedges are reported in Accumulated Other Comprehensive Income. Gains and
losses from cash flow hedges in other comprehensive income are reclassified to
earnings in the accounting periods in which the variability of cash flows of the
hedged items affect earnings


Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on
AEP's Consolidated Balance Sheets at December 31, 2002 are:
                                                                Accumulated
                                                          Other Comprehensive
                   Hedging Assets  Hedging Liabilities   Income (Loss) After Tax
                   --------------  -------------------   -----------------------
                                        (in millions)
lectricity and Gas          $6              $ (8)                    $ (2)
nterest Rate                 -               (13)*                    (12)
oreign Currency              -                (2)                      (2)
                                                                     ----
                                                                     $(16)

* Includes $6 million loss recorded in an equity investment.

The following table represents the activity in Other Comprehensive Income (Loss)
related to the effect of adopting SFAS 133 for derivative contracts that qualify
as cash flow hedges at December 31, 2002:




                                                                 (in millions)
AEP Consolidated
  Beginning Balance, January 1, 2002                               $    (3)
  Changes in fair value                                                (56)
  Reclasses from OCI to net loss                                        43
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $   (16)
                                                                   =======

                                                                (in thousands)
APCo
  Beginning Balance, January 1, 2002                               $  (340)
  Effective portion of changes in fair value                        (1,310)
  Reclasses from OCI to net income                                    (270)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $(1,920)
                                                                   =======

CSPCo
  Beginning Balance, January 1, 2002                               $   -
  Effective portion of changes in fair value                            62
  Reclasses from OCI to net income                                    (329)
                                                                   -------
Accumulated OCI derivative Loss, December 31, 2002                 $  (267)
                                                                   =======
I&M
  Beginning Balance, January 1, 2002                               $(3,835)
  Effective portion of changes in fair value                            34
  Reclasses from OCI to net income                                   3,515
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $  (286)
                                                                   =======

KPCo
  Beginning Balance, January 1, 2002                               $(1,903)
  Effective portion of changes in fair value                           343
  Reclasses from OCI to net income                                   1,882
                                                                   -------
Accumulated OCI derivative gain, December 31, 2002                 $   322
                                                                   =======

OPCo
  Beginning Balance, January 1, 2002                               $  (196)
  Effective portion of changes in fair value                          (103)
  Reclasses from OCI to net income                                    (439)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $  (738)
                                                                   =======

PSO
  Beginning Balance, January 1, 2002                               $   -
  Effective portion of changes in fair value                             2
  Reclasses from OCI to net income                                     (44)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $   (42)
                                                                   =======

SWEPCo
  Beginning Balance, January 1, 2002                               $   -
  Effective portion of changes in fair value                             1
  Reclasses from OCI to net income                                     (49)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $   (48)
                                                                   =======

TCC
  Beginning Balance, January 1, 2002                               $   -
  Effective portion of changes in fair value                            30
  Reclasses from OCI to net income                                     (66)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $   (36)
                                                                   =======

TNC
  Beginning Balance, January 1, 2002                               $   -
  Effective portion of changes in fair value                             3
  Reclasses from OCI to net income                                     (18)
                                                                   -------
Accumulated OCI derivative loss, December 31, 2002                 $   (15)
                                                                   =======


Approximately $9 million of net losses from cash flow hedges in Accumulated
Other Comprehensive Income (Loss) at December 31, 2002 are expected to be
reclassified to net income in the next twelve months as the items being hedged
settle. The actual amounts reclassified from Accumulated Other Comprehensive
Income to Net Income can differ as a result of market price changes. The maximum
term for which the exposure to the variability of future cash flows is being
hedged is five years.

Financial Instruments

Market Valuation of Non-Derivative Financial Instrument

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

The fair values of Long-term Debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange. The book values and fair values of significant financial
instruments for AEP and its registrant subsidiaries at December 31, 2002 and
2001 are summarized in the following tables.

                                    2002                         2001
                                    ----                         ----
                            Book Value   Fair Value   Book Value    Fair Value
                            ----------   ----------   ----------    ----------
                               (in millions)                (in millions)
AEP
Long-term Debt             $   10,125   $  10,470    $    9,505  $    9,542
Preferred Stock                    84          77            95          93
Trust Preferred Securities        321         324           321         321

                              (in thousands)                (in thousands)
AEGCo
Long-term Debt             $   44,802   $   48,103   $   44,793  $   45,268

APCo
Long-term Debt             $1,893,861   $1,953,087   $1,556,559  $1,439,531
Preferred Stock                10,860        9,774       10,860      10,860

CSPCo
Long-term Debt             $  621,626   $  643,715   $  791,848  $  802,194
Preferred Stock                  -            -          10,000      10,100

I&M
Long-term Debt             $1,617,062   $1,673,363   $1,652,082  $1,672,392
Preferred Stock                64,945       58,948       64,945      62,795

KPCo
Long-term Debt             $  466,632   $  475,455   $  346,093  $  350,233

OPCo
Long-term Debt             $1,067,314   $1,095,197   $1,203,841  $1,227,880
Preferred Stock                 8,850        7,965        8,850       8,837

PSO
Long-term Debt             $  545,437   $  570,761   $  451,129  $  462,903
Trust Preferred Securities     75,000       75,900       75,000      74,730

SWEPCo
Long-term Debt             $  693,448   $  727,085   $  645,283  $  656,998
Trust Preferred Securities    110,000      110,880      110,000     109,780

TCC
Long-term Debt             $1,438,565   $1,522,373   $1,253,768  $1,278,644
Trust Preferred Securities    136,250      136,959      136,250     135,760

TNC
Long-term Debt             $  132,500   $  144,060   $  255,967  $  266,846



Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust investments which are classified as held for sale for decommissioning and
SNF disposal, reported in Other Assets on AEP's Consolidated Balance Sheets, are
recorded at market value in accordance with SFAS 115 "Accounting for Certain
Investments in Debt and Equity Securities". At December 31, 2002 and 2001, the
fair values of the trust investments were $969 million and $933 million,
respectively, and had a cost basis of $909 million and $839 million,
respectively. The change in market value in 2002, 2001, and 2000 was a net
unrealized holding loss of $33 million and $11 million and a net unrealized
holding gain of $6 million, respectively.

18. Income Taxes:

The details of AEP's consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:

                   Year Ended December 31,
                   ----------------------
                  2002      2001       2000
                  ----      ----       ----
                        (in millions)
Federal:
 Current         $ 330      $404       $ 793
 Deferred         (192)       60        (236)
                 -----      ----       -----
     Total         138       464         557
                 -----      ----       -----
State:
 Current            32        61          47
 Deferred           30        34          (6)
                 -----      ----       -----
     Total          62        95          41
                 -----      ----       -----
International:
 Current            13       (13)          4
 Deferred            1        -            -
                 -----      ----       ------
     Total          14       (13)          4
                 -----      ----       -----

Total Income Tax
  as Reported
  Before
  Discontinued
  Operations,
  Extraordinary
  Items and
  Cumulative
  Effect         $ 214      $546       $ 602
                 =====      ====       =====

<TABLE>
<CAPTION>


The details of the registrant subsidiaries income taxes as reported are as
follows:


                                            AEGCo      APCo      CSPCo      I&M        KPCo
Year Ended December 31, 2002                               (in thousands)
<S>                                      <C>        <C>       <C>       <C>          <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $  6,607   $ 99,140  $ 81,539  $  66,063    $   680
  Deferred                                 (5,028)    17,626    25,771    (19,870)     9,451
  Deferred Investment Tax Credits               2     (3,229)   (3,096)    (7,340)    (1,173)
                                         --------   --------  --------  ---------    -------
    Total                                   1,581    113,537   104,214     38,853      8,958
                                         --------   --------  --------  ---------    -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (173)      (354)    9,442      3,435      1,583
  Deferred                                   -          (849)   (2,479)     2,949        388
  Deferred Investment Tax Credits          (3,363)    (1,408)     (174)      (400)       (67)
                                         --------   --------  --------  ---------   --------
    Total                                  (3,536)    (2,611)    6,789      5,984      1,904
                                         --------   --------  --------  ---------   --------

Total Income Tax as Reported             $ (1,955)  $110,926  $111,003  $  44,837   $ 10,862
                                         ========   ========  ========  =========   ========

</TABLE>
<TABLE>
<CAPTION>


                                         OPCo        PSO      SWEPCo      TCC       TNC
Year Ended December 31, 2002                               (in thousands)
<S>                                      <C>        <C>       <C>       <C>         <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 86,026   $(49,673) $ 41,354  $  30,495   $    109
  Deferred                                 30,048     75,659    (3,134)   113,726    (10,652)
  Deferred Investment Tax Credits          (2,493)    (1,791)   (4,524)    (5,207)    (1,271)
                                         --------   --------  --------  ---------   --------
    Total                                 113,581     24,195    33,696    139,014    (11,814)
                                         --------   --------  --------  ---------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                   2,732     (1,812)    1,772      3,223      1,334
  Deferred                                 15,962       -         -           (71)    (1,623)
  Deferred Investment Tax Credits            (684)      -         -          -          -
                                         --------   --------  --------  ---------   --------
    Total                                  18,010     (1,812)    1,772      3,152       (289)
                                         --------   --------  --------  ---------   --------

Total Income Tax as Reported             $131,591   $ 22,383  $ 35,468  $ 142,166   $(12,103)
                                         ========   ========  ========  =========   ========
</TABLE>
<TABLE>
<CAPTION>



                                           AEGCo      APCo       CSPCo      I&M      KPCo
Year Ended December 31, 2001                                (in thousands)
<S>                                      <C>        <C>       <C>       <C>         <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $  9,126   $ 71,623  $ 88,013  $ 107,286   $  7,726
  Deferred                                 (6,224)    27,198    14,923    (45,785)     2,812
  Deferred Investment Tax Credits            -        (3,237)   (3,899)    (7,377)    (1,180)
                                         --------   --------  --------  ---------   --------
    Total                                   2,902     95,584    99,037     54,124      9,358
                                         --------   --------  --------  ---------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                     (56)   (19,165)  (13,803)   (10,590)    (2,725)
  Deferred                                   -        21,832    17,885     16,580      3,481
  Deferred Investment Tax Credits          (3,414)    (1,528)     (159)      (947)       (72)
                                         --------   --------  --------  ---------   --------
    Total                                  (3,470)     1,139     3,923      5,043        684
                                         --------   --------  --------  ---------   --------

Total Income Tax as Reported             $   (568)  $ 96,723  $102,960  $  59,167   $ 10,042
                                         ========   ========  ========  =========   ========
</TABLE>
<TABLE>
<CAPTION>



                                           OPCo       PSO      SWEPCo       TCC       TNC
Year Ended December 31, 2001                               (in thousands)
<S>                                      <C>        <C>       <C>       <C>         <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $(62,298)  $ 53,030  $ 77,965  $ 190,671   $ 19,424
  Deferred                                166,166    (16,726)  (31,396)   (72,568)   (11,891)
  Deferred Investment Tax Credits          (2,495)    (1,791)   (4,453)    (5,207)    (1,271)
                                         --------   --------  --------  ---------   --------
    Total                                 101,373     34,513    42,116    112,896      6,262
                                         --------   --------  --------  ---------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                 (21,600)       352       542       (398)      (691)
  Deferred                                 20,014       -         -          -          -
  Deferred Investment Tax Credits            (794)      -         -          -          -
                                         --------   --------  --------  ---------   --------
    Total                                  (2,380)       352       542       (398)      (691)
                                         --------   --------  --------  ---------   --------

Total Income Tax as Reported             $ 98,993   $ 34,865  $ 42,658  $ 112,498   $  5,571
                                         ========   ========  ========  =========   ========

</TABLE>
<TABLE>
<CAPTION>


                                           AEGCo       APCo     CSPCo       I&M       KPCo
Year Ended December 31, 2000                               (in thousands)
<S>                                      <C>        <C>       <C>       <C>         <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $  8,746   $129,165  $120,494  $ 134,796   $ 17,878
  Deferred                                 (5,842)     3,838    (7,746)  (126,748)     2,521
  Deferred Investment Tax Credits            -        (2,947)   (3,379)    (7,524)    (1,187)
                                         --------   --------  --------  ---------   --------
    Total                                   2,904    130,056   109,369        524     19,212
                                         --------   --------  --------  ---------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                     (44)       327     3,777      2,950        (50)
  Deferred                                   -         4,764     3,683      1,569      1,244
  Deferred Investment Tax Credits          (3,396)    (1,968)     (103)      (330)       (65)
                                         --------   --------  --------  ---------   --------
    Total                                  (3,440)     3,123     7,357      4,189      1,129
                                         --------   --------  --------  ---------   --------

Total Income Tax as Reported             $   (536)  $133,179  $116,726  $   4,713   $ 20,341
                                         ========   ========  ========  =========   ========

</TABLE>
<TABLE>
<CAPTION>

                                          OPCo        PSO      SWEPCo      TCC        TNC
Year Ended December 31, 2000                              (in thousands)
<S>                                     <C>         <C>       <C>       <C>         <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                               $ 259,608   $ 11,597  $ 16,073  $  89,403   $  6,774
  Deferred                                (70,263)    25,453    14,653     16,263      9,401
  Deferred Investment Tax Credits          (1,824)    (1,791)   (4,482)    (5,207)    (1,271)
                                        ---------   --------  --------  ---------   --------
    Total                                 187,521     35,259    26,244    100,459     14,904
                                        ---------   --------  --------  ---------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                  15,426     (1,306)   (1,476)    (5,073)      (222)
  Deferred                                  4,307       -         -          -        (1,237)
  Deferred Investment Tax Credits         ( 1,575)      -         -          -          -
                                        ---------   --------  --------  ---------   ---------
    Total                                  18,158     (1,306)   (1,476)    (5,073)    (1,459)
                                        ---------   --------  --------  ---------   --------

Total Income Tax as Reported            $ 205,679   $ 33,953   $24,768  $  95,386   $ 13,445
                                        =========   ========   =======  =========   ========

</TABLE>

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 December 31,
                                                    ----------------------
                                              2002          2001       2000
                                              ----          ----       ----
                                                       (in millions)

Net Income (Loss)                             $(519)      $  971       $267
Discontinued Operations (net of income tax
 Of $73 million in 2002, $22 million in 2001
 and $5 million in 2000)                        190          (86)      (122)
Extraordinary Items
 (net of income tax of $20 million in 2001
  and $44 million in 2000)                       -            50         35
Cumulative Effect of Accounting Change
 (net of income tax of  $2 million in 2001)     350          (18)        -
Preferred Stock Dividends                        11           10         11
                                              -----       ------       ----
Income Before Preferred Stock Dividends
  of Subsidiaries                                32          927        191
Income Taxes Before Discontinued Operations,
  Extraordinary Items and Cumulative Effect     214          546        602
                                              -----       ------       ----
Pre-Tax Income                                $ 246       $1,473       $793
                                              =====       ======       ====

Income Taxes on Pre-Tax Income
  at Statutory Rate (35%)                     $  86       $  516       $278
Increase (Decrease) in Income Taxes
  Resulting from the Following Items:
   Depreciation                                  32           48         77
   Corporate Owned Life Insurance                -             4        247
   Investment Tax Credits (net)                 (35)         (37)       (36)
   Tax Effects of International Operations      123          (12)        (1)
   Energy Production Credits                    (14)          -          -
   Merger Transaction Costs                      -            -          49
   State Income Taxes                            40           62         26
   Other                                        (18)         (35)       (38)
                                              -----       ------       ----
Total Income Taxes as Reported Before
  Discontinued Operations, Extraordinary
  Items and Cumulative Effect                 $ 214       $  546       $602
                                              =====       ======       ====
Effective Income Tax Rate                      87.0%        37.1%      75.9%
                                              =====       ======       ====

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.
<TABLE>
<CAPTION>


                                             AEGCo     APCo      CSPCo      I&M       KPCo
Year Ended December 31, 2002                                 (in thousands)

<S>                                        <C>       <C>       <C>        <C>        <C>
Net Income                                 $  7,552  $205,492  $181,173   $ 73,992   $ 20,567
Income Taxes                                 (1,955)  110,926   111,003     44,837     10,862
                                           --------  --------  --------   --------   --------
Pre-Tax Income                             $  5,597  $316,418  $292,176   $118,829   $ 31,429
                                           ========  ========  ========   ========   ========

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                   $  1,959  $110,746  $102,262   $ 41,590   $ 11,000
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                  870     3,082     2,899     21,812      2,057
  Corporate Owned Life Insurance               -          (93)      719        268        305
  Nuclear Fuel Disposal Costs                  -         -         -        (3,814)      -
  Allowance for Funds Used
    During  Construction                       (446)     -         -        (3,453)      -
  Rockport Plant Unit 2 Investment
    Tax Credit                                 (748)     -         -          -          -
  Removal Costs                                -         -         -          -          (735)
  Investment Tax Credits (net)               (3,361)   (4,637)   (3,270)    (7,740)    (1,240)
  State Income Taxes                            335     6,469    11,387        124      1,058
  Other                                        (564)   (4,641)   (2,994)    (3,950)    (1,583)
                                           --------  --------  --------   --------   --------
Total Income Taxes as Reported             $ (1,955) $110,926  $111,003   $ 44,837   $ 10,862
                                           ========  ========  ========   ========   ========

Effective Income Tax Rate                       N.M.    35.1%     38.0%      37.7%       34.6%
                                               ====    =====     =====      =====       =====

</TABLE>
<TABLE>
<CAPTION>


                                            OPCo       PSO      SWEPCo      TCC        TNC
Year Ended December 31, 2002                                (in thousands)
<S>                                        <C>       <C>       <C>       <C>         <C>
Net Income (Loss)                          $220,023  $ 41,060  $ 82,992  $ 275,941   $(13,677)
Income Taxes                                131,591    22,383    35,468    142,166    (12,103)
                                           --------  --------  --------  ---------   --------
Pre-Tax Income (Loss)                      $351,614  $ 63,443  $118,460  $ 418,107   $(25,780)
                                           ========  ========  ========  =========   ========

Income Tax on Pre-Tax Income (Loss)
 at Statutory Rate (35%)                   $123,065  $ 22,205  $ 41,461  $ 146,337   $ (9,023)
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                4,227      (583)   (2,790)      (295)       (32)
  Corporate Owned Life Insurance                (84)     -         -          -          -
  Investment Tax Credits (net)               (3,177)   (1,791)   (4,524)    (5,207)    (1,271)
  State Income Taxes                         18,051     2,639     3,987      2,202     (1,577)
  Other                                     (10,491)      (87)   (2,666)      (871)      (200)
                                           --------  --------  --------  ---------   --------
Total Income Taxes as Reported             $131,591  $ 22,383  $ 35,468  $ 142,166   $(12,103)
                                           ========  ========  ========  =========   ========

Effective Income Tax Rate                     37.4%      35.3%     29.9%      34.0%      47.0%
                                              =====      =====     =====      =====      =====
</TABLE>
<TABLE>
<CAPTION>



                                            AEGCo     APCo      CSPCo       I&M       KPCo
Year Ended December 31, 2001                               (in thousands)

<S>                                         <C>      <C>       <C>       <C>         <C>
Net Income                                  $ 7,875  $161,818  $161,876  $  75,788   $ 21,565
Extraordinary Loss                             -         -       30,024       -          -
Income Taxes                                   (568)   96,723   102,960     59,167     10,042
                                            -------  --------  --------  ---------   --------
Pre-Tax Income                              $ 7,307  $258,541  $294,860  $ 134,955   $ 31,607
                                            =======  ========  ========  =========   ========

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                   $  2,557  $ 90,489  $103,201  $  47,234   $ 11,062
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                  230     2,977     2,757     21,224      1,581
  Corporate Owned Life Insurance               -          450       544       (148)       334
  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                                -         -         -          -          (420)
  Investment Tax Credits (net)               (3,414)   (4,765)   (4,058)    (8,324)    (1,252)
  State Income Taxes                          1,050     9,613     5,727      6,137        318
  Other                                        (287)   (2,041)   (5,211)    (2,058)    (1,581)
                                           --------  --------  --------  ---------   --------
Total Income Taxes as Reported             $   (568) $ 96,723  $102,960  $  59,167   $ 10,042
                                           ========  ========  ========  =========   ========

Effective Income Tax Rate                       N.M.     37.4%     34.9%      43.8%      31.8%
                                                ====     =====     =====      =====      =====
</TABLE>
<TABLE>
<CAPTION>



                                            OPCo        PSO     SWEPCo      TCC        TNC
Year Ended December 31, 2001                                (in thousands)
<S>                                       <C>        <C>       <C>       <C>         <C>
Net Income                                $ 147,445  $ 57,759  $ 89,367  $ 182,278   $ 12,310
Extraordinary Loss                           18,348      -         -         2,509       -
Income Taxes                                 98,993    34,865    42,658    112,498      5,571
                                          ---------  --------  --------  ---------   --------
Pre-Tax Income                            $ 264,786  $ 92,624  $132,025  $ 297,285   $ 17,881
                                          =========  ========  ========  =========   ========

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $  92,675  $ 32,418  $ 46,209  $ 104,050   $  6,258
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                7,972     1,127      (501)     8,477      1,463
  Corporate Owned Life Insurance              1,852      -         -          -          -
  Investment Tax Credits (net)               (3,289)   (1,791)   (4,453)    (5,207)    (1,271)
  State Income Taxes                          9,752     5,137     5,451      9,652      1,283
  Other                                      (9,969)   (2,026)   (4,048)    (4,474)    (2,162)
                                          ---------  --------  --------  ---------   --------
Total Income Taxes as Reported            $  98,993  $ 34,865  $ 42,658  $ 112,498   $  5,571
                                          =========  ========  ========  =========   ========

Effective Income Tax Rate                      37.4%     37.6%     32.3%      37.8%      31.2%
                                               ====      ====      ====       =====      =====
</TABLE>
<TABLE>
<CAPTION>

                                             AEGCo     APCo      CSPCo       I&M        KPCo
Year Ended December 31, 2000                                 (in thousands)

<S>                                         <C>      <C>       <C>       <C>         <C>
Net Income (Loss)                           $ 7,984  $ 73,844  $ 94,966  $(132,032)  $ 20,763
Extraordinary (Gains) Loss                             (1,066)   39,384       -          -
Income Tax Benefit                             -       (7,872)  (14,148)      -          -
Income Taxes                                   (536)  133,179   116,726      4,713     20,341
                                            -------  --------  --------  ---------   --------
Pre-Tax Income (Loss)                       $ 7,448  $198,085  $236,928  $(127,319)  $ 41,104
                                            =======  ========  ========  =========   ========

Income Tax on Pre-Tax Income
 (Loss) at Statutory Rate (35%)            $  2,607  $ 69,330  $ 82,925  $ (44,562)  $ 14,386
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                  452     7,606    10,529     20,378      1,827
  Corporate Owned Life Insurance               -       54,824    29,259     42,587      5,149
  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)     -          -          (420)
  Investment Tax Credits (net)               (3,396)   (4,915)   (3,482)    (7,854)    (1,252)
  State Income Taxes                            784     9,950        89      6,004      1,597
  Other                                        (287)   (2,419)   (2,594)    (5,672)      (946)
                                           --------  --------  --------  ---------   --------
Total Income Taxes as Reported             $   (536) $133,179  $116,726  $   4,713   $ 20,341
                                           ========  ========  ========  =========   ========

Effective Income Tax Rate                       N.M.     67.2%     49.3%      N.M.      49.5%
                                                ====     ====      ====       ====      =====
</TABLE>
<TABLE>
<CAPTION>



                                           OPCo        PSO      SWEPCo      TCC        TNC
Year Ended December 31, 2000                                (in thousands)
<S>                                       <C>        <C>       <C>       <C>         <C>
Net Income                                $  83,737  $ 66,663  $ 72,672  $ 189,567   $ 27,450
Extraordinary Loss                           40,157      -         -          -          -
Income Tax Benefit                          (21,281)     -         -          -          -
Income Taxes                                205,679    33,953    24,768     95,386     13,445
                                          ---------  --------  --------  ---------   --------
Pre-Tax Income                            $ 308,292  $100,616  $ 97,440  $ 284,953   $ 40,895
                                          =========  ========  ========  =========   ========

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $ 107,902  $ 35,216  $ 34,104  $  99,734   $ 14,313
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                               27,577       695    (1,012)     7,556      1,204
  Corporate Owned Life Insurance             84,453      -         -          -          -
  Investment Tax Credits (net)               (3,398)   (1,791)   (4,482)    (5,207)    (1,271)
  State Income Taxes                         (1,988)    3,037     1,650      2,296       -
  Other                                      (8,867)   (3,204)   (5,492)    (8,993)      (801)
                                          ---------  --------  --------  ---------   --------
Total Income Taxes as Reported            $ 205,679  $ 33,953  $ 24,768  $  95,386   $ 13,445
                                          =========  ========  ========  =========   ========

Effective Income Tax Rate                     66.7%     33.7%     25.4%     33.5%      32.9%
                                              ====      ====      ====      =====      ====

</TABLE>

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,                                       2002              2001
- --------------                                      ----              ----
                                                        (in millions)

Deferred Tax Assets                               $ 2,189          $ 1,216
Deferred Tax Liabilities                           (6,105)          (5,716)
                                                  -------          -------
Net Deferred Tax Liabilities                      $(3,916)         $(4,500)
                                                  =======          =======

Property Related Temporary Differences            $(3,612)         $(3,674)
Amounts Due From Customers For Future
   Federal Income Taxes                              (360)            (245)
Deferred State Income Taxes                          (422)            (314)
Transition Regulatory Assets                         (234)            (268)
Regulatory Assets Designated for Securitization      (310)            (332)
Asset Impairments and Investment Value Losses         417             -
Deferred Income Taxes on Other Comprehensive Loss     326                3
All Other (net)                                       279              330
                                                  -------          -------
   Net Deferred Tax Liabilities                   $(3,916)         $(4,500)
                                                  =======          =======


<TABLE>
<CAPTION>

                                          AEGCo       APCo      CSPCo        I&M        KPCo
December 31, 2002                                           (in thousands)
<S>                                     <C>        <C>        <C>         <C>          <C>
Deferred Tax Assets                     $  73,094  $ 213,972  $  72,990   $ 348,672    $  36,948
Deferred Tax Liabilities                 (102,096)  (915,773)  (510,761)   (704,869)    (215,261)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $ (29,002) $(701,801) $(437,771)  $(356,197)   $(178,313)
                                        ========== =========  =========   =========    =========

Property Related Temporary Differences  $ (74,291) $(555,824) $(331,381)  $(343,587)   $(127,073)
Amounts Due From Customers For
  Future Federal Income Taxes               7,626    (58,246)    (8,895)    (38,752)     (20,488)
Deferred State Income Taxes                (5,119)   (77,693)   (23,448)    (52,528)     (28,722)
Transition Regulatory Assets                -        (28,735)   (71,752)       -            -
Asset Impairments and Investment
  Value Losses                              -             18        215         225            4
Deferred Income Taxes on Other
  Comprehensive Loss                        -         38,823     31,961      21,800        5,089
Net Deferred Gain on Sale and
  Leaseback-Rockport Plant Unit 2          38,866       -          -         25,860         -
Accrued Nuclear Decommissioning Expense      -          -          -         65,856         -
Deferred Fuel and Purchased Power            -        (1,878)      (273)    (13,144)         415
Deferred Cook Plant Restart Costs            -          -          -        (14,000)        -
Nuclear Fuel                                 -          -          -         (5,153)        -
All Other (net)                             3,916    (18,266)   (34,198)     (2,774)      (7,538)
                                        ---------   --------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $ (29,002) $(701,801) $(437,771)  $(356,197)   $(178,313)
                                        =========  =========  =========   =========    =========

</TABLE>
<TABLE>
<CAPTION>


                                          OPCo       PSO       SWEPCo        TCC         TNC
December 31, 2002                                          (in thousands)
<S>                                     <C>        <C>        <C>         <C>          <C>
Deferred Tax Assets                     $ 155,334  $  70,649  $  82,113   $   130,210  $  35,970
Deferred Tax Liabilities                 (949,721)  (412,045)  (423,177)   (1,391,462)  (153,491)
                                        ---------  ---------  ---------   -----------  ---------
  Net Deferred Tax Liabilities          $(794,387) $(341,396) $(341,064)  $(1,261,252) $(117,521)
                                        =========  =========  =========   ===========  =========

Property Related Temporary Differences  $(620,634) $(303,888) $(315,821)  $  (709,246) $(142,034)
Amounts Due From Customers For
  Future Federal Income Taxes             (53,256)     9,490     (4,078)     (198,595)     5,726
Deferred State Income Taxes               (46,990)   (57,911)   (48,372)      (66,333)    (4,080)
Transition Regulatory Assets             (131,833)      -          -             -          -
Asset Impairments and Investment
  Value Losses                                615       -          -             -        14,996
Deferred Income Taxes on Other
  Comprehensive Loss                       39,246     29,332     28,906        39,394     16,565
Deferred Fuel and Purchased Power             540    (28,696)     3,192         2,655     (9,933)
Regulatory Assets Designated
  For Securitization                         -          -          -         (310,410)      -
All Other (net)                            17,925     10,277     (4,891)      (18,717)     1,239
                                        ---------  ---------  ---------   -----------  ---------
  Net Deferred Tax Liabilities          $(794,387) $(341,396) $(341,064)  $(1,261,252) $(117,521)
                                        =========  =========  =========   ===========  =========

</TABLE>
<TABLE>
<CAPTION>


                                          AEGCo      APCo        CSPCo       I&M         KPCo

December 31, 2001                                           (in thousands)
<S>                                     <C>        <C>        <C>         <C>          <C>
Deferred Tax Assets                     $  75,856  $ 162,334  $  74,767   $ 332,225    $  30,927
Deferred Tax Liabilities                 (103,831)  (865,909)  (518,489)   (732,756)    (199,231)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $ (27,975) $(703,575) $(443,722)  $(400,531)   $(168,304)
                                        =========  =========  =========   =========    =========

Property Related Temporary Differences  $ (70,581) $(530,298) $(323,139)  $(306,151)   $(118,147)
Amounts Due From Customers For
  Future Federal Income Taxes               9,292    (55,206)    (9,839)    (46,756)     (20,215)
Deferred State Income Taxes                (3,822)   (56,747)    (8,968)    (38,015)     (25,267)
Transition Regulatory Assets                 -       (34,783)   (78,298)       -            -
Deferred Income Taxes on Other
  Comprehensive Loss                         -           183       -          2,065        1,025
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            -        (4,106)       (39)    (26,270)          57
Deferred Cook Plant Restart Costs            -          -          -        (28,000)        -
Nuclear Fuel                                 -          -          -        (16,062)        -
All Other (net)                            (3,680)   (22,618)   (23,439)    (12,206)      (5,757)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $ (27,975) $(703,575) $(443,722)  $(400,531)   $(168,304)
                                        =========  =========  =========   =========    =========
</TABLE>
<TABLE>
<CAPTION>



                                           OPCo       PSO       SWEPCo        TCC        TNC
December 31, 2001                                           (in thousands)
<S>                                     <C>        <C>        <C>         <C>          <C>
Deferred Tax Assets                     $ 135,938  $  59,421  $  56,189   $   130,863  $  22,888
Deferred Tax Liabilities                 (933,827)   356,298)  (425,970)   (1,294,658)  (167,937)
                                        ---------   --------  ---------   -----------  ---------
  Net Deferred Tax Liabilities          $(797,889) $(296,877) $(369,781)  $(1,163,795) $(145,049)
                                        =========  =========  =========   ===========  =========

Property Related Temporary
  Differences                           $(595,974) $(320,900) $(362,884)  $  (808,922) $(149,309)
Amounts Due From Customers For
  Future Federal Income Taxes             (61,130)    10,199     (6,441)      (70,174)     4,757
Deferred State Income Taxes               (18,440)   (35,038)   (48,729)      (66,333)    (4,079)
Transition Regulatory Assets             (154,947)      -          -             -          -
Deferred Income Taxes on Other
  Comprehensive Loss                          106       -          -             -          -
Deferred Fuel and Purchased Power              12      3,052     (2,778)       18,032    (11,756)
Provision for Mine Shutdown Costs          20,323       -          -             -          -
Regulatory Assets Designated
  For Securitization                         -          -          -         (332,198)      -
All Other (net)                            12,161     45,810     51,051        95,800     15,338
                                        ---------  ---------   --------   ------------ ---------
  Net Deferred Tax Liabilities          $(797,889) $(296,877) $(369,781)  $(1,163,795) $(145,049)
                                        =========  =========  =========   ===========  =========

</TABLE>

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 6th
Circuit.

The earnings reductions recorded in 2000 for affected registrant subsidiaries
were as follows:

                     (in millions)
APCo                      $ 82
CSPCo                       41
I&M                         66
KPCo                         8
OPCo                       118

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.


19.  Basic and Diluted Earnings Per Share:

The calculation of AEP's basic and diluted earnings (loss) per common share
(EPS) is based on the amounts of Net Income (Loss) and weighted average common
shares shown in the table below:

                              2002      2001     2000
                              ----      ----     ----
                               (in millions - except
                                 per share amounts)
Income:
Income Before Discontinued
 Operations, Extraordinary
 Items and Cumulative
 Effect                      $  21    $  917    $ 180
Discontinued Operations       (190)       86      122
                             ------    -----    -----
Income (Loss) Before
 Extraordinary Item
 And Cumulative Effect        (169)    1,003      302
Extraordinary Losses
 (net of tax):
 Discontinuance of
  Regulatory Accounting
  For Generation                -        (48)     (35)
 Loss on Reacquired Debt        -         (2)     -
Cumulative Effect of
  Accounting Change
  (net of tax)                (350)       18       -
                             -----     -----    -----

Net Income (Loss)            $(519)   $  971    $ 267
                             =====    ======    =====

Weighted Average Shares:
  Average Common
   Shares Outstanding          332       322      322
  Assumed Conversion of
   Dilutive Stock Options
   (see Note 15)               -           1       -
                             -----     -----    -----
  Diluted Average Common
   Shares Outstanding          332       323      322
                             =====     =====    =====

Basic and Diluted
  Earnings Per Common Share:
  Income Before Discontinued
   Operations, Extraordinary
   Items and Cumulative
   Effect                   $ 0.06     $2.85    $0.56
  Discontinued Operations    (0.57)     0.26     0.38
                            ------     -----    -----
  Income (Loss) Before
   Extraordinary Item and
   Cumulative Effect         (0.51)     3.11     0.94
  Extraordinary Losses
   (net of tax):
   Discontinuance of
    Regulatory Accounting
    For Generation             -       (0.15)   (0.11)
   Loss on Reacquired Debt     -       (0.01)     -
  Cumulative Effect
   of Accounting Change
   (net of tax)              (1.06)     0.06      -
                            ------     -----    -----
                            $(1.57)    $3.01    $0.83
                            ======     =====    =====

The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. AEP's basic and diluted EPS
are the same in 2002, 2001 and 2000 since the effect on weighted average common
shares outstanding is minimal.

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

Options to purchase 8.8 million, 0.7 million and 6.4 million shares of common
stock were outstanding at December 31, 2002, 2001 and 2000, respectively, but
were not included in the computation of diluted earnings per share because the
options' exercise prices were greater than the year-end market price of the
common shares and, therefore, the effect would be antidilutive.

In addition, there is no effect on diluted earnings per share related to our
equity units (issued in 2002) unless the market value of AEP common stock
exceeds $49.08 per share. There were no dilutive effects from equity units at
December 31, 2002. If our common stock value exceeds $49.08 we would apply the
treasury stock method to the equity units to calculate diluted earnings per
share. This method of calculation theoretically assumes that the proceeds
received as a result of the forward purchase contracts are used to repurchase
outstanding shares. Also see Note 27.

20.  Supplementary Information:

<TABLE>
<CAPTION>

                                                                                     Year Ended December 31,
                                                                                    -----------------------
                                                                                 2002        2001         2000
                                                                                 ----        ----         ----
                                                                                         (in millions)
<S>                                                                              <C>         <C>        <C>
AEP Consolidated Purchased Power -
 Ohio Valley Electric Corporation
  (44.2% owned by AEP System)                                                    $142        $127         $86

Cash was paid for:
  Interest (net of capitalized amounts)                                          $792        $972        $842
  Income Taxes                                                                   $336        $569        $449

Noncash Investing and Financing Activities:
 Acquisitions under Capital Leases                                               $  6         $17        $118
Assumption of Liabilities Related to Acquisitions                                  $1        $171           -

Exchange of Communication Investment for Common Stock                               -          $5           -

</TABLE>

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, 2002, 2001, and 2000 were:

                                 APCo         CSPCo         I&M         OPCo
                                 ----         -----         ---         ----
                                              (in thousands)
Year Ended December 31, 2002    $53,386      $14,885      $23,282      $50,135
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


21. Power and Distribution Projects:

Power Projects

AEP owns interests of 50% or less in domestic unregulated power plants with a
capacity of 1,483 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, AEP has equity interests in international power plants
totaling 1,113 MW.

Investments in power projects that are 50% or less owned are accounted for by
the equity method and reported in Investments in Power and Distribution Projects
on AEP's Consolidated Balance Sheets (see "Eastex" within the Assets Held for
Sale section of Note 13), except for Eastex Cogeneration which, due to its
structure, is consolidated. At December 31, 2002, six domestic power projects
and three international power investments are accounted for under the equity
method. The six domestic projects are combined cycle gas turbines that provide
steam to a host commercial customer and are considered either Qualifying
Facilities (QFs) or Exempt Wholesale Generators (EWGs) under PURPA. The three
international power investments are classified as Foreign Utility Companies
(FUCO) under the Energy Policies Act of 1992. Two of the international
investments are power projects and the other international investment is a
company which owns an interest in four additional power projects. All of the
power projects accounted for under the equity method have unrelated third-party
partners.

Seven of the above power projects have project-level financing, which is
non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $58 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits.

Distribution Projects

AEP owns a 44% equity interest in Vale, a Brazilian electric operating company
which was purchased for a total of $149 million. On December 1, 2001 AEP
converted a $66 million note receivable and accrued interest into a 20% equity
interest in Caiua (Brazilian electric operating company), a subsidiary of Vale.
Vale and Caiua have experienced losses from operations and AEP's investment has
been affected by the devaluation of the Brazilian Real. In December 2002, AEP
recorded an other than temporary impairment totaling $141.1 million (after
federal income tax benefit of $76 million) of its 44% equity investment in Vale
and its 20% equity interest in Caiua. See "Grupo Rede Investment" within the
Investment Values section of Note 13 "Asset Impairments and Investment Value
Losses", for further information on the 2002 impairment of AEP's Vale and Caiua
investments.

22. Leases:

Leases of property, plant and equipment are for periods up to 99 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. Capital leases for non-regulated property are accounted for as if
the assets were owned and financed. The components of rental costs are as
follows:



<PAGE>
<TABLE>
<CAPTION>


                                   AEP     AEGCo     APCo     CSPCo     I&M      KPCo    OPCo
Year Ended December 31, 2002                            (in thousands)
<S>                             <C>       <C>      <C>      <C>      <C>       <C>      <C>
Lease Payments on
 Operating Leases               $346,000  $76,143  $ 6,634  $ 5,209  $110,833  $ 1,597  $68,816
Amortization of Capital Leases    65,000      238    9,729    6,010     8,319    2,171   12,637
Interest on Capital Leases        14,000       19    2,240    1,717     2,221      469    4,501
                                --------  -------  -------  -------  --------  -------  -------
 Total Lease Rental Costs       $425,000  $76,400  $18,603  $12,936  $121,373  $ 4,237  $85,954
                                ========  =======  =======  =======  ========  =======  =======
</TABLE>

                                   PSO     SWEPCo    TCC       TNC
Year Ended December 31, 2002                (in thousands)
Lease Payments on
 Operating Leases                $ 4,403   $3,240  $ 7,184  $ 1,981
Amortization of Capital Leases      -        -        -        -
Interest on Capital Leases          -        -        -        -
                                 -------   ------  -------  -------
 Total Lease Rental Costs        $ 4,403   $3,240  $ 7,184  $ 1,981
                                 =======   ======  =======  =======

<TABLE>
<CAPTION>

                                   AEP     AEGCo     APCo     CSPCo    I&M      KPCo     OPCo
Year Ended December 31, 2001                            (in thousands)
<S>                             <C>       <C>      <C>      <C>      <C>       <C>      <C>
Lease Payments on
 Operating Leases               $293,000  $76,262  $ 6,142  $ 7,063  $104,574  $ 1,191  $63,913
Amortization of Capital Leases    82,000      281   12,099    7,206    17,933    2,740   14,443
Interest on Capital Leases        22,000       55    3,789    2,396     4,424      808    5,818
                                --------  -------  -------  -------  --------  -------  -------
 Total Lease Rental Costs       $397,000  $76,598  $22,030  $16,665  $126,931  $ 4,739  $84,174
                                ========  =======  =======  =======  ========  =======  =======
</TABLE>

                                   PSO     SWEPCo    TCC      TNC
Year Ended December 31, 2001                (in thousands)
Lease Payments on
 Operating Leases               $  4,010  $ 2,277  $ 5,948  $ 1,534
Amortization of Capital Leases      -        -        -        -
Interest on Capital Leases          -        -        -        -
                                --------  -------  -------  -------
 Total Lease Rental Costs       $  4,010  $ 2,277  $ 5,948  $ 1,534
                                ========  =======  =======  =======
<TABLE>
<CAPTION>

                                   AEP     AEGCo     APCo     CSPCo     I&M      KPCo    OPCo
Year Ended December 31, 2000                            (in thousands)
<S>                             <C>       <C>      <C>      <C>      <C>       <C>      <C>
Lease Payments on
 Operating Leases               $246,000  $73,858  $ 7,128  $ 7,683  $ 81,446  $ 1,978  $51,981
Amortization of Capital Leases   118,000      281   13,900    7,776    26,341    3,931   37,280
Interest on Capital Leases        36,000       55    3,930    2,690    10,908    1,054    9,584
                                --------  -------  -------   ------  --------  -------  -------
 Total Lease Rental Costs       $400,000  $74,194  $24,958  $18,149  $118,695  $ 6,963  $98,845
                                ========  =======  =======  =======  ========  =======  =======
</TABLE>


                                   PSO     SWEPCo    TCC      TNC
Year Ended December 31, 2000                (in thousands)
Lease Payments on
 Operating Leases               $  3,269  $ 1,401  $ 5,410  $ 1,210
Amortization of Capital Leases      -        -        -        -
Interest on Capital Leases          -        -        -        -
                                --------  -------  -------  -------
 Total Lease Rental Costs       $  3,269  $ 1,401  $ 5,410  $ 1,210
                                ========  =======  =======  =======

<TABLE>
<CAPTION>

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
Year Ended December 31, 2002                       (in thousands)
<S>                             <C>       <C>      <C>      <C>      <C>       <C>
Property, Plant and Equipment
 Under Capital Leases
 Production                     $ 40,000  $ 1,793  $ 3,368  $ 6,380  $  5,728  $ 1,138
 Distribution                     15,000     -        -        -       14,589      -
 Other:
  Mining Assets and Other        687,000     -      67,395   46,791    70,140   14,258
                                --------  ------   -------  -------  --------  -------
   Total Property, Plant
    and Equipment                742,000    1,793   70,763   53,171    90,457   15,396
 Accumulated Amortization        299,000    1,294   37,452   26,551    41,141    8,168
                                --------  -------  -------  -------  --------   ------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $443,000  $   499  $33,311  $26,620  $ 49,316  $ 7,228
                                ========  =======  =======  =======  ========  =======

Obligations Under Capital Leases:
  Noncurrent Liability          $170,000  $   301  $23,991  $21,643  $ 42,619  $ 5,093
  Liability Due Within One Year   58,000      198    9,598    5,967     8,229    2,155
                                --------  -------  -------  -------  --------   ------
      Total Obligations Under
       Capital Leases           $228,000  $   499  $33,589  $27,610  $ 50,848  $ 7,248
                                ========  =======  =======  =======  ========  =======


</TABLE>


                                  OPCo    SWEPCo
Year Ended December 31, 2002      (in thousands)
Property, Plant and Equipment
 Under Capital Leases
 Production                     $ 21,360  $  -
 Distribution                       -        -
 Other:
  Mining Assets and Other        103,018   45,699
   Total Property, Plant
    and Equipment                124,378   45,699
 Accumulated Amortization         63,810   45,699
  Net Property, Plant and
   Equipment Under
   Capital Leases               $ 60,568  $  -
                                ========  =======

Obligations Under Capital Leases:
  Noncurrent Liability          $ 51,266  $  -
  Liability Due Within One Year   14,360     -
                                --------  -------
      Total Obligations Under
       Capital Leases           $ 65,626  $  -
                                ========  =======
<TABLE>
<CAPTION>


                                  AEP      AEGCo     APCo    CSPCo     I&M       KPCo     OPCo
Year Ended December 31, 2001                             (in thousands)
<S>                             <C>       <C>      <C>      <C>      <C>        <C>      <C>
Property, Plant and Equipment
 Under Capital Leases
 Production                     $ 39,000  $ 1,983  $ 2,712  $ 6,380  $   4,826  $ 1,138  $ 22,477
 Distribution                     15,000     -        -        -        14,593     -         -
 Other:
 Mining Assets and Other         723,000      129   82,292   54,999     86,267   17,658   114,944
                                --------  -------  -------  -------  ---------  -------   -------
   Total Property, Plant
    and Equipment                777,000    2,112   85,004   61,379    105,686   18,796   137,421
 Accumulated Amortization        250,000    1,801   38,745   26,044     43,768    9,213    57,429
                                --------  -------  -------  -------  ---------  -------  --------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $527,000  $   311  $46,259  $35,335  $  61,918  $ 9,583  $ 79,992
                                ========  =======  =======  =======  =========  =======  ========

Obligations Under Capital Leases:
  Noncurrent Liability          $219,000  $    76  $33,928  $27,052  $  51,093  $ 6,742  $ 64,261
  Liability Due Within One Year   75,000      235   12,357    7,835     10,840    2,841    16,405
                                --------  -------  -------  -------  ---------  -------  --------
      Total Obligations Under
       Capital Leases           $294,000  $   311  $46,285  $34,887  $  61,933  $ 9,583  $ 80,666
                                ========  =======  =======  =======  =========  =======  ========

</TABLE>
<TABLE>
<CAPTION>

Future minimum lease payments consisted of the following at December 31, 2002:

                                   AEP     AEGCo     APCo     CSPCo      I&M      KPCo    OPCo
Capital                                                  (in thousands)
<S>                            <C>      <C>        <C>      <C>      <C>        <C>      <C>
- -------
2003                           $ 70,000 $      249 $12,483  $ 7,365  $  10,373  $ 2,623  $ 17,363
2004                             53,000        114  10,515    6,231      9,122    1,957    14,634
2005                             37,000         58   6,799    5,279      6,506    1,581    11,442
2006                             29,000         31   5,117    3,898      5,561      948    10,220
2007                             21,000         29   2,668    2,969      4,024      788     8,694
Later Years                      59,000         79   4,829    8,321     10,732      725    20,302
                               -------- ---------- -------  -------  ---------  -------  --------
Total Future Minimum
 Lease Payments                 269,000        560  42,411   34,063     46,318    8,622    82,655
Less Estimated Interest Elemen   41,000         61   8,822    6,453     (4,530)   1,374    17,029
                               -------- ---------- -------  -------  ---------  -------  --------
Estimated Present Value of
  Future Minimum Lease
  Payments                     $228,000 $      499 $33,589  $27,610  $  50,848  $ 7,248  $ 65,626
                               ======== ========== =======  =======  =========  =======  ========

</TABLE>
<TABLE>
<CAPTION>

                                  AEP      AEGCo      APCo    CSPCo      I&M      KPCo     OPCo
                                                         (in thousands)
Noncancellable Operating Leases
<S>                         <C>         <C>        <C>      <C>     <C>         <C>      <C>
2003                        $   305,000 $   73,854 $ 4,482  $ 4,608 $   95,213  $ 1,031  $ 62,784
2004                            271,000     73,854   3,723    5,111     81,246      865    62,837
2005                            252,000     73,854   3,114    4,013     78,968      747    62,169
2006                            242,000     73,854   2,742    1,630     77,741      576    62,481
2007                            237,000     73,854   1,962    1,374     76,461      875    62,880
Later Years                   2,462,000  1,107,810   4,384    2,670  1,117,725    1,492   180,548
                             ---------- ---------- -------- ------- ----------  -------  --------
Total Future Minimum
 Lease Payments              $3,769,000 $1,477,080 $20,407  $19,406 $1,527,354  $ 5,586  $493,699
                             ========== ========== =======  ======= ==========  =======  ========
</TABLE>


                                 PSO      SWEPCo     TCC     TNC
                                            (in thousands)
Noncancellable Operating Leases
2003                         $    2,260 $      912 $ 1,815  $   448
2004                              1,998        617   1,565      296
2005                              1,714        433   1,388      192
2006                              1,391        317   1,086      169
2007                              1,256        301     603      167
Later Years                        -          -       -        -
                             ---------- ---------- -------  -------
Total Future Minimum
 Lease Payments              $    8,619 $    2,580 $ 6,457  $ 1,272
                             ========== ========== =======  =======


OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG was formed to
design, construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG
owns the Gavin Scrubber and leases it to OPCo. The lease is accounted for as an
operating lease with the payment obligations included in the lease footnote.
Payments under the operating lease are based on JMG's cost of financing (both
debt and equity) and include an amortization component plus the cost of
administration. Neither OPCo nor AEP has an ownership interest in JMG and does
not guarantee JMG's debt.

At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.

The use of JMG allows AEP to enter into an operating lease while keeping the tax
benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP will consolidate JMG in the third quarter of 2003 as a result of the
issuance of FIN 46. Upon consolidation, AEP would record the assets,
liabilities, depreciation expense, minority interest and debt interest expense
of JMG. AEP would eliminate operating lease expense. AEP's maximum exposure to
loss as a result of its involvement with JMG is approximately $560 million of
outstanding debt and equity of JMG as of December 31, 2002.

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.

23.  Lines of Credit and Sale of Receivables:

Lines of Credit - AEP System

The AEP System uses short-term debt, primarily commercial paper and revolving
credit facilities, to meet fluctuations in working capital requirements and
other interim capital needs. AEP has established a utility money pool and a
non-utility money pool to coordinate short-term borrowings for certain
subsidiaries. Utility money participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC. AEP also incurs borrowings outside of the money
pool for other subsidiaries. As of December 31, 2002, AEP had revolving credit
facilities totaling $3.5 billion to support its commercial paper program. At
December 31, 2002, AEP had $3.2 billion outstanding in short-term borrowings of
which $1.4 billion was commercial paper supported by the revolving credit
facilities. The maximum amount of commercial paper outstanding during the year,
which had a weighted average interest rate during 2002 of 2.47%, was $3.3
billion during April 2002. On December 11, 2002, Moody's Investor Services
placed AEP's Prime-2 short-term rating for commercial paper under review for
possible downgrade. On January 24, 2003, Standard & Poor's Rating Services
placed AEP's A-2 short-term rating for commercial paper under review for
possible downgrade. On February 10, 2003, Moody's Investor Services downgraded
AEP's short-term rating for commercial paper to Prime-3 from Prime-2. As a
result, AEP's access to the commercial paper market will be limited and AEP will
use other sources of funds as necessary.
The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows:

                        Year Ended December 31,
                        ----------------------
                       2002      2001      2000
                       ----      ----      ----
                             (in millions)

AEGCo                  $0.4     $ 0.8      $  -
APCo                    4.9       9.8         -
CSPCo                   3.2       5.0        1.4
I&M                     0.4      13.1        0.8
KPCo                    1.8       2.3         -
OPCo                    6.9      14.6        9.2
PSO                     5.4       6.3        7.5
SWEPCo                  4.6       3.4        4.2
TCC                    11.1      11.4       16.9
TNC                     3.8       3.1        2.7

Interest income earned from amounts advanced to the AEP money pool by the
registrant subsidiaries were:

                        Year Ended December 31,
                        ----------------------
                       2002      2001       2000
                       ----      ----       ----
                            (in millions)

AEGCo                  $0.1      $ -        $ -
APCo                    2.0       1.7         -
CSPCo                   1.3       0.8        1.1
I&M                     2.0       1.6        9.0
KPCo                     -        0.1        1.8
OPCo                    0.8       8.6        3.4
PSO                     1.1        -          -
SWEPCo                  1.6       0.1         -
TCC                     2.0       0.1         -

Outstanding short-term debt for AEP Consolidated consisted of:

                                 December 31,
                                 -----------
                               2002        2001
                               ----        ----
                                (in millions)
Balance Outstanding:
  Notes Payable               $1,747      $1,063
  Commercial paper             1,417       2,948
                              ------      ------
    Total                     $3,164      $4,011
                              ======      ======

Sale of Receivables - AEP Credit

AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140
allowing the receivables to be taken off of AEP Credit's balance sheet and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.

At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. AEP Credit
maintains a retained interest in the receivables sold and this interest is
pledged as collateral for the collection of the receivables sold. The fair value
of the retained interest is based on book value due to the short-term nature of
the accounts receivables less an allowance for anticipated uncollectible
accounts.

AEP Credit purchases accounts receivable through purchase agreements with
affiliated companies and, until the first quarter of 2002, with non-affiliated
companies. As a result of the restructuring of electric utilities in the State
of Texas, the purchase agreement between AEP Credit and Reliant Energy,
Incorporated was terminated as of January 25, 2002 and the purchase agreement
between AEP Credit and Texas-New Mexico Power Company, the last remaining
non-affiliated company, was terminated on February 7, 2002. In addition, the
purchase agreements between AEP Credit and its Texas affiliates AEP Texas
Central Company (formerly Central Power and Light Company) and AEP Texas North
Company (formerly West Texas Utilities Company) were terminated effective March
20, 2002.



Comparative accounts receivable information for AEP Credit:

                            Year Ended December 31,
                            ----------------------
                             2002           2001
                             ----           ----
                                (in millions)
Proceeds from Sale of
 Accounts Receivable        $5,513        $1,134
Accounts Receivable
 Retained Interest Less
  Uncollectible Accounts
  and Amounts Pledged as
  Collateral                    76           143
Deferred Revenue from
 Servicing Accounts
 Receivable                      1             5
Loss on Sale of Accounts
 Receivable                      4             8
Average Variable
 Discount Rate                1.92%         2.28%
Retained Interest if 10%
 Adverse change in
 Uncollectible Accounts         74           142
Retained Interest if 20%
 Adverse change in
 Uncollectible Accounts         72           140



Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:

<TABLE>
<CAPTION>

                                                                        Face Value
                                                                   Year Ended December 31,
                                                                   ----------------------
                                                                    2002          2001
                                                                       (in millions)

<S>                                                                <C>           <C>
Customer Accounts Receivable Retained                              $  466        $  343
Miscellaneous Accounts Receivable Retained                          1,394         1,365
Allowance for Uncollectible Accounts Retained                        (119)          (69)
                                                                   ------        ------
        Total Net Balance Sheet Accounts Receivable                 1,741         1,639

Customer Accounts Receivable Securitized (Affiliate)                  454           560
Customer Accounts Receivable Securitized (Non-Affiliate)              -             485
                                                                   ------        ------
        Total Accounts Receivable managed                          $2,195        $2,684
                                                                   ======        ======

Net Uncollectible Accounts Written Off                                 48            72
                                                                   ------        ------
</TABLE>



Customer accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit. Miscellaneous account receivable
have been fully retained and not securitized.

At December 31, 2002, delinquent customer accounts receivable was $30 million.

Under the factoring arrangement certain of 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. The amount of
factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:

                      December 31,
                      -----------
                    2002      2001
                    ----      ----
Company             (in millions)
- -------
APCo               $ 67.6    $ 61.2
CSPCo               114.3     105.7
I&M                 103.7      94.9
KPCo                 29.5      26.2
OPCo                109.8     100.2
PSO                  83.7      70.7
SWEPCo               65.2      81.6
TCC                  -        145.3
TNC                  -         35.5


The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:

                             Year Ended December 31,
                             ----------------------
                         2002         2001         2000
                         ----         ----         ----
                                  (in millions)

APCo                    $ 4.8         $ 5.2        $  -
CSPCo                    15.8          15.2         10.8
I&M                       7.4           8.5          6.8
KPCo                      2.7           2.7          1.9
OPCo                     11.4          12.8          8.4
PSO                       7.2           9.6          8.3
SWEPCo                    5.4           7.4          9.2
TCC                       2.2          14.7         15.7
TNC                       1.4           3.8          4.0



24.  Unaudited Quarterly Financial Information:

The unaudited quarterly financial information for AEP Consolidated follows:

                                    2002 Quarterly Periods Ended
                                    ----------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                        --------        -------       --------       -------
(In Millions - Except
Per Share Amounts)
Revenues                 $3,169          $3,575         $3,870        $3,941
Operating Income (Loss)     459             427            782          (405)
Income (Loss) Before
 Discontinued Operations,
 Extraordinary Items
 and Cumulative Effect      159             158            386          (682)
Net Income (Loss)          (169)             62            425          (837)
Earnings (Loss) per Share
 Before Discontinued
 Operations,Extraordinary
 Items and Cumulative
 Effect*                   0.49            0.49           1.14         (2.01)
Earnings (Loss) per
 Share**                  (0.53)           0.19           1.25         (2.47)

                                    2001 Quarterly Periods Ended
                                    ----------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                        --------        -------       --------       -------
(In Millions - Except
Per Share Amounts)

Revenues                 $2,910          $3,259         $3,733        $2,865
Operating Income            521             622            824           215
Income Before
 Discontinued Operations,
 Extraordinary Items
 and Cumulative Effect      230             251            399            37
Net Income                  266             232            421            52
Earnings per Share Before
 Discontinued Operations,
 Extraordinary Items
 and Cumulative Effect***  0.72            0.77           1.23          0.12
Earnings per Share****     0.83            0.72           1.31          0.16

* Amounts for 2002 do not add to $0.06 earnings per share before Discontinued
Operations, Extraordinary Items and Cumulative Effect due to rounding and the
dilutive effect of shares issued in 2002.

**Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.

***Amounts for 2001 do not add to $2.85 earnings per share before Discontinued
Operations, 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:

<TABLE>
<CAPTION>



   Quarterly Periods Ended                   AEGCo      APCo        CSPCo       I&M        KPCo
                                                                (in thousands)
   2002
<S>                                          <C>      <C>         <C>        <C>        <C>
   March 31
    Operating Revenues                       $49,875  $462,605    $314,826   $352,235   $ 99,185
    Operating Income                           1,767    81,554      45,548     30,363     15,484
    Income Before
      Extraordinary Items                      1,893    55,341      33,858     11,058     10,246
    Net Income                                 1,893    55,341      33,858     11,058     10,246

   June 30
    Operating Revenues                       $53,356  $432,015    $343,813   $369,043   $ 92,164
    Operating Income                           1,504    65,224      58,040     19,865      9,550
    Income Before
      Extraordinary Items                      1,718    46,608      51,721      7,494      5,246
    Net Income                                 1,718    46,608      51,721      7,494      5,246

   September 30
    Operating Revenues                       $55,988  $474,282    $428,437   $421,472   $100,359
    Operating Income                           1,436    81,365      89,033     57,004     11,119
    Income Before Extraordinary Items          1,947    53,947      76,117     35,312      5,994
    Net Income                                 1,947    53,947      76,117     35,312      5,994

   December 31
    Operating Revenues                       $54,062  $445,568    $313,084   $384,014   $ 86,975
    Operating Income                           1,422    73,920      27,158     43,957      6,044
    Income (Loss) Before
      Extraordinary Items                      1,994    49,596      19,477     20,128       (919)
    Net Income (Loss)                          1,994    49,596      19,477     20,128       (919)

</TABLE>
<TABLE>
<CAPTION>


   Quarterly Periods Ended                    OPCo       PSO        SWEPCo      TCC        TNC
   -----------------------                    ----       ---        ------      ---        ---
                                                                (in thousands)
   2002
<S>                                         <C>       <C>         <C>        <C>        <C>
   March 31
    Operating Revenues                      $520,652  $148,986    $222,259   $278,910   $103,626
    Operating Income                          83,716     8,410      22,469     55,445     11,145
    Income (Loss) Before Extraordinary Items  64,051    (1,648)      8,159     24,445      3,992
    Net Income (Loss)                         64,051    (1,648)      8,159     24,445      3,992

   June 30
    Operating Revenues                      $521,365  $158,330    $263,074   $360,391   $104,452
    Operating Income                          61,046    20,201      31,988     64,319      5,547
    Income Before Extraordinary Items         55,348    11,620      18,155     33,535        675
    Net Income                                55,348    11,620      18,155     33,535        675

   September 30
    Operating Revenues                      $566,366  $230,098    $362,423   $546,260   $152,667
    Operating Income (Loss)                   97,210    50,710      60,254    118,204       (308)
    Income (Loss) Before Extraordinary Items  80,258    41,002      45,794     93,383     (4,193)
    Net Income (Loss)                         80,258    41,002      45,794     93,383     (4,193)

   December 31
    Operating Revenues                      $504,742  $256,233    $236,964   $504,932   $ 89,995
    Operating Income (Loss)                   56,357     5,400      27,758    155,765     (8,513)
    Income (Loss) Before
      Extraordinary Items                     20,366    (9,914)     10,884    124,578    (14,151)
    Net Income (Loss)                         20,366    (9,914)     10,884    124,578    (14,151)

</TABLE>
<TABLE>
<CAPTION>

   Quarterly Periods Ended                    AEGCo     APCo        CSPCo       I&M        KPCo
   -----------------------                    -----     ----        -----       ---        ----
                                                                (in thousands)
   2001
<S>                                          <C>      <C>         <C>        <C>        <C>
   March 31
    Operating Revenues                       $60,507  $501,204    $327,437   $387,813   $100,681
    Operating Income                           1,807    88,152      51,932     52,698     12,604
    Income Before Extaordinary Items           1,980    61,787      37,671     32,363      7,075
    Net Income                                 1,980    61,787      37,671     32,363      7,075

   June 30
    Operating Revenues                       $52,217  $430,412    $333,995   $382,234   $ 89,541
    Operating Income                           1,882    59,362      62,894     47,340      8,364
    Income Before Extrodinary Items            2,063    36,419      47,418     27,374      2,742
    Net Income                                 2,063    36,419      21,011     27,374      2,742

   September 30
    Operating Revenues                       $57,417  $434,450    $375,691   $398,457   $ 96,197
    Operating Income                           1,615    60,381      76,920     44,509     12,587
    Income Before Extraordinary Items          2,051    30,317      65,318     25,064      5,312
    Net Income                                 2,051    30,317      65,318     25,064      5,312

   December 31
    Operating Revenues                       $57,407  $418,193    $313,196   $358,493   $ 92,606
    Operating Income                           1,673    67,091      60,431     15,158     14,123
    Income (Loss) Before
      Extraordinary Items                      1,781    33,295      41,493     (9,013)     6,436
    Net Income (Loss)                          1,781    33,295      37,876     (9,013)     6,436

</TABLE>
<TABLE>
<CAPTION>

   Quarterly Periods Ended                   OPCo       PSO        SWEPCo      TCC        TNC
   -----------------------                   ----       ---        ------      ---        ---
                                                                (in thousands)
  2001
<S>                                         <C>       <C>         <C>        <C>        <C>
  March 31
    Operating Revenues                      $552,503  $225,080    $267,117   $432,910   $141,649
    Operating Income                          64,756     8,340      33,986     64,152      5,392
    Income (Loss) Before Extraordinary Items  53,397    (1,560)     19,869     35,031        891
    Net Income (Loss)                         53,397    (1,560)     19,869     35,031        891

  June 30
    Operating Revenues                      $512,196  $265,360    $271,748   $470,420   $139,228
    Operating Income                          47,067    21,942      32,649     82,351     12,428
    Income Before Extraordinary Items         32,094    11,921      17,784     52,518      6,133
    Net Income                                10,579    11,921      17,784     52,518      6,133
  September 30
    Operating Revenues                      $535,535  $325,373    $331,441   $527,117   $181,433
    Operating Income                          69,668    59,914      60,194    112,598     17,745
    Income Before Extraordinary Items         51,378    51,069      46,357     83,702     14,067
    Net Income                                51,378    51,069      46,357     83,702     14,067

  December 31
    Operating Revenues                      $497,871  $141,187    $231,020   $308,390   $ 94,148
    Operating Income (Loss)                   59,219     6,792      19,378     36,630     (2,175)
    Income (Loss) Before
      Extraordinary Items                     28,924    (3,671)      5,357     13,536     (8,781)
    Net Income (Loss)                         32,091    (3,671)      5,357     11,027     (8,781)

</TABLE>

Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
for the fourth quarter 2002 decreased $896 million from the prior year due to
the impairment loss and impairment value losses of approximately $1,188 million
(pre-tax) to reduce the valuation of under-performing assets. In addition to the
impairments that were recorded during the fourth quarter, a change in AEP's
Accumulated Other Comprehensive Income (Loss) of $585 million for pension
liability had a negative effect on each registrant's Consolidated Balance
Sheets.

25.  Trust Preferred Securities:

The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of PSO, SWEPCo and TCC were outstanding at December 31, 2002 and
December 31, 2001. They are classified on AEP's, PSO's, SWEPCo's and TCC's
Balance Sheets as Certain Subsidiary Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of
Such Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037.
TCC reacquired 490,000 trust preferred units during 2001.

<TABLE>
<CAPTION>


                                                   Units
                                                  Issued/                                           Description of
                                                Outstanding                                           Underlying
Business Trust              Security            At 12/31/02      Amount at December 31,        Debentures of Registrant
- --------------              --------            -----------      ----------------------        ------------------------
                                                                      2002           2001
                                                                        (in millions)
<S>                      <C>                    <C>                   <C>            <C>         <C>
CPL Capital I            8.00%, Series A         5,450,000            $136           $136        TCC, $141 million,
                                                                                                  8.00%, Series A

PSO Capital I            8.00%, Series A         3,000,000              75             75        PSO, $77 million,
                                                                                                  8.00%, Series A

SWEPCo Capital I         7.875%, Series A        4,400,000             110            110        SWEPCO, $113 million,
                                                ----------            ----           ----
                                                                                                  7.875%, Series A
                                                12,850,000            $321           $321
                                                ==========            ====           ====

</TABLE>

Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.

26.  Minority Interest in Finance Subsidiary:

In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.

Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.

The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.

The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.

Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.

Caddis and SubOne 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 SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's consolidated statements of operation and
consolidated balance sheets as Minority Interest in Finance Subsidiary.

AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.

As of December 31, 2002, we are continuing to review the application of FIN 46
as it relates to the Steelhead transaction.

27. Equity Units

In June 2002, AEP issued 6.9 million equity units at $50 per unit and received
proceeds of $345 million. Each equity unit consists of a forward purchase
contract and a senior note.

The forward purchase contracts obligate the holders to purchase shares of AEP
common stock on August 16, 2005. The purchase price per equity unit is $50. The
number of shares to be purchased under the forward purchase contract will be
determined under a formula based upon the average closing price of AEP common
stock near the stock purchase date. Holders may satisfy their obligation to
purchase AEP common stock under the forward purchase contracts by allowing the
senior notes to be remarketed or by continuing to hold the senior notes and
using other resources as consideration for the purchase of stock. If the holders
elect to allow the notes to be remarketed, the proceeds from the remarketing
will be used to purchase a portfolio of U.S. treasury securities that the
holders will pledge to AEP in order to meet their obligations under the forward
purchase contracts.

The senior notes have a principal amount of $50 each and mature on August 16,
2007. The senior notes are the collateral that secures the holders' requirement
to purchase common stock under the forward purchase contracts.

AEP will make quarterly interest payments on the senior notes at the initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP will make contract adjustment
payments to the purchaser at the annual rate of 3.50% on the forward purchase
contracts. The present value of the contract adjustment payments has been
recorded as a $31 million liability in Equity Unit Senior Notes offset by a
charge to Paid-in Capital. Interest payments on the senior notes are reported as
interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.

AEP applies the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that the
proceeds received as a result of the forward purchase contract are used to
repurchase outstanding shares.

28.  Jointly Owned Electric Utility Plant:

CSPCo, PSO, SWEPCo, TCC and TNC 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:

<TABLE>
<CAPTION>

                                                              Company's Share
                                                                December 31,
                                                              ---------------
                                                     2002                        2001
                                          --------------------------  ---------------------------
                                 Percent     Utility    Construction     Utility   Construction
                                   of         Plant         Work          Plant         Work
                                Ownership  in Service   in Progress    in Service   in Progress
                                --------- ------------ -------------  ------------ ------------
                                                (in thousands)              (in thousands)
<S>                                 <C>   <C>            <C>           <C>           <C>
CSPCo:
  W.C. Beckjord Generating Station
   (Unit No. 6)                     12.5  $   15,487     $    49       $   14,292    $   884
  Conesville Generating Station
   (Unit No. 4)                     43.5      81,960         279           81,697        494
  J.M. Stuart Generating Station    26.0     197,276      44,865          193,760     27,758
  Wm. H. Zimmer Generating Station  25.4     705,620      14,077          704,951      2,634
  Transmission                       (a)      61,187       2,281           61,476         91
                                          ----------     -------       ----------    -------
                                          $1,061,530     $61,551       $1,056,176    $31,861
                                          ==========     =======       ==========    =======

PSO:
  Oklaunion Generating Station
   (Unit No. 1)                     15.6  $   83,562     $   777       $   82,646    $   634
                                          ==========     =======       ==========    ========

SWEPCo:
  Dolet Hills Generating Station
   (Unit No. 1)                     40.2   $  235,366      1,313       $  234,747    $   675
  Flint Creek Generating Station
   (Unit No. 1)                     50.0       91,567      1,052           83,953        213
  Pirkey Generating Station
   (Unit No. 1)                     85.9      451,136      2,197          439,430     10,577
                                           ----------    -------       ----------    -------
                                           $  778,069    $ 4,562       $  758,130    $11,465
                                           ==========    =======       ==========    ========

TCC:
  Oklaunion Generating Station
  (Unit No. 1)                       7.8   $   38,055    $   369       $   37,728    $   318
  South Texas Project Generating
   Station (Units No. 1 and 2)      25.2    2,364,359     43,887        2,360,452     41,571
                                           ----------    -------       ----------    -------
                                           $2,402,414    $44,256       $2,398,180    $41,889
                                           ==========    =======       ==========    ========

TNC:
  Oklaunion Generating Station
   (Unit No. 1)                     54.7   $  277,946    $ 3,650       $  279,419    $ 1,651
                                           ==========    =======       ==========    =======



(a) Varying percentages of ownership.

</TABLE>



The accumulated depreciation with respect to each AEP registrant subsidiary's
share of jointly owned facilities is shown below:

                                December 31,
                                -----------
                           2002             2001
                           ----             ----
                               (in thousands)

CSPCo                    $436,683         $410,756
PSO                        49,085           35,653
SWEPCo                    450,057          392,728
TCC                       927,193          863,130
TNC                       102,542          100,430


29.  Related Party Transactions

AEP System Power Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement,
dated July 6, 1951, as amended (the Interconnection Agreement), defining how
they share the costs and benefits associated with their generating plants. This
sharing is based upon each company's "member-load-ratio," which is calculated
monthly on the basis of each company's maximum peak demand in relation to the
sum of the maximum peak demands of all five companies during the preceeding 12
months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been
parties to the AEP System Interim Allowance Agreement which provides, among
other things, for the transfer of SO2 Allowances associated with transactions
under the Interconnection Agreement. As part of AEP's restructuring settlement
agreement filed with FERC, under certain conditions CSPCo and OPCo would no
longer be parties to the Interconnection Agreement and certain other
modifications to its terms would also be made.

Power marketing and trading transactions (trading activities) are conducted by
the AEP Power Pool and shared among the parties under the Interconnection
Agreement. Trading activities involve the purchase and sale of electricity under
physical forward contracts at fixed and variable prices and the trading of
electricity contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional marketing area and
are typically settled by entering into offsetting contracts.

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

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

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



The following table shows the revenues derived from sales to the Pools and
direct sales to affiliates for years ended December 31, 2002, 2001 and 2000:

<TABLE>
<CAPTION>

                                          APCo    CSPCo       I&M      KPCo    OPCo     AEGCo
Related Party Revenues                                (in thousands)
<S>      <C>                            <C>      <C>      <C>        <C>      <C>      <C>
2002     Sales to East System Pool      $106,651 $42,986  $  197,525 $ 22,369 $397,248 $   -
         Sales to West System Pool        18,300  12,107      13,036    4,717   16,265     -
         Direct Sales To East Affiliates  58,213    -           -        -      50,599  213,071
         Direct Sales To West Affiliates    -       -           -        -        -        -
         Other                             3,313   2,109       3,577      878    1,090     -
                                        -------- -------  ---------- -------- -------- --------
            Total Revenues              $186,477 $57,202  $  214,138 $ 27,964 $465,202 $213,071
                                        ======== =======  ========== ======== ======== ========

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 Affiliates  54,777    -           -        -      55,450  227,338
         Direct Sales To West Affiliates  (3,133) (1,705)     (1,905)    (744)  (2,590)    -
         Other                             2,772  11,060       2,071    2,258    7,072     -
                                        -------- -------  ---------- -------- -------- --------
            Total Revenues              $171,285 $67,511  $  255,039 $ 42,366 $511,366 $227,338
                                        ======== =======  ========== ======== ======== ========

2000     Sales to East System Pool      $ 81,013 $36,884  $  200,474 $ 36,554 $502,140 $   -
         Sales to West System Pool         7,697   4,095       4,614    1,829    6,356     -
         Direct Sales To East Affiliates  59,106    -           -        -      66,487  227,983
         Direct Sales To West Affiliates   4,092   2,262       2,510      972    3,421     -
         Other                             2,770   6,124       2,710    2,466    4,043     -
                                        -------- -------  ---------- -------- -------- --------
            Total Revenues              $154,678 $49,365  $  210,308 $ 41,821 $582,447 $227,983
                                        ======== =======  ========== ======== ======== ========
</TABLE>


                                          PSO    SWEPCo      TCC      TNC
Related Party Revenues                            (in thousands)

2002     Sales to East System Pool       $  -    $  -     $     -    $  -
         Sales to West System Pool           674   1,334     18,416    1,280
         Direct Sales To East Affiliates     611     270        366      (23)
         Direct Sales To West Affiliates   6,047  75,674    956,751  228,404
         Other                             2,107  (4,979)    32,911   10,764
                                         ------- ------- ---------- --------
            Total Revenues               $ 9,439 $72,299 $1,008,444 $240,425
                                         ======= ======= ========== ========

2001     Sales to East System Pool       $     4 $  -    $      -   $   -
         Sales to West System Pool         3,317   8,073     19,865      322
         Direct Sales To East Affiliates   2,833   3,238      3,697    1,228
         Direct Sales To West Affiliates  30,668  67,930     12,617    9,350
         Other                               (51)     (4)     5,583    7,781
                                         ------- ------- ---------- --------
            Total Revenues               $36,771 $79,237 $   41,762 $ 18,681
                                         ======= ======= ========== ========

2000     Sales to East System Pool       $  -    $  -    $     -    $   -
         Sales to West System Pool         7,323   5,546     23,421      194
         Direct Sales To East Affiliates  (1,990) (3,008)    (3,348)  (1,116)
         Direct Sales To West Affiliates  21,995  62,178     12,516    7,645
         Other                           (12,680) (1,592)     5,163   11,931
                                         ------- ------- ---------- --------
            Total Revenues               $14,648 $63,124 $   37,752 $ 18,654
                                         ======= ======= ========== ========


The following table shows the purchased power expense incurred from purchases
from the Pools and affiliates for the years ended December 31, 2002, 2001, and
2000:

<TABLE>
<CAPTION>


                                                APCo     CSPCo    I&M      KPCo     OPCo
Related Party Purchases                                      (in thousands)
<S>      <C>                                   <C>      <C>      <C>      <C>       <C>
2002     Purchases from East System Pool       $233,677 $309,999 $ 83,918 $ 68,846  $70,338
         Purchases from West System Pool            337      219      237       86      297
         Direct Purchases from East Affiliates      583      387  149,569   64,070      519
         Direct Purchases from West Affiliates     -        -        -        -        -
                                               -------- -------- -------- --------  -------
             Total Purchases                   $234,597 $310,605 $233,724 $133,002  $71,154
                                               ======== ======== ======== ========  =======

2001     Purchases from East System Pool       $346,582 $292,034 $ 79,030 $ 61,816  $62,350
         Purchases from West System Pool            296      165      185       72      235
         Direct Purchases from East Affiliates     -        -     159,022   68,316     -
         Direct Purchases from West Affiliates     -        -        -        -        -
                                               -------- -------- -------- --------  -------
             Total Purchases                   $346,878 $292,199 $238,237 $130,204  $62,585
                                               ======== ======== ======== ========  =======

2000     Purchases from East System Pool       $355,305 $287,482 $106,644 $ 58,150  $50,339
         Purchases from West System Pool            455      260      285      108      390
         Direct Purchases from East Affiliates     -        -     158,537   69,446     -
         Direct Purchases from West Affiliates       14        8        9        3       12
                                               -------- -------- -------- --------  -------
             Total Purchases                   $355,774 $287,750 $265,475 $127,707  $50,741
                                               ======== ======== ======== ========  =======

</TABLE>
<TABLE>
<CAPTION>


                                                  PSO     SWEPCo    TCC     TNC
Related Party Purchases                                  (in thousands)
<S>      <C>                                    <C>      <C>      <C>     <C>
2002     Purchases from East System Pool        $   343  $  -     $   -   $  -
         Purchases from West System Pool            874     (456)   1,366  15,475
         Direct Purchases from East Affiliates   29,029   17,242    8,236   2,669
         Direct Purchases from West Affiliates   59,208   25,236   13,804  19,438
                                                -------  -------  ------- -------
             Total Purchases                    $89,454  $42,022  $23,406 $37,582
                                                =======  =======  ======= =======


2001     Purchases from East System Pool        $ 1,327  $  -     $   -   $     4
         Purchases from West System Pool          5,877    3,810      415  11,689
         Direct Purchases from East Affiliates    1,951    2,352   12,657   4,614
         Direct Purchases from West Affiliates   34,603    9,696   45,569  40,349
                                                -------  -------  ------- -------
             Total Purchases                    $43,758  $15,858  $58,641 $56,656
                                                =======  =======  ======= =======

2000     Purchases from East System Pool        $20,100  $  -     $   -   $  -
         Purchases from West System Pool          5,386    4,379    1,696  18,444
         Direct Purchases from East Affiliates    2,117      695      251      71
         Direct Purchases from West Affiliates   33,185    8,264   30,644  39,258
                                                -------  -------  ------- -------
             Total Purchases                    $60,788  $13,338  $32,591 $57,773
                                                =======  =======  ======= =======

</TABLE>

The above summarized related party revenues and expenses are reported in their
entirety, without elimination, and are presented as operating revenues
affiliated and purchased power affiliated on the statements of operations of
each AEP Power Pool member. Since all of the above pool members are included in
AEP's consolidated results, the above summarized related party transactions are
eliminated in total in AEP's consolidated revenues and expenses.




<PAGE>


AEP System Transmission Pool

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated
April 1, 1984, as amended (the Transmission Agreement), defining how they share
the costs associated with their relative ownership of the extra-high-voltage
transmission system (facilities rated 345 kv and above) and certain facilities
operated at lower voltages (138 kv and above). Like the Interconnection
Agreement, this sharing is based upon each company's "member-load-ratio."

The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 2002,
2001 and 2000:

            2002         2001          2000
            ----         ----          ----
                    (in thousands)

APCo     $(13,400)    $ (3,100)    $ (3,400)
CSPCo      42,200       40,200       38,300
I&M       (36,100)     (41,300)     (43,800)
KPCo       (5,400)      (4,600)      (6,000)
OPCo       12,700        8,800       14,900

PSO, SWEPCo, TCC, TNC and AEP Service Corporation are parties to a Transmission
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA
established a coordinating committee, which is charged with the responsibility
of overseeing the coordinated planning of the transmission facilities of the
west zone operating subsidiaries, including the performance of transmission
planning studies, the interaction of such subsidiaries with independent system
operators (ISO) and other regional bodies interested in transmission planning
and compliance with the terms of the Open Access Transmission Tariff (OATT)
filed with the FERC and the rules of the FERC relating to such tariff.

Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.

The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 2002,
2001 and 2000:

            2002         2001          2000
            ----         ----          ----
                    (in thousands)

PSO       $(4,200)    $ (4,000)    $ (3,300)
SWEPCo     (5,000)      (5,400)      (5,900)
TCC         3,600        3,900        3,400
TNC         5,600        5,500        5,800

AEP's System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP's east and west zone operating subsidiaries. Like the System
Integration Agreement, the System Transmission Integration Agreement functions
as an umbrella agreement in addition to the AEP Transmission Agreement and the
Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:

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

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

Unit Power Agreements and Other

A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides
for the sale by AEGCo to I&M of all the power (and the energy associated
therewith) available to AEGCo at the Rockport Plant unless it is sold to another
utility. I&M is obligated, whether or not power is available from AEGCo, to pay
as a demand charge for the right to receive such power (and as an energy charge
for any associated energy taken by I&M) such amounts, as when added to amounts
received by AEGCo from any other sources, will be at least sufficient to enable
AEGCo to pay all its operating and other expenses, including a rate of return on
the common equity of AEGCo as approved by FERC, currently 12.16%. The I&M Power
Agreement will continue in effect until the expiration of the lease term of Unit
2 of the Rockport Plant unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would have paid AEGCo under the terms of the
I&M Power Agreement for such entitlement. The KPCo unit power agreement expires
on December 31, 2004. This unit power agreement extends until December 31, 2009
for Unit 1 and until December 7, 2022 for Unit 2 if AEP's restructuring
settlement agreement filed with the FERC becomes operative.

APCo and OPCo, jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate expense accounts
on each company's consolidated statements of income. Each company's investment
in these plants is included in electric utility plant on its consolidated
balance sheets.

I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense. The amount of affiliated revenues
and affiliated expenses were:

                    Year Ended December 31,
                     2002     2001     2000
                     ----     ----     ----
Company                   (in millions)

I&M - revenues      $34.3    $30.2    $23.5
AEGCo - expense       7.8      8.5      8.8
APCo - expense       12.8     11.5      7.8
OPCo - expense        7.9     10.2      6.9
Memco - expense       5.7      -         -
AEP Energy Services   0.1      -         -

American Electric Power Service Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge basis, whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation for the use of equity
capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the PUHCA.

30. Subsequent Events (Unaudited):

Common Stock Offering - On February 27, 2003, AEP priced its offering of 50
million shares of common stock at a public offering price of $20.95 per share.
AEP has granted the underwriters an option to purchase an additional 7.5 million
shares of common stock to cover overallotments. The net proceeds from the sale
of these securities will be used to reduce debt and for general corporate
purposes.

Senior Notes Offering - During March 2003, AEP completed an offering of 5.375%
Series C Senior Notes which have a principal amount of $500 million and a
maturity date of March 15, 2010. The net proceeds from the offering will be used
to repay or redeem current maturities of long-term debt, a portion of our
minority interest in a financing subsidiary, and for general corporate purposes.




<PAGE>



REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, ACCOUNTING POLICIES  AND OTHER MATTERS


<PAGE>





The following is a combined presentation of management's discussion and analysis
of financial condition, accounting policies and other matters for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its subsidiary registrants is presented with
their financial statements earlier in this document. The following is a list of
sections of management's discussion and analysis of financial condition,
accounting policies and other matters and the registrant to which they apply:

Financial Condition         AEP, AEGCo, APCo,
                            CSPCo, I&M, KPCo,
                            OPCo, PSO, SWEPCo,
                            TCC, TNC

Critical Accounting         AEP, AEGCo, APCo,
  Policies                  CSPCo, I&M, KPCo,
                            OPCo, PSO, SWEPCo,
                            TCC, TNC

Market Risks                AEP, AEGCo, APCo,
                            CSPCo, I&M, KPCo,
                            OPCo, PSO, SWEPCo,
                            TCC, TNC

Industry Restructuring      AEP, APCo, CSPCo
                            I&M, KPCo, OPCo,
                            PSO, SWEPCo, TCC,
                            TNC

Litigation                  AEP, AEGCo, APCo,
                            CSPCo, I&M, KPCo,
                            OPCo, PSO, SWEPCo,
                            TCC, TNC

Environmental Concerns      AEP, AEGCo, APCo,
  and Issues                CSPCo, I&M, KPCo
                            OPCo, PSO,
                            SWEPCo, TCC, TNC

Other Matters               AEP, AEGCo, APCo,
                            CSPCo, I&M, KPCo,
                            OPCo, PSO,
                            SWEPCo, TCC, TNC

Financial Condition

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

Balance sheet capitalization ratios and cash flow ratios are principal
determinants of our credit quality.

Credit Ratings

The rating agencies have been conducting credit reviews of AEP and its
registrant subsidiaries. The agencies are also reviewing most companies in the
energy sector due to issues which impact the entire industry, not only AEP and
its subsidiaries.

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review were downgrades of
the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1
to Baa2, TCC from Baa1 to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1.
TNC, which had no senior unsecured notes outstanding at the time of the ratings
action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial
paper was also concurrently downgraded from P-2 to P-3. The completion of this
review was a culmination of earlier ratings action in 2002 that had included a
downgrade of AEP from Baa1 to Baa2 and the placement of five of the registrant
subsidiaries on negative outlook. With the completion of the reviews, Moody's
has placed AEP and its rated subsidiaries on stable outlook.

In February 2003, Standard & Poor's placed AEP's senior unsecured debt and
commercial paper ratings on credit watch with negative implications, and did the
same with the subsidiaries. S&P indicated that resolution regarding these
actions would come within a short time (see additional discussion in Financing -
Credit Ratings in Item 1 of Part I).

In 2002, Fitch Ratings Service downgraded both PSO and SWEPCo from A to A- for
the senior unsecured notes. Fitch has AEP and its subsidiaries on stable outlook
and the commercial paper rating is stable at F-2 (see additional discussion in
Financing - Credit Ratings in Item 1 of Part I).

Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the
following table:

Company                      Moody's    S&P      Fitch
- -------                      -------    ---      -----

APCo                         Baa1       BBB+     A-
CSPCo                        A3         BBB+     A
I&M                          Baa1       BBB+     BBB+
KPCo                         Baa1       BBB+     BBB+
OPCo                         A3         BBB+     A-
PSO                          A3         BBB+     A
SWEPCO                       A3         BBB+     A
TCC                          Baa1       BBB+     A
TNC                          A3         BBB+     A


Current short-term ratings are as follows:

Company                      Moody's    S&P      Fitch
- -------                      -------    ---      -----

AEP                          P-3        A-2      F-2


The current ratings for senior unsecured debt are listed in the following table:

Company                      Moody's    S&P      Fitch
- -------                      -------    ---      -----

AEP                          Baa3       BBB+     BBB+
AEP Resources*               Baa3       BBB+     BBB+
APCo                         Baa2       BBB+     BBB+
CSPCo                        A3         BBB+     A-
I&M                          Baa2       BBB+     BBB
KPCo                         Baa2       BBB+     BBB
OPCo                         A3         BBB+     BBB+
PSO                          Baa1       BBB+     A-
SWEPCO                       Baa1       BBB+     A-
TCC                          Baa2       BBB+     A-
TNC                          Baa1       BBB+     A-

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


AEP's common equity to total capitalization declined to 32% in 2002 from 36% in
2001 and 37% in 2000. Total capitalization includes long-term debt due within
one year, equity unit senior notes, minority interest and short-term debt.
Preferred stock at 1% remained unchanged. In 2002, long-term debt including
equity unit senior notes and trust preferred securities increased from 43% to
50% while Short-term Debt decreased from 17% to 14% and Minority Interest in
Finance Subsidiary remained unchanged at 3%. In 2001 Long-term Debt remained
unchanged while Short-term Debt decreased from 20% to 17% and Minority Interest
in Finance Subsidiary increased to 3%. In 2002, 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. Common stock was
issued in 2002 for stock options exercised and under an equity offering
(discussed in Financing Activity).

Liquidity
- ---------

Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of a company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing AEP and its subsidiaries' financial
needs in 2003.

As of December 31, 2002, we had an available liquidity position of $3.5 billion
as illustrated in the table below:

Credit Facilities
- -----------------
                       (in millions) Maturity
Commercial Paper Backup
  Lines of Credit          $2,500*       5/03
Commercial Paper Backup
  Lines of Credit           1,000        5/05
Corporate Separation
  Revolving Credit          1,725        4/03
Euro Revolving Credit
  Facilities                  315       10/03
                           ------
         Total              5,540

Cash
Liquidity Reserve           1,000**
                           ------
Total Credit Facilities
  and Cash                  6,540

Less: Commercial Paper
        Outstanding
      Corporate Separation  1,415
        Loans               1,300
      Euro Revolving
        Credit Loans          305
                           ------
Total Available Liquidity  $3,520
                           ======

 *  Contains one year term-out provision.
**  Unrestricted and excludes $213 million
     of operational cash on hand.


AEP and its subsidiaries' goal for 2003 is to use cash from operations to fund
capital expenditures, dividend payments and working capital requirements.
Short-term debt is used as an interim bridge for timing differences in the need
for cash or to fund debt maturities until permanent financing is arranged.

Short-term funding comes from the parent company's commercial paper program and
revolving credit facilities. Proceeds are loaned to the subsidiaries through
intercompany notes. AEP and its subsidiaries also operate a non-utility and
utility money pool to minimize the AEP System's external short-term funding
requirements and sell accounts receivable to provide liquidity for the domestic
electric subsidiaries. The commercial paper program is backed by $3.5 billion in
bank facilities of which $1 billion matures in May 2005. The remaining $2.5
billion matures in May 2003 and has a one-year term-out provision at AEP's
option. At December 31, 2002, approximately $1.4 billion of commercial paper was
outstanding. A portion of the commercial paper balance is related to funding of
debt maturities of the Ohio and Texas subsidiaries pending a permanent financing
program. The Ohio and Texas subsidiaries issued $2,025 million of senior
unsecured notes in February 2003 with maturity dates ranging from 2005 to 2033.
The commercial paper balance outstanding decreased in early 2003 due to
repayment with proceeds from these issuances.

AEP also has a $1.725 billion bank facility maturing in April 2003 that is
available for debt refinancing. At December 31, 2002, $1.3 billion was
outstanding under that facility. With the issuance of the permanent financing
for the Ohio and Texas subsidiaries mentioned above, this facility was repaid
and cancelled in February 2003.

AEP also has revolving credit facilities in place for 300 million Euros to
support the wholesale business in Europe. At December 31, 2002, the majority of
these facilities were drawn.

AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At December 31, 2002, AEP had $1 billion of cash available
for liquidity.

On December 6, 2002, we closed a 364-day, $425 million facility and used it to
partially repay the maturing interim financing for the U.K. generation plants
(FFF). The facility was secured by a pledge of the shares of AEP companies in
the FFF ownership chain and guaranteed by the parent company. A portion ($213
million) of the facility is due in May 2003. The remainder of the FFF interim
financing was repaid using a combination of existing funds and draws against the
Euro revolving credit facilities.

In total, we had approximately $6.5 billion in liquidity sources of which $3.5
billion were unused and available at December 31, 2002.

During 2002, cash flow from operations was $1.7 billion, including $21 million
from Net Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect, approximately $1.3 billion from depreciation, amortization,
deferred taxes, and deferred investment tax credits, approximately $1.1 billion
associated with asset, investment value and other impairments, offset by
additional working capital requirements of approximately $700 million. These
additional working capital requirements reflect the one time impact of the
discontinuance of the sale of accounts receivable for Texas companies and
billing delays related to the transition to customer choice in Texas, higher
margin requirements for gas trading, seasonal fuel inventory growth, and other
miscellaneous items. Construction expenditures were $1.7 billion including major
expenditures for emission control technology on several coal-fired generating
units (see discussion in Note 9). Dividends on common stock were $793 million.
Cash from operations, proceeds from the sale of SEEBOARD, CitiPower and the
Texas REPs and the issuance of common stock, common equity units, 15-year notes
for a wind generation project and transition funding bonds provided funds to
reduce debt, fund construction and pay dividends.

During 2001, AEP's cash flow from operations was $2.8 billion, including $885
million from Net Income Before Discontinued Operations, Extraordinary Items and
Cumulative Effect and $1.4 billion from depreciation, amortization, deferred
taxes and deferred investment tax credits. Capital expenditures including
acquisitions were $3.9 billion and dividends on common stock were $773 million.
Cash from operations less dividends on common stock financed 51% of capital
expenditures.

During 2001, the proceeds of AEP's $1.25 billion global notes issuance and
proceeds from the sale of a U.K. distribution company and two generating plants
provided cash to purchase assets, fund construction, retire debt and pay
dividends. Major construction expenditures include amounts for a wind generating
facility and emission control technology on several coal-fired generating units.
Asset purchases include HPL, coal mines, a barge line, a wind generating
facility and two coal-fired generating plants in the U.K. These acquisitions
accounted for the increase in total debt during 2001. Long-term funding
arrangements for specific assets are often complex and typically not completed
until after the acquisition.

The loss for 2002 resulted in a negative dividend payout ratio of 153%
reflecting the losses on sale and impairments of assets. Earnings for 2001
resulted in a dividend payout ratio of 80%, a considerable improvement over the
289% payout ratio in 2000. The abnormally high ratio in 2000 was the result of
the adverse impact on 2000 earnings from the Cook Plant extended outage and
related restart expenditures, merger costs and the write-off related to COLI and
non-regulated subsidiaries.

AEP and its subsidiaries generally use short-term borrowings to fund property
acquisitions and construction until long-term funding mechanisms are arranged.
Some acquisitions of existing business entities include the assumption of their
outstanding debt and certain liabilities. Sources of long-term funding include
issuance of AEP common stock, minority interest or long-term debt and
sale-leaseback or leasing arrange-ments. The domestic electric subsidiaries
generally issue short-term debt to provide for interim financing of capital
expenditures that exceed internally generated funds and periodically reduce
their outstanding short-term debt through issuances of long-term debt and
additional capital contributions from their parent company.

AEP's revolving credit agreements include covenants that require performance of
certain actions, including maintaining specified financial ratios.
Non-performance of these covenants may result in an event of default under these
credit agreements. At December 31, 2002, AEP complied with the covenants
contained in these credit agreements. In addition, a default under any other
agreement or instrument relating to debt outstanding in excess of $50 million is
an event of default under these credit agreements. An event of default under
these credit agreements would cause all amounts outstanding thereunder to be
immediately payable.


Financing Activity
- ------------------

Common Stock

In June 2002, AEP issued 16 million shares of common stock at $40.90 per share
through an equity offering and received net proceeds of $634 million. Proceeds
from the sale of equity units and common stock were used to pay down short-term
debt and establish a cash liquidity reserve fund.

Equity Units

In June 2002, AEP issued 6.9 million equity units at $50 per unit ($345
million). See Note 27 for additional information.

Debt

In February 2002, TCC issued $797 million of securitization notes that were
approved by the PUCT as part of Texas restructuring to recover generation
related regulatory assets. The proceeds were used to reduce TCC's debt and
equity.

In April 2002, AEP closed on a bridge loan facility consisting of a $1.125
million 364-day revolving credit facility and a $600 million 364-day term loan
facility to prepare for corporate separation. At year-end, $600 million was
borrowed under the term loan facility and $700 million was borrowed under the
revolving credit facility. Those amounts were repaid and the facility terminated
when bonds were issued by CSPCo, OPCo, TCC and TNC in February 2003.

In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The use of
proceeds from the above bonds was repayment of the bridge loan facility
mentioned above, repayment of short-term debt, and for general corporate
purposes.

In 2002, the following issuances were completed by the subsidiaries of AEP:


- ------------ ---------------- ----------- ----------- -------
                              Principal
                               Amount
                                (in
                                mil-
Com-pany      Type of Debt     lions)      Interest    Due
                                             Rate      Date
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
APCo         Unsecured Notes     $450       4.80%      2005
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
APCo         Unsecured Notes     200        4.32%*     2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Installment
I&M          Purchase             50        4.90%      2025
             Contracts
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
I&M          Unsecured Notes     150         6.0%      2032
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
I&M          Unsecured Notes     100        6 3/8%     2012
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
KPCo         Unsecured Notes     125        5.50%      2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
KPCo         Unsecured Notes      80        4.32%*     2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
KPCo         Unsecured Notes      70        4.37%*     2007
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
PSO          Unsecured Notes     200        6.00%      2032
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
             Senior
SWEPCo       Unsecured Notes     200        4.50%      2005
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Other        Notes Payable       121      6.20%-       2017
Subsid-iaries                               6.60%
- ------------ ---------------- ----------- ----------- -------
- ------------ ---------------- ----------- ----------- -------
Other        Revolving           305       Variable    2003
Subsid-iariesCredit
- ------------ ---------------- ----------- ----------- -------
- -------------------------------------------------------------
* Interest rate payable by subsidiary in U.S. dollars. While these companies do
not have an Australian rate obligation, there is an underlying interest rate to
Australian investors in Australian dollars of either 6% or a variable rate.
- -------------------------------------------------------------

The subsidiaries also redeemed approximately $2 billion of long-term debt in
2002. See the Schedule of Long-term Debt for each registrant in sections B to K
for details.

AEP uses money pools to meet the short-term borrowings for the majority of its
subsidiaries In addition, AEP also funds the short-term debt requirements of
other subsidiaries that are not included in the money pool. As of December 31,
2002, AEP had credit facilities totaling $3.5 billion to support its commercial
paper program. At December 31, 2002, AEP had $1.4 billion outstanding in
short-term borrowings subject to these credit facilities.

AEP Credit purchases, without recourse, the accounts receivable of most of the
domestic utility operating companies. AEP Credit's financing for the purchase of
receivables changed in December 2001. Starting December 31, 2001, AEP Credit
entered into a sale of receivables agreement. The agreement allows AEP Credit to
sell certain receivables and receive cash meeting the requirements of SFAS 140
for the receivables to be removed from AEP's and the subsidiaries' Balance
Sheets. At December 31, 2002, AEP Credit had $454 million sold under this
agreement. See Note 23 for further discussion.

Off-balance Sheet and Minority Interest Arrangements

AEP and its subsidiaries enter into off-balance sheet arrangements for various
reasons ranging from accelerating cash collections, reducing operational expense
to spreading risk of loss to third parties. The following identifies significant
off-balance sheet arrangements:

Power Generation Facility

AEP has entered into agreements with Katco Funding L.P. (Katco), an unrelated
unconsolidated special purpose entity. Katco has an aggregate financing
commitment of $525 million and a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97% is debt
from a syndicate of banks. Katco was formed to develop, construct, finance and
lease a power generation facility to AEP. Katco will own the power generation
facility and lease it to AEP after construction is completed. The lease will be
accounted for as an operating lease (see Note 22), therefore neither the
facility nor the related obligations are reported on AEP's Consolidated Balance
Sheets. Payments under the operating lease are expected to commence in the first
quarter of 2004. AEP will in turn sublease the facility to Dow Chemical Company
(DOW), which will use the energy produced by the facility and sell excess
energy. AEP has agreed to purchase the excess energy from DOW for resale. The
use of Katco allows AEP to limit its risk associated with the power generation
facility once the construction phase has been completed.

AEP is the construction agent for Katco, and is responsible for completing
construction by December 31, 2003, subject to unforeseen events beyond AEP's
control.

In the event the project is terminated before completion of construction, AEP
has the option to either purchase the facility for 100% of project costs or
terminate the project and make a payment to Katco for 89.9% of project costs.

The operating lease between Katco and AEP commences on the commercial operation
date of the facility and continues until November 2006. The lease contains
extension options subject to the approval of Katco, and if all extension options
were exercised, the total term of the lease would be 30 years. AEP's lease
payments to Katco are sufficient for Katco to make required debt payments and
provide a return to the investors of Katco. At the end of each lease term, AEP
may renew the lease at fair market value subject to Katco's approval, purchase
the facility at its original construction cost, or sell the facility, on behalf
of Katco, to an independent third party. If the facility is sold and the
proceeds from the sale are insufficient to repay Katco, AEP may be required to
make a payment to Katco for the difference between the proceeds from the sale
and the obligations of Katco, up to 82% of the project's cost. AEP has
guaranteed a portion of the obligations of its subsidiaries to Katco during the
construction and post-construction periods.

As of December 31, 2002, project costs subject to these agreements totaled $360
million, and total costs for the completed facility are expected to be
approximately $510 million. For the 30-year extended lease term, the lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently
as market interest rates increase, the payments under this operating lease will
also increase. Annual payments of approximately $12 million represent future
minimum payments during the initial term calculated using the indexed LIBOR rate
(1.38% at December 31, 2002). The Power Generation Facility collateralizes the
debt obligation of Katco. AEP's maximum exposure to loss as a result of its
involvement with Katco is 100% during the construction phase and up to 82% once
the construction is completed. Maximum loss is deemed to be remote due to the
collateralization.

It is reasonably possible that AEP will consolidate Katco in the third quarter
of 2003, as a result of the issuance of FASB Interpretation No. 46
"Consolidation of Variable Interest Entities" (FIN 46). Upon consolidation, AEP
would record the assets, liabilities, depreciation expense, minority interest
and debt interest expense. AEP would eliminate operating lease expense. The
sublease to DOW would not be affected by this consolidation.

The lease payments and the guarantee of construction commitments are included in
the Other Commercial Commitments table below.

Minority Interest in Finance Subsidiary
- ---------------------------------------

In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC (SubOne)
and Caddis Partners, LLC (Caddis). SubOne is a wholly owned consolidated
subsidiary of AEP that was capitalized with the assets of Houston Pipe Line
Company, Louisiana Interstate Gas Company (AEP subsidiaries) and $321.4 million
of AEP Energy Services Gas Holding Company (AEP Gas Holding is an AEP subsidiary
and parent of SubOne) preferred stock, that is convertible into AEP common stock
at market price on a dollar-for-dollar basis. Caddis was capitalized with $2
million cash and a subscription agreement that represents an unconditional
obligation to fund $83 million from SubOne and $750 million from Steelhead
Investors LLC ("Steelhead" - non-controlling preferred member interest). As
managing member, SubOne consolidates Caddis. Steelhead is an unconsolidated
special purpose entity and has a capital structure of $750 million of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from a syndicate of banks. The use of Steelhead allows AEP to
limit its risk associated with Houston Pipe Line Company and Louisiana
Intrastate Gas Company.

Under the provisions of the Caddis formation agreements, Steelhead receives a
quarterly preferred return equal to an adjusted floating reference rate (4.784%
and 4.413% for the quarters ended December 31, 2002 and 2001, respectively).
Caddis has the right to redeem Steelhead's interest at any time.

The $750 million invested in Caddis by Steelhead was loaned to SubOne. This
intercompany loan to SubOne is due August 2006, and is supported by the natural
gas pipeline assets of SubOne, a cash reserve fund of SubOne and SubOne's $321.4
million of preferred stock in AEP Gas Holding. The preferred stock is
convertible into AEP common stock upon the occurrence of certain events
including AEP's stock price closing below $18.75 for ten consecutive trading
days. AEP can elect not to have the transaction supported by such preferred
stock if SubOne were to reduce its loan with Caddis by $225 million. The credit
agreement between Caddis and SubOne contains covenants that restrict certain
incremental liens and indebtedness, asset sales, investments, acquisitions, and
distributions. The credit agreement also contains covenants that impose minimum
financial ratios. Non-performance of these covenants may result in an event of
default under the credit agreement. Through December 31, 2002, we have complied
with the covenants contained in the credit agreement. In addition, a default
under any other agreement or instrument relating to AEP and certain
subsidiaries' debt outstanding in excess of $50 million is an event of default
under the credit agreement.

The initial period of Steelhead's investment in Caddis is through August 2006.
At the end of the initial period, Caddis will either reset Steelhead's return
rate, re-market Steelhead's interests to new investors, redeem Steelhead's
interests, in whole or in part including accrued return, or liquidate Caddis in
accordance with the provisions of applicable agreements.

Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events including a default in the payment of the preferred
return, Steelhead's rights include: forcing a liquidation of Caddis and acting
as the liquidator, and requiring the conversion of the AEP Gas Holding preferred
stock into AEP common stock. If Steelhead exercised its rights to force Caddis
to liquidate under these conditions, then AEP would evaluate whether to
refinance at that time or relinquish the assets that support the intercompany
loan to Caddis. Liquidation of Caddis could negatively impact AEP's liquidity.

Caddis and SubOne 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 SubOne are consolidated with AEP for financial reporting
purposes. Steelhead's investment in Caddis and payments made to Steelhead from
Caddis are currently reported on AEP's income statement and balance sheet as
Minority Interest in Finance Subsidiary.

AEP's maximum exposure to loss as a result of its involvement with Steelhead is
$321.4 million of preferred stock, $83 million under the subscription agreement
to Caddis for any losses incurred by Caddis and the cash reserve fund balance of
$34 million (as of December 31, 2002) due Caddis for default under the
intercompany loan agreement. AEP can reduce its maximum exposure related to the
preferred stock by a reduction of $225 million of the intercompany loan.

As of December 31, 2002, management is continuing to review the application of
FIN 46 as it relates to the Steelhead transaction.

AEP Credit
- ----------

AEP Credit entered into a sale of receivables agreement with a group of banks
and commercial paper conduits. Under the sale of receivables agreement, which
expires May 28, 2003, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140
allowing the receivables to be taken off of AEP Credit's balance sheet and
allowing AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities in
accordance with GAAP. We continue to service the receivables. This off-balance
sheet transaction was entered into to allow AEP Credit to repay its outstanding
debt obligations, continue to purchase the AEP operating companies' receivables,
and accelerate its cash collections.

At December 31, 2002, the sale of receivables agreement provided the banks and
commercial paper conduits would purchase a maximum of $600 million of
receivables from AEP Credit, of which $454 million was outstanding. As
collections from receivables sold occur and are remitted, the outstanding
balance for sold receivables is reduced and as new receivables are sold, the
outstanding balance of sold receivables increases. All of the receivables sold
represented affiliate receivables. The commitment's new term under the sale of
receivables agreement will remain at $600 million until May 28, 2003. AEP Credit
maintains a retained interest in the receivables sold and this interest is
pledged as collateral for the collection of the receivables sold. The fair value
of the retained interest is based on book value due to the short-term nature of
the accounts receivables less an allowance for anticipated uncollectible
accounts.

See Note 23 "Lines of Credit and Sale of Receivables" for further disclosure.

Gavin Plant's flue gas desulfurization system (Gavin Scrubber)
- -------------------------------------------------------------

OPCo has entered into an agreement with JMG Funding LLP (JMG) an unrelated
unconsolidated special purpose entity. JMG has a capital structure of which 3%
is equity from investors with no relationship to AEP or any of its subsidiaries
and 97% is debt from pollution control bonds and other bonds. JMG owns the Gavin
Scrubber and leases it to OPCo. The lease is accounted for as an operating lease
with the payment obligations included in the lease footnote. Payments under the
operating lease are based on JMG's cost of financing (both debt and equity) and
include an amortization component plus the cost of administration. Neither OPCo
nor AEP has an ownership interest in JMG and does not guarantee JMG's debt.

At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber. The initial
15-year lease term is non-cancelable. At the end of the initial term, OPCo can
renew the lease, purchase the Gavin Scrubber (terms previously mentioned), or
sell the Gavin Scrubber. In case of a sale at less than the adjusted acquisition
cost, OPCo must pay the difference to JMG.

The use of JMG allows OPCo to enter into an operating lease while keeping the
tax benefits otherwise associated with a capital lease. As of December 31, 2002,
unless the structure of this arrangement is changed, it is reasonably possible
that AEP and OPCo will consolidate JMG in the third quarter of 2003 as a result
of the issuance of FIN 46. Upon consolidation, AEP and OPCo would record the
assets, liabilities, depreciation expense, minority interest and debt interest
expense of JMG. AEP and OPCo would eliminate operating lease expense. AEP's and
OPCo's maximum exposure to loss as a result of their involvement with JMG is
approximately $560 million of outstanding debt and equity of JMG as of December
31, 2002.

Rockport Plant Unit 2
- ---------------------

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. AEGCo, I&M
nor AEP has ownership interest in the Owner Trustee and do not guarantee its
debt.




<PAGE>


Summary Obligation Information

The contractual obligations of AEP and its subsidiaries include amounts reported
on the Consolidated Balance Sheets and other obligations disclosed in the
footnotes. The following table summarizes AEP's contractual cash obligations at
December 31, 2002:

<TABLE>
<CAPTION>

                                                                    Payments Due by Period
                                                                        (in millions)
Contractual Cash Obligations             Less Than 1 year      2-3 years    4-5 years      After 5 years    Total
- ----------------------------             ----------------      ---------    ---------      -------------    -----
<S>                                           <C>             <C>            <C>              <C>         <C>
Long-term Debt                                $1,633          $1,817         $2,316           $4,354      $10,120
Short-term Debt                                3,164            -              -                -           3,164
Equity Unit Senior Notes                        -               -               376             -             376
Trust Preferred Securities                      -               -              -                 321          321
Minority Interest In Finance
 Subsidiary (a)                                 -               -               759             -             759
Preferred Stock Subject to
 Mandatory Redemption                           -               -               -                 84           84
Capital Lease Obligations                         70              90             50               18          228
Unconditional Purchase
 Obligations (b)                               1,405           1,810            989            1,513        5,717
Noncancellable Operating Leases                  305             523            479            2,462        3,769
                                              ------          ------         ------           ------      -------
  Total Contractual
   Cash Obligations                           $6,577          $4,240         $4,969           $8,752      $24,538
                                              ======          ======         ======           ======      =======
</TABLE>

(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.

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 K for the timing of debt payment obligations
and the lease footnote (Note 22) in section L for the timing of rent payments.

The special purpose entities (SPE), described under "Off-Balance Sheet and
Minority Interest Arrangements" above, 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 Scrubber, the permanent financing of HPL, and the
sale of accounts receivable all use SPEs. Neither AEP nor any AEP related
parties have an ownership interest in the SPE. AEP does not guarantee the debt
of these entities. These SPEs are not consolidated in AEP's or the subsidiaries'
financial statements in accordance with GAAP. As a result, neither the assets
nor the debt of the SPE are included on AEP's Consolidated Balance Sheets. The
future cash obligations payable to the SPEs are included in the above table.

In addition to the amounts disclosed in the contractual cash obligations table
above, AEP and its 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, 2002 under these agreements are
summarized in the table below:

<TABLE>
<CAPTION>

                                                    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
- ----------------------------             ----------------      ---------    ---------      -------------    -----

<S>                                           <C>                 <C>        <C>               <C>          <C>
Standby Letters of Credit (a)                 $  125              $  1       $ -               $ 40         $  166
Guarantees of the Performance
  of Ooutside Parties (b)                         13                17        325               137            492
Guarantess of Our Performance                  1,159                 2         82                 9          1,252
Construction of Generating and
 Transmission Facilities for
 Third Parties (c)                               671                  83       47                67            868
Other Commercial
 Commitments (d)                                  14                53         11                -              78
                                              ------              ----       ----              ----         ------
Total Commercial Commitments                  $1,982              $156       $465              $253         $2,856
                                              ======              ====       ====              ====         ======
</TABLE>

(a) AEP has standby letters of credit to third parties. These letters of credit
    cover gas and electricity trading contracts, various construction contracts
    and credit enhancement for issued bonds. All of these letters of credit
    were issued at a subsidiary level of AEP in the subsidiaries' ordinary
    course of business. The maximum future payments of these letters of credit
    are $166 million with maturities ranging from January 2003 to December
    2007. There is no liability recorded for these letters of credit in
    accordance with FIN 45. Since AEP is the parent to all these subsidiaries,
    it holds all assets of the subsidiary as collateral. There is no recourse
    to third parties in the event these letters of credit are drawn.
(b) These amounts are the balances drawn, not the maximum guarantee disclosed in
    Note 10.
(c) As construction agent for third party owners of power plants and
    transmission facilities, AEP has committed by contract terms to complete
    construction by dates specified in the contracts. Should AEP default on
    these obligations, financial payments could be up to 100% of contract
    value (amount shown in table) or other remedies required by contract terms.
(d) Represents estimated future payments for power to be generated at facilities
    under construction.


With the exceptions of SWEPCo's guarantee of an unaffiliated mine operator's
obligations (payable upon their default) of $148 million at December 31, 2002,
and OPCo's obligations under a power purchase agreement of $14 million each year
in 2003 through 2005, the obligations in the above table are commitments of AEP
and its non-registrant subsidiaries.

OPCo has entered into a 30-year power purchase agreement for electricity
pro-duced by an unaffiliated entity's three-unit natural gas fired plant. The
plant was completed in 2002 and the agreement will terminate in 2032. Under the
terms of the agreement, OPCo has the option to run the plant until December 31,
2005 taking 100% of the power generated and making monthly capacity payments.
The capacity payments are fixed through December 2005 at $1.2 million per month.
For the remainder of the 30 year contract term, OPCo will pay the variable costs
to generate the electricity it purchases which could be up to 20% of the plant's
capacity. The estimated fixed payments are included in the Other Commercial
Commitments table shown above.

Expenditures for domestic electric utility construction are estimated to be $4
billion for the next three years. Approximately 90% of those construction
expenditures are expected to be financed by internally generated funds.

Construction expenditures for certain registrant subsidiaries for the next three
years are:

                              Construction
          Projected           Expenditures
          Construction        Financed with
          Expenditures       Internal Funds
          ------------       --------------
          (in millions)

APCo        $1,005                 70%
I&M            601                 90
OPCo           733                100
SWEPCo         351                100
TCC            419                100

APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Certificates have been issued by both the WVPSC and the Virginia
SCC authorizing construction and operation of the line. On December 31, 2002,
the United States Forest Service issued a final environmental impact statement
and record of decision to allow the use of federal lands in the Jefferson
National Forest for construction of a portion of the line. APCo expects
additional state and federal permits to be issued in the first half of 2003.
Through December 31, 2002, APCo has invested approximately $51 million in this
effort. The line is estimated to cost $287 million including amounts spent to
date with completion in 2006. If the required permits are not obtained and the
line is not constructed, the $51 million investment would be written off
adversely affecting future results of operations and cash flows.

Pension Plans
- -------------

AEP maintains qualified defined benefit pension plans (Qualified Plans), which
cover substantially all non-union and certain union associates, and unfunded
excess plans to provide benefits in excess of amounts permitted to be paid under
the provisions of the tax law to participants in the Qualified Plans.
Additionally, AEP has entered into individual retirement agreements with certain
current and retired executives that provide additional retirement benefits.

AEP's pension income for all pension plans approximated $69 million and $44
million for the years ended December 31, 2001 and December 31, 2002,
respectively, and is calculated based upon a number of actuarial assumptions,
including an expected long-term rate of return on the Qualified Plans' assets of
9%. In developing the expected long-term rate of return assumption, AEP
evaluated input from actuaries and investment consultants, including their
reviews of asset class return expectations as well as long-term inflation
assumptions. Projected returns by such actuaries and consultants are based on
broad equity and bond indices. AEP also considered historical returns of the
investment markets as well as AEP's 10-year average return (for the period ended
2002) of 8.8%. AEP anticipates that the investment managers will continue to
generate long-term returns of at least 9.0%. The expected long-term rate of
return on the Qualified Plans' assets is based on an asset allocation assumption
of 70% with equity managers, with an expected long-term rate of return of 10.5%,
and 28% with fixed income managers, with an expected long-term rate of return of
6%, and 2% in cash and short term investments with an expected rate of return of
3%. Because of market fluctuation, the actual asset allocation as of December
31, 2002 was 67% with equity managers and 32% with fixed income managers and 1%
in cash. AEP believes, however, that the long-term asset allocation on average
will approximate 70% with equity managers, 28% with fixed income managers and
the remaining 2% in cash. AEP regularly reviews the actual asset allocation and
periodically rebalances the investments to our targeted allocation when
considered appropriate. AEP continues to believe that 9.0% is a reasonable
long-term rate of return on the Qualified Plans' assets, despite the recent
market downturn in which the Qualified Plans' assets had a loss of 11.2% for the
twelve months ended December 31, 2002. AEP will continue to evaluate the
actuarial assumptions, including the expected rate of return, at least annually,
and will adjust as necessary.

AEP bases its determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of December 31, 2002 AEP had
cumulative losses of approximately $879 million which remain to be recognized in
the calculation of the market-related value of assets. These unrecognized net
actuarial losses result in increases in the future pension costs depending on
several factors, including whether such losses at each measurement date exceed
the corridor in accordance with SFAS No. 87, "Employers' Accounting for
Pensions."

The discount rate that AEP utilizes for determining future pension obligations
is based on a review of long-term bonds that receive one of the two highest
ratings given by a recognized rating agency. The discount rate determined on
this basis has decreased from 7.25% at December 31, 2001 to 6.75% at December
31, 2002. Due to the effect of the unrecognized actuarial losses and based on an
expected rate of return on the Qualified Plans' assets of 9.0%, a discount rate
of 6.75% and various other assumptions, AEP estimates that the pension expense
for all pension plans will approximate $2 million, $46 million and $97 million
in 2003, 2004 and 2005, respectively. Future actual pension expense will depend
on future investment performance, changes in future discount rates and various
other factors related to the populations participating in the pension plans.

Lowering the expected long-term rate of return on the Qualified Plans' assets by
..5% (from 9.0% to 8.5%) would have reduced pension income for 2002 by
approximately $19 million. Lowering the discount rate by 0.5% would have reduced
pension income for 2002 by approximately $8 million.

The value of the Qualified Plans' assets has decreased from $3.438 billion at
December 31, 2001 to $2.795 billion at December 31, 2002. The Qualified Plans
paid out $272 million in benefits to plan participants during 2002 (nonqualified
plans paid out $6 million in benefits). The investment returns and declining
discount rates have changed the status of the Qualified Plans from overfunded
(plan assets in excess of projected benefit obligations) by $146 million at
December 31, 2001 to an underfunded position (plan assets are less than
projected benefit obligations) of $788 million at December 31, 2002. Due to the
Qualified Plans currently being underfunded, AEP recorded a charge to Other
Comprehensive Income (OCI) of $585 million, and a Deferred Income Tax Asset of
$315 million, offset by a Minimum Pension Liability of $662 million and a
reduction to prepaid costs and intangible assets of $238 million. The charge to
OCI does not affect earnings or cash flow. AEP is in full compliance with all
regulations governing such plans including all Employee Retirement Income
Security Act of 1974 laws. Because of the recent reductions in the funded status
of the Qualified Plans, AEP expects to make cash contributions to the Qualified
Plans of approximately $66 million in 2003 increasing to approximately $108
million per year by 2005.

Critical Accounting Policies

In the ordinary course of business, AEP and its registrant subsidiaries have
made a number of estimates and assumptions relating to the reporting of results
of operations and financial condition in the preparation of their financial
statements in conformity with accounting principles generally accepted in the
United States of America. Actual results could differ significantly from those
estimates under different assumptions and conditions. They believe that the
following discussion addresses the most critical accounting policies, which are
those that are most important to the portrayal of the financial condition and
results and require management's most difficult, subjective and complex
judgments, often as a result of the need to make estimates about the effect of
matters that are inherently uncertain.

Revenue Recognition
- -------------------
Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, OPCo, CSPCo,
TCC, TNC and SWEPCo) reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide for refunds to customers
that have not yet been made.

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

Traditional Electricity Supply and Delivery Activities - Revenues are recognized
on the accrual or settlement basis for normal retail and wholesale electricity
supply sales and electricity transmission and distribution delivery services.
The revenues are recognized in our statement of operations when the energy is
delivered to the customer and include unbilled as well as billed amounts. In
general, expenses are recorded when purchased electricity is received and when
expenses are incurred.

Domestic Gas Pipeline and Storage Activities - Revenues are recognized from
domestic gas pipeline and storage services when gas is delivered to contractual
meter points or when services are provided. Transportation and storage revenues
also include the accrual of earned, but unbilled and/or not yet metered gas.

Substantially all of the forward gas purchase and sale contracts, excluding
wellhead purchases of natural gas, swaps and options for the domestic pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in the results of
operations, appropriately discounted and net of applicable credit and liquidity
reserves.

Energy Marketing and Trading Activities -In 2000, 2001 and throughout the
majority of 2002, AEP engaged in broad non-regulated wholesale electricity,
natural gas and other commodity marketing and trading transactions (trading
activities). AEP's trading activities involved the purchase and sale of energy
under forward contracts at fixed and variable prices and the buying and selling
of financial energy contracts which include exchange traded futures and options
and over-the-counter options and swaps. We used the mark-to-market method of
accounting for trading activities as required by EITF Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10). Under the mark-to-market method of accounting, gains
and losses from settlements of forward trading contracts are recorded net in
revenues. For energy contracts not yet settled, whether physical or financial,
changes in fair value are recorded net as revenues. Such fair value changes are
referred to as unrealized gains and losses from mark-to-market valuations. When
positions are settled and gains and losses are realized, the previously recorded
unrealized gains and losses from mark-to-market valuations are reversed.
Unrealized mark-to-market gains and losses are included in the Balance Sheets as
"Energy Trading and Derivative Contracts." In October 2002, management announced
plans to focus on wholesale markets where we own assets. A portion of the
revenues and costs associated with AEP's wholesale electricity trading
activities is allocated to TCC, SWEPCo, PSO and TNC and to members of the AEP
Power Pool (APCo, CSPCo, I&M, KPCo and OPCo); however, TCC, SWEPCo, PSO and TNC
are only allocated a portion of the forward transactions.

AEP's cost-based rate-regulated electric public utility companies (I&M, KPCo,
PSO, and a portion of TNC and SWEPCo) defer, as regulatory liabilities
(unrealized gains) or regulatory assets (unrealized losses), changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area. AEP's traditional marketing area is up to two transmission
systems from the AEP service territory. For contracts which are outside of AEP's
traditional marketing area, the change in fair value is included in nonoperating
income on a net basis.

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

For I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract settles
the total gain or loss is realized in cash and the impact on the income
statement depends on whether the contract's delivery points are within or
outside of AEP's traditional marketing area. For contracts with delivery points
in AEP's traditional marketing area, the total gain or loss realized in cash for
sales and the cost of purchased energy are included in revenues on a net basis.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts in AEP's traditional marketing area are deferred as
regulatory liabilities (gains) or regulatory assets (losses). For contracts with
delivery points outside of AEP's traditional marketing area only the difference
between the accumulated unrealized net gains or losses recorded in prior periods
and the cash proceeds is recognized in the income statement as nonoperating
income. Prior to settlement, changes in the fair value of physical forward sale
and purchase contracts with delivery points outside of AEP's traditional
marketing area are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.

For APCo, CSPCo and OPCo, depending on whether the delivery point for the
electricity is in AEP's traditional marketing area or not determines where the
contract is reported in the income statement. Physical forward trading sale and
purchase contracts with delivery points in AEP's traditional marketing area are
included in revenues on a net basis. Prior to settlement, changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area are also included in revenues on a net basis. Physical forward
sale and purchase contracts for delivery outside of AEP's traditional marketing
area are included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts with delivery points outside of AEP's traditional marketing area are
included in nonoperating income on a net basis.

Continuing with the above example for AEP, APCo, CSPCo, OPCo, TCC, and a portion
of TNC and SWEPCo, assume that later in January or sometime in February through
July we enter into an offsetting forward contract to buy energy in July. If we
do nothing else with these contracts until settlement in July and if the
commodity type, volumes, delivery point, schedule and other key terms match,
then the difference between the sale price and the purchase price represents a
fixed value to be realized when the contracts settle in July. Mark-to-market
accounting for these contracts from this point forward will have no further
impact on operating results but has an offsetting and equal effect on trading
contract assets and liabilities. If the sale and purchase contracts do not match
exactly as to commodity type, volumes, delivery point, schedule and other key
terms, then there could be continuing mark-to-market effects on revenues from
recording additional changes in fair values using MTM accounting.

For AEP, the trading of energy options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse to revenues the prior
cumulative unrealized net gain or loss. APCo, CSPCo, I&M, KPCo and OPCo also
have financial transactions, but record the unrealized gains and losses, as well
as the net proceeds upon settlement, in nonoperating income.

The fair values of open short-term trading contracts are based on exchange
prices and broker quotes. We mark-to-market open long-term trading contracts
based primarily on valuation models that estimate future energy prices based on
existing market and broker quotes and supply and demand market data and
assumptions. The fair values determined are reduced by the appropriate valuation
adjustments for items such as discounting, liquidity and credit quality. Credit
risk is the risk that the counterparty to the contract will fail to perform or
fail to pay amounts due to AEP. Liquidity risk represents the risk that
imperfections in the market will cause the price to be less than or more than
what the price should be based purely on supply and demand. There are inherent
risks related to the underlying assumptions in models used to fair value open
long-term trading contracts. We have independent controls to evaluate the
reasonableness of our valuation models. However, energy markets, especially
electricity markets, are imperfect and volatile. Unforeseen events can and will
cause reasonable price curves to differ from actual prices throughout a
contract's term and at the time contracts settle. Therefore, there could be
significant adverse or favorable effects on future results of operations and
cash flows if market prices are not consistent with AEP's approach at estimating
current market consensus for forward prices in the current period. This is
particularly true for long-term contracts.

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

Volatility in energy commodities markets affects the fair values of all of our
open trading and derivative contracts exposing us to market risk and causing our
results of operations to be subject to volatility. See Note 17, "Risk
Management, Financial Instruments and Derivatives" for a discussion of the
policies and procedures used to manage our exposure to market and other risks
from trading activities.

Given the previously discussed reduction in AEP's trading activities, the impact
of mark-to-market accounting on our financial statements is expected to decline
in future periods.

Long-Lived Assets
- -----------------

Long-lived assets, including fixed assets and intangibles, are evaluated
periodically for impairment whenever events or changes in circumstances indicate
that the carrying amount of any such assets may not be recoverable. If the sum
of the undiscounted cash flows is less than the carrying value, we recognize an
impairment loss, measured as the amount by which the carrying value exceeds the
fair value of the asset. The estimate of cash flow is based upon, among other
things, certain assumptions about expected future operating performance. Our
estimates of undiscounted cash flow may differ from actual cash flow due to,
among other things, technological changes, economic conditions, changes to its
business model or changes in its operating performance.

Pension Benefits
- ----------------

AEP sponsors pension and other retirement plans in various forms covering
substantially all employees who meet eligibility requirements. Several
statistical and other factors which attempt to anticipate future events are used
in calculating the expense and liability related to the plans. These factors
include assumptions about the discount rate, expected return on plan assets and
rate of future compensation increases as determined by management, within
certain guidelines. In addition, AEP's actuarial consultants also use subjective
factors such as withdrawal and mortality rates to estimate these factors. The
actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or
longer or shorter life spans of participants. These differences may result in a
significant impact to the amount of pension expense recorded.

New Accounting Pronouncements
- -----------------------------

See  Note 1 to the  consolidated  financial  statements  for a  discussion
of  significant  accounting  policies  and  new  accounting pronouncements.

Market Risks

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

Policies and procedures have been established to identify, assess, and manage
market risk exposures in our day to day operations. Our risk policies have been
reviewed with the Board of Directors, approved by a Risk Executive Committee and
administered by a Chief Risk Officer. The Risk Executive Committee establishes
risk limits, approves risk policies, assigns responsibilities regarding the
oversight and management of risk and monitors risk levels. This committee
receives daily, weekly, and monthly reports regarding compliance with policies,
limits and procedures. The committee meets monthly and consists of the Chief
Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.

We use a risk measurement model which calculates Value at Risk (VaR) to measure
our commodity price risk in the trading portfolio. The VaR is based on the
variance - covariance method using historical prices to estimate volatilities
and correlations and assuming a 95% confidence level and a one-day holding
period. Based on this VaR analysis, at December 31, 2002 a near term typical
change in commodity prices is not expected to have a material effect on our
results of operations, cash flows or financial condition. The following table
shows the high, average, and low market risk as measured by VaR at:

                 December 31,
                 -----------
                   2002             2001
                   ----             ----
          High Average Low   High Average Low
          ---- ------- ---   ---- ------- ---
                      (in millions)

AEP        $24    $12   $4    $28    $14   $5

APCo         4      1    -      4      1    -
CSPCo        3      1    -      2      1    -
I&M          3      1    -      3      1    -
KPCo         1      -    -      1      -    -
OPCo         4      1    -      3      1    -
PSO          -      -    -      2      1    -
SWEPCo       -      -    -      3      1    -
TCC          -      -    -      3      1    -
TNC          -      -    -      1      1    -

After the October announcement of our strategy to reduce trading activity, the
related VaRs were substantially reduced. The average AEP trading VaR for the
fourth quarter 2002 was $7 million as compared to $13 million for fourth quarter
2001. In 2003 we will continue to adjust our VaR limit structure commensurate
with our anticipated level of trading activity.

We also utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $527 million at
December 31, 2002 and $673 million at December 31, 2001. However, since we would
not expect to liquidate our entire debt portfolio in a one year holding period,
a near term change in interest rates should not materially affect results of
operations or consolidated financial position.

The following table shows the potential loss in fair value as measured by VaR
allocated to the AEP registrant subsidiaries based upon debt outstanding:

VaR for Registrant Subsidiaries:

                                     December 31,
                                     -----------
                                 2002           2001
                                 ----           ----
                                    (in millions)
Company
AEGCo                            $ 3              $5
APCo                              87             100
CSPCo                             33              60
I&M                               85              86
KPCo                              30              16
OPCo                              34              59
PSO                               70              17
SWEPCo                            70              36
TCC                               65              80
TNC                                5              20

AEGCo is not exposed to risk from changes in interest rates on short-term and
long-term borrowings used to finance operations since financing costs are
recovered through the unit power agreements.

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

We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree other commodities and as a result we are
subject to price risk. The amount of risk taken by the traders is controlled by
the management of the trading operations and the Company's Chief Risk Officer
and his staff. When the risk from trading activities exceeds certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.

We employ fair value hedges, cash flow hedges and swaps to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. We do not hedge all interest rate risk.

We employ cash flow forward hedge contracts to lock-in prices on certain power
trading transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.

Credit Risk

AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. In addition, AEP uses Moody's Investor Service, Standard and
Poor's and qualitative and quantitative data to independently assess the
financial health of counterparties on an ongoing basis. This data, in
conjunction with the ratings information, is used to determine appropriate risk
parameters. AEP also requires cash deposits, letters of credit and
parental/affiliate guarantees as security from counterparties depending upon
credit quality in our normal course of business.

We trade electricity and gas contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty is not material to our financial
condition at December 31, 2002. At December 31, 2002 approximately 7% of our
exposure was below investment grade as expressed in terms of net MTM assets. Net
MTM assets represents the aggregate difference between the forward market price
for the remaining term of the contract and the contractual price per
counterparty. As of December 31, 2002, the following table approximates
counterparty credit quality and exposure for AEP based on netting across AEP
entities, commodities and instruments:

                    Futures,
                  Forward and
Counterparty          Swap
Credit Quality:    Contracts    Options      Total
- --------------      -------     -------     ------
                            (in millions)

AAA/Exchanges        $    26      $  2     $   28
AA                       307        33        340
A                        448        26        474
BBB                      700       101        801
Below Investment
Grade                    107       11         118
                    ---------    -----    --------

  Total              $ 1,588      $173     $1,761
                     =======      ====     ======


The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electric and gas transactions are executed over the counter
with counterparties or through brokers. Gas transactions are also executed
through brokerage accounts with brokers who are registered with the Commodity
Futures Trading Commission. Brokers and counterparties require cash or cash
related instruments to be deposited on these transactions as margin against open
positions. The combined margin deposits at December 31, 2002 and 2001 were $109
million and $55 million, respectively. These margin accounts are restricted and
therefore are not included in Cash and Cash Equivalents on the Balance Sheets.
We can be subject to further margin requirements should related commodity prices
change.

We recognize the net change in the fair value of all open trading contracts, in
accordance with generally accepted accounting principles and include the net
change in mark-to-market amounts on a net discounted basis in revenues. The
marking-to-market of open trading contracts contributed an unrealized $180
million to revenues in 2002. The mark-to-market fair values of open short-term
trading contracts are based on exchange prices and broker quotes. The fair value
of open long-term trading contracts are based mainly on internally developed
valuation models. The gross value is present valued and reduced by appropriate
valuation adjustments for counterparty credit risks and liquidity risk to arrive
at fair value. The models are derived from internally assessed market prices
with the exception of the NYMEX gas curve, where we use daily settled prices.
Forward price curves are developed for inclusion in the model based on broker
quotes and other available market data. The liquid portion of these curves are
validated on a regular basis by the middle-office through the market data.
Illiquid portions of the curves are validated through a review of the underlying
market assumptions and variables for consistency and reasonableness. The end of
the month liquidity reserve is based on the difference in price between the
price curve and the bid price if we have a long position and the price curve and
the ask price if we have a short position. This provides for a more accurate
valuation of energy contracts.

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 prices, at the time of settlement, do not
correlate with our interally developed price models.

The effect on the Statements of Operations of marking to market open electricity
trading contracts in AEP's regulated jurisdictions, specifically I&M, KPCo, PSO
and a portion of SWEPCO, is deferred as regulatory assets (losses) or
liabilities (gains) 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.


The following table shows net revenues (revenues less fuel and purchased energy
expense) and their relationship to the mark-to-market revenues (the change in
fair value of open trading contracts).

                                December 31,
                                -----------
                        2002       2001        2000
                        ----       ----        ----

                               (in millions)
Revenues
 (including
 Mark- To-
 Market
 Adjustment)          $14,555    $12,767    $11,113
Fuel and
 Purchased
 Energy
 Expense                6,307      4,944      3,880
                      -------    -------    -------
Net Revenues          $ 8,248    $ 7,823    $ 7,233
                      =======    =======    =======
Mark-to-Market
 Revenues                $180       $207       $187
                          ===       ====       ====
Percentage of
 Net Revenues
 Represented by
 Mark-to-Market
 On Open
 Trading  Positions        2%         3%         3%
                           ==         ==         ==


<PAGE>


The following tables analyze the changes in fair values of trading assets and
liabilities. The first table "Net Fair Value of Mark-to-Market Energy Trading
and Derivative Contracts" shows how the net fair value of energy trading
contracts was derived from the amounts included in the Consolidated Balance
Sheets line item "Energy Trading and Derivative Contracts." The next table
"Mark-to-Market Energy Trading and Derivative 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 and related derivatives at December 31, 2001 of $448
million to December 31, 2002 of $250 million. Contracts realized/settled during
the period include both sales and purchase contracts. The third table
"Mark-to-Market Energy Trading and Derivative Contract Maturities" shows
exposures to changes in fair values and realization periods over time for each
method used to determine fair value.

<TABLE>
<CAPTION>

Net Fair Value of Mark-to-Market Energy Trading and Derivative Contracts - AEP
                                                                                                    December 31
                                                                                              ----------------------
                                                                                             2002                  2001
                                                                                             ----                  ----
                                                                                                   (in millions)

<S>                                                                                         <C>                  <C>
Energy Trading and Derivative Contracts:
    Current Asset                                                                           $1,046               $ 2,125
    Long-term Asset                                                                            824                   795
    Current Liability                                                                       (1,147)               (1,877)
    Long-term Liability                                                                       (484)                 (603)
                                                                                            ------               -------
Net Fair Value of Energy Trading and Derivative Contracts                                      239                   440
Non-trading related derivative liabilities                                                      11*                 -
Assets held for sale (CitiPower)                                                              -                        8
                                                                                            ------               -------
Net Fair Value of Energy Trading and Derivative Contracts                                   $  250               $   448
                                                                                            ======               =======

* Excludes $6 million Loss recorded in an equity investment.
</TABLE>


The above net fair value of energy trading and derivative contracts includes
$180 million at December 31, 2002, in unrealized mark-to-market gains that are
recognized in the Consolidated Statements of Operations at December 31, 2002.

<TABLE>
<CAPTION>

Mark-to-Market Energy Trading and Derivative Contracts - AEP
                                                                                                Total
                                                                                                -----
                                                                                            (in millions)
<S>                                                                                           <C>                <C>
Net Fair Value of Energy Trading and Derivative Contracts
  at December 31, 2001                                                                         $ 448

(Gain) Loss from Contracts Realized/Settled During the Period                                   (182)              (a)

Fair Value of New Open Contracts When Entered Into During the Period                              68               (b)

Net Option Premiums Paid/(Received) (130) (c)

Change in fair value due to Methodology Changes                                                      1             (d)

Change in Market Value of Energy Trading Contracts
  Allocated to Regulated Jurisdictions                                                            (2)              (e)

Changes in Market Value of Contracts                                                              47               (f)
                                                                                               -----

Net Fair Value of Energy Trading and Derivative Contracts
 at December 31, 2002                                                                          $ 250
                                                                                               =====


</TABLE>
<TABLE>
<CAPTION>




Mark-to-Market Energy Trading and Derivative Contracts - Registrant Subsidiaries

                                                               APCo                 CSPCo                  I&M
                                                               ----                 -----                  ---
<S>                                                          <C>                     <C>                 <C>
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                              $ 75,701                $48,449             $ 61,345
(Gain) Loss from Contracts
 Realized/Settled During the Period (a)                        (19,143)              (13,812)              (9,611)
Change in Fair Value Due To
 Methodology Changes (d)                                           350                   228                  247
Changes in Fair Market Value of Energy
 Trading Contracts Allocated To
 Regulated Jurisdictions (e)                                       -                     -                  1,502
Fair Value Of New Open Contracts
 When Entered Into during The Period (b)                       10,865                  7,039                2,774
Net Option Premium Payments (c)                                 (1,797)               (1,208)              (1,292)
Changes In Market Value Of Contracts (f)                       30,876                 24,421               15,896
                                                             --------                -------             --------
Net Fair Value of Energy Trading
 Contracts at December 31, 2002 (g)                          $ 96,852                $65,117             $ 70,861
                                                             ========                =======             ========
</TABLE>
<TABLE>
<CAPTION>


                                                               KPCo                  OPCo                  PSO
                                                               ----                  ----                  ---
<S>                                                            <C>                 <C>                    <C>
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                                $12,729              $ 65,446              $ 2,434
(Gain) Loss From Contracts
 Realized/Settled During Period (a)                              1,153              (18,337)                6,476
Change in Fair Value Due To
 Methodology Changes (d)                                            90                   311                   32
Changes In Fair Market Value Of Energy
 Trading Contracts Allocated To
 Regulated Jurisdiction (e)                                      5,136                 -                   (5,397)
Fair Value of New Open Contracts
 When Entered Into During Period (b)                             1,013                18,443                 -
Net Option Premium Payments (c)                                   (464)               (1,603)                -
Changes In Market Value Of Contracts (f)                         5,341                29,846                 -
                                                               -------              --------              -------
Net Fair Value of Energy Trading
 Contracts at December 31, 2002 (g)                            $24,998              $ 94,106              $ 3,545
                                                               =======              ========              =======
</TABLE>
<TABLE>
<CAPTION>


                                                                 SWEPCo                  TCC              TNC
                                                                 ------                  ---              ---
<S>                                                            <C>                   <C>                  <C>
Net Fair Value of Energy Trading
 Contracts at December 31, 2001                                $ 2,900               $ 3,857              $   915
(Gain) Loss From Contracts
 Realized/Settled During The Period (a)                          6,971                 7,138                2,413
Change in Fair Value Due To
 Methodology Changes (d)                                            36                    42                   12
Changes In Fair Market Value Of Energy
 Trading Contracts Allocated To
 Regulated jurisdiction (e)                                     (2,485)                 -                    (336)
Fair Value Of New Open Contracts
  When Entered Into During The Period (b)                          428                 1,919                1,627
Net Option Premium Payments (c)                                   -                     -                    -
Changes In Market Value Of Contracts (f)                        (3,800)               (7,542)              (2,588)
                                                               -------               -------              -------
Net Fair Value of Energy Trading
 Contracts at December 31, 2002 (g)                            $ 4,050               $ 5,414              $ 2,043
                                                               =======               =======              =======

</TABLE>

(a) "(Gain) Loss from Contracts Realized/Settled During the Period" include
realized gains from energy trading contracts and related derivatives that
settled during 2002 that were entered into prior to 2002. (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 2002. 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) Net Option Premiums Paid/(Received)" reflects the net option premiums
paid/(received) as they relate to unexercised and unexpired option contracts
that were entered into in 2002. (d) The Company changed the discount rate
applied to its trading portfolio from BBB+ Utility to LIBOR in the second
quarter which increased fair value by $10 million. In addition, the Company
changed its methodology in valuing a spread option model so as to more
accurately reflect the exercising of power transactions at optimal prices which
reduced fair value by $9 million.
(e)"Change in Market Value of Energy Trading Contracts Allocated to Regulated
Jurisdictions" relates to the net gains of those contracts that are not
reflected in the Consolidated Statements of Operations. These net gains are
recorded as regulatory liabilities for those subsidiaries that operate in
regulated jurisdictions.
(f)"Changes 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.
(g)"Net Fair Value of Energy Trading Contracts" does not reflect the changes in
fair value associated with derivative contracts designated as hedges and
therefore will not agree to the net fair value of the Energy Trading and
Derivative Contracts line items on the individual registrants' balance sheets.



<TABLE>
<CAPTION>


Mark-to-Market Energy Trading and Derivative Contract Maturities - AEP

                                                          Fair Value of Contracts at December 31, 2002
                                                          --------------------------------------------
                                                                             Maturities
                                                                            (in millions)

AEP Consolidated                                  Less than                             In Excess       Total Fair
Source of Fair Value                               1 year    1-3 years     4-5 years    Of 5 years        Value
- --------------------                               ------    ---------     ---------    ----------        -----
<S>                                                <C>            <C>           <C>         <C>           <C>
Prices Actively Quoted (a)                          $(32)         $ 69          $ -         $ -           $ 37
Prices Provided by Other External
 Sources (b)                                          24           189           11           -            224
Prices Based on Models and Other
 Valuation Methods (c)                               (84)           13           36          24            (11)
                                                    ----          ----          ---         ---           ----
  Total                                             $(92)         $271          $47         $24           $250
                                                    ====          ====          ===         ===           ====

</TABLE>
<TABLE>
<CAPTION>

Mark-to-Market Energy Trading and Derivative Contract Maturities- Registrant Subsidiaries

                                                                  Fair Value of Contracts at December 31, 2002
                                                                  --------------------------------------------
                                                                                 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
- --------------------                           ------        ---------     ---------    ----------      -----

<S>                                            <C>           <C>            <C>             <C>           <C>
APCo
Prices Provided by Other
 External Sources (b)                          $14,352       $43,307        $ 3,018         $ -           $ 60,677
Prices Based on Models and Other
 Valuation Methods (c)                          11,492         9,475          8,183          7,025          36,175
                                               -------       -------        -------         ------        --------
  Total                                        $25,844       $52,782        $11,201         $7,025        $ 96,852
                                               =======       =======        =======         ======        ========

CSPCo
Prices Provided by Other
 External Sources (b)                          $ 9,657       $29,113        $ 2,028         $ -           $ 40,798
Prices Based on Models and Other
 Valuation Methods (c)                           7,726         6,370          5,501          4,722          24,319
                                               -------       -------        -------         ------        --------
  Total                                        $17,383       $35,483        $ 7,529         $4,722        $ 65,117
                                               =======       =======        =======         ======        ========

KPCo
Prices Provided by Other
 External Sources (b)                          $ 3,707       $11,176        $   779         $ -           $ 15,662
Prices Based On Models and Other
 Valuation Methods (c)                           2,966         2,442          2,114          1,814           9,336
                                               -------       -------        -------         ------        --------
  Total                                        $ 6,673       $13,618        $ 2,893         $1,814        $ 24,998
                                               =======       =======        =======         ======        ========

I&M
Prices Provided by Other
 External Sources (b)                          $12,105       $30,961        $ 2,171         $ -           $ 45,237
Prices Based on Models and Other
 Valuation Methods (c)                           7,913         6,772          5,886          5,053          25,624
                                               -------       -------        -------         ------        --------
  Total                                        $20,018       $37,733        $ 8,057         $5,053        $ 70,861
                                               =======       =======        =======         ======        ========

OPCo
Prices Provided by Other
 External Sources (b)                          $20,775       $38,622        $ 2,691         $ -           $ 62,088
Prices Based on Models and Other
 Valuation Methods (c)                          10,003         8,453          7,298          6,264          32,018
                                               -------       -------        -------         ------        --------
  Total                                        $30,778       $47,075        $ 9,989         $6,264        $ 94,106
                                               =======       =======        =======         ======        ========

PSO
Prices Provided by Other
 External Sources (b)                          $   373        $1,736        $   125         $ -           $  2,234
Prices Based on Models and Other
 Valuation Methods (c)                             296           390            336            289           1,311
                                               -------        ------        -------        -------        --------
  Total                                        $   669        $2,126        $   461        $   289        $  3,545
                                               =======        ======        =======        =======        ========

SWEPCo
Prices Provided by Other
 External Sources (b)                          $   427        $1,983        $   141        $  -           $  2,551
Prices Based on Models and Other
 Valuation Methods (c)                             338           446            385            330           1,499
                                               -------        ------        -------        -------        --------
  Total                                        $   765        $2,429        $   526        $   330        $  4,050
                                               =======        ======        =======        =======        ========

TCC
Prices Provided by Other
 External Sources (b)                          $ 1,536       $ 1,605       $    115        $   -          $  3,256
Prices Based on Models and Other
 Valuation Methods (c)                           1,219           361            311            267           2,158
                                               -------       -------       --------        -------        --------
  Total                                        $ 2,755       $ 1,966       $    426        $   267        $  5,414
                                               =======       =======       ========        =======        ========

TNC
Prices Provided by Other
 External Sources (b)                          $   201        $1,016       $     73           $  -        $  1,290
Prices Based on Models and Other
 Valuation Methods (c)                             159           229            197            168             753
                                               -------        ------       --------         ------        --------
  Total                                        $   360        $1,245       $    270         $  168        $  2,043
                                               =======        ======       ========         ======        ========

</TABLE>

(a)"Prices Actively Quoted" represents the Company's exchange traded futures
    positions.
(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. 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 exchange or an
    over-the-counter broker, the value of transactions
    for which an internally developed price curve was developed as a result of
    the long dated nature of certain transactions, and the value of certain
    structured transactions.




<PAGE>


We have investments in debt and equity securities which are held in nuclear
trust funds. The trust investments and their fair value are discussed in Note
17, "Risk Management, Financial Instruments and Derivatives." Financial
instruments in these trust funds have not been included in the market risk
calculation for interest rates as these instruments are marked-to-market and
changes in market value of these instruments are reflected in a corresponding
decommissioning liability. Any differences between the trust fund assets and the
ultimate liability are expected to be recovered through regulated rates from our
regulated customers.

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

Industry Restructuring

Four of the eleven state retail jurisdictions (Michigan, Ohio, Texas and
Virginia) in which AEP's domestic electric utility companies operate have
implemented retail restructuring legislation. Three other states (Arkansas,
Oklahoma and West Virginia) initially adopted retail restructuring legislation,
but have since delayed the implementation of that legislation or repealed the
legislation (Arkansas). In general, retail restructuring legislation provides
for a transition from cost-based rate regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. As legislative
and regulatory proceedings evolved, six AEP electric operating companies (APCo,
CSPCo, OPCo, SWEPCo, TCC and TNC) have discontinued the application of SFAS 71
regulatory accounting for the generation business. AEP has not discontinued its
regulatory accounting for its subsidiaries doing business in Michigan (I&M) and
Oklahoma (PSO). Restructuring legislation, the status of the transition plans
and the status of the electric utility companies' accounting to comply with the
changes in each of our state regulatory jurisdictions affected by restructuring
legislation is presented in Note 8 of the Notes to Financial Statements.

Corporate Separation

AEP and its subsidiaries have filed with the FERC and SEC seeking approval to
separate their regulated and unregulated operations. The plan for corporate
separation allows AEP and its subsidiaries to meet the requirements of Texas and
Ohio restructuring legislation. In Texas, TCC and TNC intended to transfer the
generation assets from the integrated electric operating companies (CPL and WTU)
which operated in ERCOT prior to the effective date of the Texas Restructuring
Legislation to unregulated generation companies. In Ohio, CSPCo and OPCo
intended to transfer transmission and distribution assets from the integrated
companies to two new wires companies leaving CSPCo and OPCo as generating
companies. AEP and its subsidiaries proposed amendments to the power pooling
agreements to remove the four Ohio and Texas generating companies. Only those
operating companies that continue to exist as integrated utilities would have
been included in the amended power pooling agreements, which would govern energy
exchanges among members and the allocation of their off-system purchases and
sales. In connection with corporate seperation, certain new interim power supply
agreements have been proposed to provide power to distribution companies who
will no longer own generation assets. Several state commissions, wholesale
customer groups and other interested parties intervened in the FERC proceeding.
Negotiated settlement agreements with the state regulatory commissions and other
major intervenors were filed with the FERC in December 2001. In September 2002,
the FERC conditionally approved our corporate separation plan as modified by the
settlement agreements. Terms in the settlement agreements would be effective
upon implementation of corporation separation. In addition, SEC approval of
AEP's corporate separation plan is required for its implementation. The Arkansas
Commission intervened with the SEC, which has extended the length of time needed
for the SEC's review. In order to execute this separation, AEP and its
subsidiaries may be required to retire various debt securities and transfer
assets between legal entities.

With the changes in AEP's business strategy in response to current energy
market/business conditions, management is evaluating changes to the corporate
separation plans, including determining whether legal corporate separation is
appropriate.

RTO Formation

FERC Order No. 2000 and many of the settlement agreements with the FERC and
state regulatory commissions to approve the AEP-CSW merger required the transfer
of functional control of the subsidiaries' transmission systems to RTOs.

AEP East companies initially participated in the formation of the Alliance RTO.
In December 2001, the FERC reversed prior approvals and rejected the Alliance
RTO's filing. Subsequently, in May 2002, AEP announced an agreement with the PJM
Interconnection to pursue terms for AEP East companies to participate in PJM
with final agreements to be negotiated. In July 2002, the FERC conditionally
approved AEP's decision for AEP East companies to join PJM subject to certain
conditions being met. The performance of these conditions are only partially
under AEP's control. In December 2002, AEP East companies in Indiana, Kentucky,
Ohio and Virginia filed for state regulatory commission approval of their plans
to transfer functional control of their transmission assets to PJM based on
statutory or regulatory requirements in those states. Those proceedings are
currently pending. In February 2003, the Virginia Legislature enacted
legislation that would prohibit the transfer to an RTO, until at least July
2004, which is currently awaiting signature by the Governor of Virginia.

AEP West companies are members of ERCOT or the SPP. In May 2002, FERC accepted,
conditionally, filings related to a proposed consolidation of the MISO and the
SPP. In that order the FERC required the AEP West companies in SPP to file
reasons why they should not be required to join MISO. In August 2002, AEP,
SWEPCo and TNC notified the FERC of their intent that the transmission assets in
SPP would participate in MISO. AEP's SPP companies are also regulated by state
public utility commissions, and the Louisiana and Arkansas commissions also
filed responses to the FERC's RTO order indicating that additional analysis was
required. Regulatory activities concerning various RTO issues are ongoing in
Arkansas and Louisiana.

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

FERC Proposed Standard Market Design and Security Standards

In 2002, the FERC issued its Standard Market Design (SMD) notice of proposed
rulemaking seeking to standardize the structure and operation of wholesale
electricity markets across the country. The FERC published for comment its
proposed security standards as part of the SMD. These standards are intended to
ensure all market participants have a basic security program that effectively
protects the electric grid and related market activities. Because the rule is
not yet finalized, management cannot predict the effect of the final rule on AEP
or its subsidiaries' operations and financial results. See Note 9 for a complete
discussion of these proposals.

Litigation

AEP and its subsidiaries are involved in various litigation. The details of
significant litigation contingencies are disclosed in Note 9 and summarized
below.

Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corp. and its subsidiaries which are pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron's bankruptcy,
AEP and its subsidiaries had open trading contracts and trading accounts
receivables and payables with Enron and various HPL related contingencies and
indemnities including issues related to the underground Bammel gas storage
facility and the cushion gas (or pad gas) required for its normal operation.

In 2001, AEP expensed $47 million ($31 million net of tax) for our estimated
loss from the Enron bankruptcy. In 2002 AEP expensed an additional $6 million
for a cumulative loss of $53 million ($34 million net of tax). The amounts for
certain subsidiary registrants were:

                                              Amounts
                           Amounts             Net of
Registrant                Expensed              Tax
                          --------             -----
                                  (in millions)

APCo                         $5.3              $3.4
CSPCo                         2.7               1.8
I&M                           2.8               1.8
KPCo                          1.1               0.7
OPCo                          3.6               2.3

The additional 2002 expense did not materially change the cumulative expense per
registrant subsidiary. The amounts expensed were based on an analysis of
contracts where AEP entities and Enron are counterparties.

Management believes that we have the right to utilize offsetting receivables and
payables and related collateral across various Enron entities by offsetting
approximately $110 million of trading payables owed to various Enron entities
against trading receivables due to us. Management believes we have legal
defenses to any challenge that may be made to the utilization of such offsets.
At this time management is unable to predict the ultimate resolution of these
issues or their impact on results of operations and cash flows. See Note 9 for
further discussion.

COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

A decision by the U.S. District Court for the Southern District of Ohio in
February 2001 that denied AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to a COLI program resulted in a
$319 million reduction in AEP's Net Income for 2000.

The earnings reductions for affected registrant subsidiaries were as follows:

                                (in millions)
APCo                                $ 82
CSPCo                                 41
I&M                                   66
KPCo                                   8
OPCo                                 118

AEP has appealed the Court's decision. See Note 18 for further discussion.

Shareholders' Litigation - Affecting AEP

In 2002, lawsuits alleging securities law violations, a breach of fiduciary duty
for failure to establish and maintain adequate internal controls and violations
of the Employee Retirement Income Security Act were filed against AEP, certain
AEP executives, members of the AEP Board of Directors and certain investment
banking firms. These cases are in the initial pleading stage. AEP intends to
vigorously defend against these actions. See Note 9 for further discussion.

California Lawsuit - Affecting AEP

In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP intends to
vigorously defend against this action. See Note 9 for further discussion.

FERC Wholesale Fuel Complaints - Affecting AEP and TNC

In May 2000 and November 2001, certain TNC wholesale customers filed a
complaints with FERC alleging that TNC had overcharged them through the fuel
adjustment clause for certain purchased power costs. The final resolution of
this matter could have a negative impact on futute results of operations, cash
flow and financial condition. See Note 6 for further discussion.

Merger Litigation - Affecting AEP and all Subsidiary Registrants

In January 2002, a federal court ruled that the SEC did not properly find that
the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and
sent the case back to the SEC for further review. Management believes that the
merger meets the requirements of the PUHCA and expects the matter to be resolved
favorably. See Note 9 for further discussion.

Arbitration of Williams Claim - Affecting AEP

In 2002, AEP filed its demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
Although management is unable to predict the outcome of this matter, it is not
expected to have a material impact on results of operations, cash flows or
financial condition. See Note 9 for further discussion.

Energy Market Investigations - Affecting AEP

During 2002, the FERC, the California attorney general, the PUCT, the SEC, the
Department of Justice and the U.S. Commodity Futures Trading Commission (CFTC)
initiated investigations into whether any entity, including Enron, manipulated
short-term prices in electric energy or natural gas markets, exercised undue
influence over wholesale prices or participated in fraudulent trading practices.

AEP and its subsidiaries have and will continue to provide information to the
FERC, the SEC, state officials and the CFTC as required. See Note 9 for further
discussion.

FERC Market Power Mitigation  - Affecting the AEP System

A FERC order on our triennial market based wholesale power rate authorization
update required certain mitigation actions that AEP and its subsidiaries would
need to take for sales/purchases within their control area and required the
posting of information on our website regarding the status of AEP's power
system. As a result of a request for rehearing filed by AEP and other market
participants, FERC issued an order delaying the effective date of the mitigation
plan until after a planned technical conference on market power determination.
No such conference has been held and management is unable to predict the timing
of any further action by the FERC or its affect on future results of operations
and cash flows.

Other Litigation - Affecting AEP and all Subsidiary Registrants

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

Environmental Concerns and Issues

AEP and its subsidiaries will confront several new environmental requirements
over the next decade with the potential for substantial control costs and
premature retirement of some generating plants. These policies include:
stringent controls on sulfur dioxide (S02), nitrogen oxide (NOx) and mercury
(Hg) emissions from future regulations or laws, or an adverse decision in the
New Source Review litigation; a new Clean Water Act rule to reduce fish killed
at once-through cooled power plants; and a possible future requirement to reduce
carbon dioxide (CO2) emissions as the world endeavors to stabilize atmospheric
concentrations of greenhouse gas emissions and avert global climatic changes.

AEP and its subsidiaries' environmental policy require full compliance with all
applicable legal requirements. In support of this policy, AEP and its
subsidiaries invest in research through groups like the Electric Power Research
Institute and directly through demonstration projects for new emission control
technologies. AEP and its subsidiaries intend to continue in a leadership role
to protect and preserve the environment while providing vital energy commodities
and services to customers at fair prices. AEP and its subsidiaries have a proven
record of efficiently producing and delivering electricity and gas while
minimizing the impact on the environment. AEP and its subsidiaries have spent
billions of dollars to equip many of their facilities with pollution control
technologies.

Multi-pollutant control legislation has been introduced in Congress and is
supported by the Bush Administration. The legislation would regulate NOx, SO2,
Hg and possibly CO2 emissions from electric generating plants. AEP and its
subsidiaries are advocates of comprehensive, multi-pollutant legislation so that
compliance planning can be coordinated and collateral emission reductions
maximized. Optimally, such legislation would establish reasonable emission
reduction targets and compliance timetables based on sound science, utilize
nationwide cap-and-trade programs for achieving compliance as cost-effectively
as possible, protect fuel diversity and preserve the reliability of the nation's
electric supply. Management is unable to predict the timing or magnitude of
additional pollution control laws or regulations. If additional control
technology is required on AEP System facilities and their costs are not
recoverable from customers through regulated rates or market prices, those costs
could adversely affect future results of operations and cash flows. The
following discussions explain existing control efforts, litigation and other
pending matters related to environmental issues for AEP companies.

Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M
and OPCo

Since 1999 AEPSC, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA, a
number of states and special interest groups alleged that AEP System companies
modified certain units at coal fired generating plants in violation of the Clean
Air Act over a 20 year period.

Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense.
Management is unable to estimate the loss or range of loss related to the
contingent liability under the Clear Air Act proceedings and unable to predict
the timing of resolution of these matters due to the number of alleged
violations and the significant number of issues yet to be determined by the
Court. If the AEP System companies do not prevail, any capital and operating
costs of additional pollution control equipment or any penalties imposed would
adversely affect future results of operations, cash flows and possibly financial
condition unless such costs can be recovered. See Note 9 for further discussion.

NOx Reductions - Affecting AEP, APCo,  I&M, OPCo, SWEPCo and TCC

Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
requiring substantial reductions in NOx emissions in a number of eastern states,
including certain states in which the AEP System's generating plants are
located. The compliance date for these rules is May 31, 2004.

In 2000, the Texas Commission on Environmental Quality (formerly the Texas
Natural Resource Conservation Commission) adopted rules requiring significant
reductions in NOx emissions from utility sources, including TCC and SWEPCo. The
compliance date is May 2003 for TCC and May 2005 for SWEPCo.

AEP and its subsidiaries are installing a variety of emission control
technologies to reduce NOx emissions to comply with the applicable state and
Federal NOx requirements including selective catalytic reduction (SCR) and
non-SCR technologies. The AEP System NOx compliance plan is a dynamic plan that
is continually reviewed and revised. Current estimates indicate that compliance
with the NOx Rule, the Texas Commission on Environmental Quality rule and the
Section 126 Rule could result in required capital expenditures in the range of
$1.3 billion to $2 billion of which $843 million has been spent through December
31, 2002 for the AEP System.

The following table shows the estimated compliance cost ranges and amounts spent
by certain of AEP's registrant subsidiaries through December 31, 2002.




                 Estimated     Amounts
             Compliance Costs   Spent
             ----------------  -------
                      (in millions)
Company

APCo                $445       $234
I&M               42-210          5
OPCo             535-864        387
SWEPCo                40         24
TCC                    5          5

Unless any capital and operating costs of additional pollution control equipment
are recovered from customers, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition. See Note 9 for
further discussion.

Superfund and State Remediation - Affecting AEP, APCo, CSPCo, I&M, OPCo, SWEPCo
and TCC

By-products from the generation of electricity include materials such as ash,
slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products,
which constitute the overwhelming percentage of these materials, are typically
disposed of or treated in captive disposal facilities or are beneficially
utilized. In addition, our generating plants and transmission and distribution
facilities have used asbestos, PCBs and other hazardous and non-hazardous
materials. AEP and its subsidiaries are currently incurring costs to safely
dispose of these substances. Additional costs could be incurred to comply with
new laws and regulations if enacted.

Superfund addresses clean-up of hazardous substances at disposal sites and
authorized Federal EPA to administer the clean-up programs. As of year-end 2002
subsidiaries of AEP are named by the Federal EPA as a PRP for five sites. APCo,
CSPCo, and OPCo each have one PRP site and I&M has two PRP sites. There are six
additional sites for which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received
information requests which could lead to PRP designation. HPL, OPCo, SWEPCo and
TCC have also been named potentially liable at six sites under state law.
Liability has been resolved for a number of sites with no significant effect on
results of operations. In those instances where AEP or its subsidiaries have
been named a PRP or defendant, their disposal or recycling activities were in
accordance with the then-applicable laws and regulations. Unfortunately,
Superfund does not recognize compliance as a defense, but imposes strict
liability on parties who fall within its broad statutory categories.

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

Global Climate Change - Affecting AEP and all Registrant Subsidiaries

At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997, more than
160 countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly CO2, which many scientists
believe are contributing to global climate change. Although the U.S. signed the
Kyoto Protocol on November 12, 1998, the treaty was not submitted to the Senate
for its advice and consent by President Clinton. In March 2001, President Bush
announced his opposition to the treaty and its U.S. ratification. At the Seventh
Conference of the Parties in November 2001, the parties finalized the rules,
procedures and guidelines required to facilitate ratification of the protocol.
The protocol is expected to become effective in 2003. AEP does not support the
Kyoto Protocol but intends to work with the Bush Administration and U.S.
Congress to develop responsible public policy on this issue. Management expects
that due to President Bush's opposition to legislation mandating greenhouse gas
emissions controls, any policies developed and implemented in the near future
are likely to encourage voluntary measures to reduce, avoid or sequester such
emissions. AEP has for many years been a leader in pursuing voluntary actions to
control greenhouse gas emissions. AEP recently expanded its commitment in this
area by
joining the Chicago Climate Exchange, a pilot greenhouse gas emission reduction
and trading program, under which AEP and its subsidiaries are obligated to
reduce or offset 18 million tons of CO2 emissions during 2003-2006.

The acquisition of 4,000 MW of coal-fired generation in the United Kingdom in
December 2001 exposes these assets to potential CO2 emission control obligations
since the U.K has become a party to the Kyoto Protocol.

Control of Mercury Emissions

In December 2000, Federal EPA issued a regulatory determination listing the
electric generating sector as a source category under the Clean Air Act for
development of maximum achievable control technology standards to control
emissions of hazardous air pollutants, including Hg. Federal EPA is expected to
issue proposed regulations in 2003 and develop a final rule in 2004. Management
cannot predict the outcome of these regulatory proceedings, or the costs to
comply with any new standards adopted by Federal EPA. The costs associated with
compliance could be material. However, unless any capital and operating costs of
additional pollution control equipment are recovered from customers, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition.

Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, I&M and TCC

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a
significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law I&M and TCC participate in the DOE's
SNF disposal program which is described in Note 9 of the Notes to Financial
Statements. Since 1983 I&M has collected $303 million from customers for the
disposal of nuclear fuel consumed at the Cook Plant. $117 million of these funds
have been deposited in external trust funds to provide for the future disposal
of SNF and $186 million has been remitted to the DOE. TCC has collected and
remitted to the DOE, $53 million for the future disposal of SNF since STP began
operation in the late 1980s. Under the provisions of the Nuclear Waste Policy
Act, collections from customers are to provide the DOE with money to build a
permanent repository for spent fuel. However, in 1996, the DOE notified the
companies that it would be unable to begin accepting SNF by the January 1998
deadline required by law. To date DOE has failed to comply with the requirements
of the Nuclear Waste Policy Act.

As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and
STPNOC on behalf of TCC and the other STP owners, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of
liability. The case continues on the issue of damages owed to I&M by the DOE. As
long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent storage
of SNF and the cost of decommissioning will continue to increase.

In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined a
lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to DOE's nuclear waste fund cost recovery settlement with PECO Energy
Corporation (now Exelon Generation Company, LLC). The settlement adjusted the
fees Exelon was required to pay to DOE for disposal of SNF. The fee adjustment
allowed Exelon to skip payments to the DOE to make up for Exelon's damages from
DOE's breach of its contract obligation to dispose of SNF from commercial
nuclear power plants. The companies believe the settlement was unlawful as it
would force other utilities (rather than DOE) to compensate Exelon for the
damages it had incurred from DOE's breach of contract. In September 2002, the
U.S. Court of Appeals for the Eleventh Circuit found that DOE acted improperly
by adopting the fee adjustment provision of this settlement, that the fee
adjustment provisions of the settlement harmed other utilities who pay into the
fund and violated the federal nuclear waste management laws and that the fee
adjustment provisions of the settlement were null and void.

The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed SNF disposal program. Studies completed in 2000 estimate the cost to
decommission the Cook Plant ranges from $783 million to $1,481 million in 2000
non-discounted dollars. External trust funds have been established with amounts
collected from customers to decommission the plant. At December 31, 2002, the
total decom-missioning trust fund balance for Cook Plant was $618 million which
includes earnings on the trust investments. Studies completed in 1999 for STP
estimate TCC's share of decommissioning cost to be $289 million in 1999
non-discounted dollars. Amounts collected from customers to decommission STP
have been placed in an external trust. At December 31, 2002, the total
decommission-ing trust fund for TCC's share of STP was $98 million which
includes earnings on the trust investments. Estimates from the decommissioning
studies could continue to escalate due to the uncertainty in the SNF disposal
program and the length of time that SNF may need to be stored at the plant site.
I&M and TCC will work with regulators and customers to recover the remaining
estimated costs of decommissioning Cook Plant and STP. However, AEP's, I&M's and
TCC's future results of operations, cash flows and possibly their financial
conditions would be adversely affected if the cost of SNF disposal and
decommissioning continues to increase and cannot be recovered.

Other Environmental Concerns - Affecting AEP and all Subsidiaries

AEP and its subsidiaries are exposed to other environmental concerns which are
not considered to be material or potentially material at this time. Should they
become significant or should any new concerns be uncovered that are material,
they could have a material adverse effect on results of operations and possibly
financial condition. AEP performs environmental reviews and audits on a regular
basis for the purpose of identifying, evaluating and addressing environmental
concerns and issues.

Other Matters

Seasonality

Sale of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change depending on the nature and location
of facilities AEP and its subsidiaries acquire and the terms of power sale
contracts they enter. In addition, AEP and its subsidiaries have historically
sold less power, and consequently earned less income, when weather conditions
are milder. AEP and its subsidiaries expect that unusually mild weather in the
future could diminish their results of operations and may impact their financial
condition.

Sustained Earnings Improvement Initiative

In response to difficult conditions in AEP's business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth. Termination benefits expense relating to 1,120 terminated
employees totaling $75.4 million pre-tax was recorded in the fourth quarter of
2002. We determined that the termination of the employees under our SEI
initiative did not constitute a curtailment under the provisions of SFAS No. 88
"Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits". In addition, certain buildings and
corporate aircraft are being sold in an effort to reduce ongoing operating
expenses. See Note 11 for additional information.

Non-Core Wholesale Investments

Additional market deterioration associated with AEP's non-core wholesale
investments, including AEP's U.K. operations, could have an adverse impact on
AEP's future results of operations and cash flows. Significant long-term changes
in external market conditions could lead to additional write-offs and potential
divestitures of AEP's wholesale investments, including, but not limited to,
AEP's U.K. operations.

Elk City Referendum - Affecting AEP and PSO

In October 2002, the City Commission of Elk City, Oklahoma voted to hold a
referendum seeking voter approval of a $20.4 million acquisition of PSO's
distribution assets within the city limits. The vote occurred in December 2002
with the referendum being defeated.

Snohomish Settlement - Affecting AEP

In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract.
Investments Limitations - Affecting AEP

Our investment, including guarantees of debt, in certain types of activities is
limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling
securities in an amount up to 100% of our average quarterly consolidated
retained earnings balance for investment in EWGs and FUCOs. At December 31,
2002, AEP's investment in EWGs and FUCOs was $2.0 billion, including guarantees
of debt, compared to AEP's limit of $2.8 billion.

SEC rules under PUHCA permit AEP to invest up to 15% of consolidated
capitalization (such amount was $3.2 billion at December 31, 2002) in
energy-related companies, including marketing and/or trading of electricity, gas
and other energy commodities.


<PAGE>


INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373

FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities and Exchange Commission  will
 be available in April 2003 at no cost to shareholders.
Please address requests for copies to:
R. Todd Rimmer
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH  43215-2373

TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve Trust Company, N.A.
P.O. Box 43069
Providence, RI 02940-3069
Phone Number: 1-800-328-6955
Hearing Impaired Number:  TDD: 1-800-952-9245
Website:  http://www.equiserve.com




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>19
<FILENAME>x21.txt
<TEXT>
<PAGE>
<TABLE>
                                                                              EXHIBIT 21
                                 Subsidiaries of
                      American Electric Power Company, Inc.
                             As of December 31, 2002

The  voting  stock of each  company  shown  indented  is  owned  by the  company
immediately  above which is not  indented to the same degree.  Subsidiaries  not
indented are directly owned by American Electric Power Company, Inc.

<CAPTION>
                                                                          Percentage
                                                                           of Voting
                                                                           Securities
                                                 Location of                Owned By
Name of Company                                 Incorporation           Immediate Parent
- ---------------                                 -------------           ----------------
<S>                                               <C>                        <C>
American Electric Power Company, Inc.             New York
American Electric Power Service Corporation       New York                   100.0
AEP C&I Company, LLC                              Delaware                   100.0
AEP Coal, Inc.                                    Nevada                     100.0
AEP Communications, Inc.                          Ohio                       100.0
AEP Energy Services, Inc.                         Ohio                       100.0
AEP Generating Company                            Ohio                       100.0
AEP Desert Sky LP, LLC                            Delaware                   100.0
AEP Desert Sky LP II, LLC                         Delaware                   100.0
Golden Prairie Holding Company LLC                Delaware                   100.0
AEP Investments, Inc.                             Ohio                       100.0
Mutual Energy L.L.C.                              Delaware                   100.0
AEP Power Marketing, Inc.                         Ohio                       100.0
AEP T&D Services, LLC                             Delaware                   100.0
AEP Pro Serv, Inc.                                Ohio                       100.0
AEP Retail Energy LLC                             Delaware                   100.0
AEP Texas POLR, LLC                               Delaware                   100.0
AEP Resources, Inc.                               Ohio                       100.0
Appalachian Power Company                         Virginia                    98.7 (a)
  Cedar Coal Co.                                  West Virginia              100.0
  Central Appalachian Coal Company                West Virginia              100.0
  Central Coal Company                            West Virginia               50.0 (b)
  Southern Appalachian Coal Company               West Virginia              100.0
Columbus Southern Power Company                   Ohio                       100.0
  Colomet, Inc.                                   Ohio                       100.0
  Conesville Coal Preparation Company             Ohio                       100.0
  Simco Inc.                                      Ohio                       100.0
  Ohio Valley Electric Corporation                Ohio                         4.3 (e)
    Indiana-Kentucky Electric Corporation         Indiana                    100.0
Franklin Real Estate Company                      Pennsylvania               100.0
Indiana Michigan Power Company                    Indiana                    100.0
  Blackhawk Coal Company                          Utah                       100.0
  Price River Coal Company, Inc.                  Indiana                    100.0
Kentucky Power Company                            Kentucky                   100.0
Kingsport Power Company                           Virginia                   100.0
Ohio Power Company                                Ohio                        99.2 (c)
  Cardinal Operating Company                      Ohio                        50.0 (d)
  Central Coal Company                            West Virginia               50.0 (b)
Ohio Valley Electric Corporation                  Ohio                        39.9 (e)
  Indiana-Kentucky Electric Corporation           Indiana                    100.0
Wheeling Power Company                            West Virginia              100.0
Central and South West Corporation                Delaware                   100.0
  AEP Texas Central Company                       Texas                      100.0 (f)
    CPL Capital I                                 Delaware                   100.0 (g)
    CPL Transition Funding LLC (DE)               Delaware                   100.0 (g)
  Public Service Company of Oklahoma              Oklahoma                   100.0
    PSO Capital I                                 Delaware                   100.0

  Southwestern Electric Power Company             Delaware                   100.0
    The Arklahoma Corporation                     Arkansas                    47.6
    SWEPCo Capital I                              Delaware                   100.0
    Southwestern Arkansas Utilities Corporation   Arkansas                   100.0
    Dolet Hills Lignite Company, LLC              Delaware                   100.0
  AEP Texas North Company                         Texas                      100.0 (h)


Notes:

a.   13,499,500 shares of Common Stock, all owned by parent,  have one vote each
     and 177,899 shares of Preferred  Stock,  all owned by the public,  have one
     vote each.

b.   Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.

c.   27,952,473 shares of Common Stock, all owned by parent,  have one vote each
     and 238,977 shares of Preferred  Stock,  all owned by the public,  have one
     vote each.

d.   Ohio  Power  Company  owns 50% of the  stock;  the  other 50% is owned by a
     corporation not affiliated with American Electric Power Company, Inc.

e.   American  Electric Power Company,  Inc. and Columbus Southern Power Company
     own 39.9% and 4.3% of the stock,  respectively,  and the remaining 55.8% is
     owned by unaffiliated companies.

f.   Central  Power  and Light  Company  changed  its name to AEP Texas  Central
     Company.

g.   The  names  of CPL  Capital  I and  CPL  Transition  Funding  LLC  (DE)were
     unchanged at December  31,  2002.  AEP intends to change the names of these
     companies in 2003.

h.   West Texas Utilities Company changed its name to AEP Texas North Company.


</TABLE>

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>20
<FILENAME>x23.txt
<DESCRIPTION>AUDITOR D&T
<TEXT>

<PAGE>

                                                                     Exhibit 23

INDEPENDENT AUDITORS' CONSENT


We consent to the  incorporation  by reference in  Registration  Statement  Nos.
333-46360,  333-39402,  333-66048  and  333-62278  of  American  Electric  Power
Company,  Inc.  on Form  S-8,  Post-Effective  Amendment  No. 1 to  Registration
Statement No.  333-50109 of American  Electric Power Company,  Inc. on Form S-8,
Post-Effective  Amendment  No.  3 to  Registration  Statement  No.  33-01052  of
American Electric Power Company,  Inc. on Form S-8, Post Effective Amendment No.
3 to  Registration  Statement No.  33-01734 of American  Electric Power Company,
Inc. on Form S-3, Post Effective  Amendment No. 1 to Registration  Statement No.
333-86050 of American Electric Power Company,  Inc. on Form S-3 and Registration
Statement No. 333-58540 of American Electric Power Company, Inc. on Form S-3, of
our reports dated February 21, 2003,  appearing in and incorporated by reference
in this Annual Report on Form 10-K of American Electric Power Company,  Inc. for
the year ended December 31, 2002.

/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
March 20, 2003




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24
<SEQUENCE>21
<FILENAME>x24.txt
<DESCRIPTION>AEP POA
<TEXT>

<PAGE>

                                                                      Exhibit 24
                                POWER OF ATTORNEY

                      AMERICAN ELECTRIC POWER COMPANY, INC.
              Annual Report on Form 10-K for the Fiscal Year Ended
                                December 31, 2002


     The undersigned  directors of AMERICAN ELECTRIC POWER COMPANY,  INC., a New
York  corporation  (the  "Company"),  do hereby  constitute  and appoint E. LINN
DRAPER,  JR.,  ARMANDO  A.  PENA and  SUSAN  TOMASKY,  and  each of them,  their
attorneys-in-fact  and agents,  to execute for them, and in their names,  and in
any and all of their capacities,  the Annual Report of the Company on Form 10-K,
pursuant to Section 13 of the  Securities  Exchange Act of 1934,  for the fiscal
year ended December 31, 2002, and any and all  amendments  thereto,  and to file
the same, with all exhibits thereto and other documents in connection therewith,
with   the   Securities   and   Exchange   Commission,    granting   unto   said
attorneys-in-fact  and agents,  and each of them, full power and authority to do
and perform  every act and thing  required or necessary to be done,  as fully to
all intents and purposes as the undersigned might or could do in person,  hereby
ratifying and confirming all that said  attorneys-in-fact  and agents, or any of
them, may lawfully do or cause to be done by virtue hereof.

     IN WITNESS  WHEREOF,  the undersigned  have signed these presents this 25th
day of February, 2003.


   /s/ E. R. Brooks                             /s/ Leonard J. Kujawa
- ----------------------------                 ------------------------------
E. R. Brooks                                 Leonard J. Kujawa


   /s/ Donald M. Carlton                        /s/ Richard L. Sandor
- ----------------------------                 ------------------------------
Donald M. Carlton                            Richard L. Sandor


   /s/ John P. DesBarres                       /s/ Thomas V. Shockley, III
- ----------------------------                 ------------------------------
John P. DesBarres                            Thomas V. Shockley, III


   /s/ E. Linn Draper, Jr.                       /s/ Donald G. Smith
- ----------------------------                 ------------------------------
E. Linn Draper, Jr.                          Donald G. Smith


   /s/ Robert W. Fri                             /s/ Linda Gillespie Stuntz
- ----------------------------                 ------------------------------
Robert W. Fri                                Linda Gillespie Stuntz


   /s/ William R. Howell                         /s/ Kathryn D. Sullivan
- ----------------------------                 ------------------------------
William R. Howell                            Kathryn D. Sullivan


   /s/ Lester A. Hudson, Jr.
- ----------------------------
Lester A. Hudson, Jr.



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>22
<FILENAME>x99a.txt
<DESCRIPTION>(A) CERTIFICATE OF CEO
<TEXT>

<PAGE>

                                                                  Exhibit 99(a)


              Certification Pursuant to Section 1350 of Chapter 63
                      Of Title 18 of the United States Code


I, E. Linn Draper, Jr., the chief executive officer of

                      American Electric Power Company, Inc.
                             AEP Generating Company
                            AEP Texas Central Company
                             AEP Texas North Company
                            Appalachian Power Company
                         Columbus Southern Power Company
                         Indiana Michigan Power Company
                             Kentucky Power Company
                               Ohio Power Company
                       Public Service Company of Oklahoma
                       Southwestern Electric Power Company

(the "Companies"),  certify that (i) the Annual Reports of the Companies on Form
10-K for the year ended December 31, 2002 (the "Reports")  fully comply with the
requirements  of Section 13(a) or 15(d) of the  Securities  Exchange Act of 1934
and (ii) the  information  contained  in the  Reports  fairly  presents,  in all
material  respects,  the  financial  condition  and results of operations of the
Companies.

/s/ E. Linn Draper, Jr.

E. Linn Draper, Jr.

March 20, 2003




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>23
<FILENAME>x99b.txt
<DESCRIPTION>(B) CERTIFICATE OF CFO
<TEXT>

<PAGE>

                                                                  Exhibit 99(b)


              Certification Pursuant to Section 1350 of Chapter 63
                      Of Title 18 of the United States Code


I, Susan Tomasky, the chief financial officer of

                      American Electric Power Company, Inc.
                             AEP Generating Company
                            AEP Texas Central Company
                             AEP Texas North Company
                            Appalachian Power Company
                         Columbus Southern Power Company
                         Indiana Michigan Power Company
                             Kentucky Power Company
                               Ohio Power Company
                       Public Service Company of Oklahoma
                       Southwestern Electric Power Company

(the "Companies"),  certify that (i) the Annual Reports of the Companies on Form
10-K for the year ended December 31, 2002 (the "Reports")  fully comply with the
requirements  of Section 13(a) or 15(d) of the  Securities  Exchange Act of 1934
and (ii) the  information  contained  in the  Reports  fairly  presents,  in all
material  respects,  the  financial  condition  and results of operations of the
Companies.

/s/ Susan Tomasky

Susan Tomasky

March 20, 2003




</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----
