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                                  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, 2003

[ ]  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 Corporation)    13-4922640
  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) 716-1000
</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.

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, $6.50 par value.............New York Stock Exchange
  Power Company, Inc.        9.25% Equity Units........................New York Stock Exchange
Appalachian Power Company    None
Columbus Southern Power      None
  Company
CPL Capital I                8.00% Cumulative Quarterly Income
                             Preferred Securities, Series A, Liquidation
                             Preference $25 per Preferred Security.....New York Stock Exchange
Indiana Michigan Power
  Company                    6% Senior Notes, Series D, Due 2032.......New York Stock Exchange
Kentucky Power Company       None
Ohio Power Company           7 3/8% Senior Notes, Series A, Due 2038...New York Stock Exchange
Public Service Company of    6% Senior Notes, Series B, Due 2032.......New York Stock Exchange
 Oklahoma
PSO Capital I                8.00% Trust Originated Preferred
                             Securities, Series A, Liquidation
                             Preference $25 per Preferred Security.....New York Stock Exchange
Southwestern Electric Power  None
  Company
</TABLE>




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>


                                    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 30, 2003         December 31, 2003

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.  $11,782,905,274            395,016,421
                                                            ($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)

         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).

                       DOCUMENTS INCORPORATED BY REFERENCE

                                                               Part of Form 10-K
                                                            Into Which Document
Description                                                   Is Incorporated

Portions of Annual Reports of the following companies for         Part II 
the fiscal year ended December 31, 2003:
           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 2004 Annual Meeting of Shareholders,
to be filed within 120 days after December 31, 2003

Portions of Information Statements of the following               Part III 
companies for 2004 Annual Meeting of Shareholders, to 
be filed within 120 days after December 31, 2003:
           Appalachian Power Company
           Ohio Power Company

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

   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, including
AEP's Principles of Business Conduct (which also serves as a code of ethics
applicable to Item 10 of this Form 10-K), certain committee charters and
Principles of Corporate Governance. 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.

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<PAGE>

<TABLE>
<CAPTION>



                                TABLE OF CONTENTS
                                                                                       Page
                                                                                      Number
<S>                                                                                  <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...................    29
   Executive Officers of the Registrants............................................    30

PART II

   Item    5. Market for Registrant's Common Equity,  Related Stockholder Matters and
              Issuer Purchases of Equity Securities.................................    31

   Item    6. Selected Financial Data...............................................    31

   Item    7. Management's Financial Discussion and Analysis and Financial Condition    32

   Item   7A. Quantitative and Qualitative Disclosures About Market Risk............    32

   Item    8. Financial Statements and Supplementary Data...........................    32

   Item    9. Changes  in  and  Disagreements  with  Accountants  on  Accounting  and
              Financial Disclosure..................................................    32

   Item   9A. Controls and Procedures...............................................    32

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........................    36

   Item   14. Principal Accountant Fees and Services................................    36

PART IV

   Item   15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K......    37
Signatures..........................................................................    39
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.
ALJ...........................  Administrative law judge
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 public utility
  subsidiaries................  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
KPSC..........................  Kentucky Public Service Commission
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.
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, anelectric 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
SO2...........................  Sulfur dioxide
SO2 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 
Virginia Act..................  Virginia electric restructuring legislation
VSCC..........................  Virginia State Corporation Commission
WVPSC.........................  West Virginia Public Service Commission 
West zone public utility
  subsidiaries................  PSO, SWEPCo, TCC and TNC

</TABLE>



<PAGE>

                           FORWARD-LOOKING INFORMATION

   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     Weather conditions.

o     Available sources and costs of fuels.

o     Availability of generating capacity and the performance of AEP's
      generating plants.

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

o     New legislation and government regulation including requirements for
      reduced emissions of sulfur, nitrogen, carbon and other substances.

o     Resolution of pending and future rate cases, negotiations and other
      regulatory decisions (including rate or other recovery for environmental
      compliance).

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

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

o     AEP's ability to reduce its operation and maintenance costs.

o     The success of disposing of investments that no longer match AEP's
      corporate profile.

o     AEP's ability to sell assets at attractive prices and on other attractive
      terms.

o     International and country-specific developments affecting foreign
      investments including the disposition of any current 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     AEP's ability to develop and execute on a point of view regarding prices
      of electricity, natural gas, and other energy-related commodities.

o     Changes in the creditworthiness and number of participants in the energy
      trading market.

o     Changes in the financial markets, particularly those affecting the
      availability of capital and AEP's ability to refinance existing debt at
      attractive rates.

o     Actions of rating agencies, including changes in the ratings of debt and
      preferred stock.

o     Volatility and changes in markets for electricity, natural gas, and other
      energy-related commodities.

o     Changes in utility regulation, including the establishment of a regional
      transmission structure.

o     Accounting pronouncements periodically issued by accounting
      standard-setting bodies.

o     The performance of AEP's pension plan.

o     Prices for power that we generate and sell at wholesale.

o     Changes in technology and other risks and unforeseen events, including
      wars, the effects of terrorism (including increased security costs), 
      embargoes and other catastrophic events.



<PAGE>



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, 2003, the subsidiaries of AEP had a total of 22,075
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 929,000
   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, 2003, APCo and its wholly owned subsidiaries had 2,371
   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 698,000 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, 2003, CSPCo had 1,125 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 575,000
   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, 2003, I&M had 2,634 employees. Among the
   principal industries served are primary metals, transportation equipment,
   electrical and electronic 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 175,000
   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, 2003, KPCo had
   394 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, 2003, 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 704,000 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, 2003, OPCo had
   2,153 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, 2003, PSO had 1,067 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 439,000
   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, 2003, SWEPCo had 1,351 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 711,000 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 participants. At December 31, 2003,
   TCC had 1,203 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 190,000 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, 2003, TNC had 472 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, 2003, Wheeling Power Company
   had 57 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, 2003, AEPSC had 6,215 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, 2003 are as follows:


<TABLE>
<CAPTION>

                                       AEP
                                   System(a) APCo CSPCo I&M KPCo
<S>                              <C>        <C>        <C>        <C>         <C>
                                                      (in thousands)
  Utility Operations:
    Retail Sales
      Residential..............  $3,171,000  $ 623,435  $ 509,919  $ 352,710  $120,001
      Commercial...............   2,348,000    321,515    455,304    272,319    68,904
      Industrial...............   1,977,000    342,593    133,242    319,783    94,567
      Other Retail Sales.......     173,000     41,060     17,975      6,154       926
                                 ----------  ---------  ---------  ---------  --------
         Total Retail..........   7,669,000  1,328,603  1,116,440    950,966   284,398

   Wholesale
     System Sales and
    Transmission...............   2,554,000    311,056    183,490    337,275    69,451
      Other Wholesale Revenues.           -          -          -          -         -
      Risk Management Realized.     205,000     17,391     10,491     11,440     4,038
      Risk Management Mark-
         to-Market ............    (198,000)    (2,249)    (5,134)         -         -
                                 ----------  ---------  ---------  ---------  --------
       Total Wholesale.........   2,561,000    326,198    188,847    348,715    73,489

    Other Operating Revenues...     745,000     79,583     42,195     46,712    18,775
    Sales to Affiliates........           -    222,793     84,369    249,203    39,808
                                 ----------  ---------  ---------  ---------  --------
       Gross Utility Operations  10,975,000  1,957,177  1,431,851  1,595,596   416,470
    Provision for Rate Refund..    (104,000)       181          -          -         -
                                 ----------- ---------  ---------  ---------  --------
         Net Utility Operations  10,871,000  1,957,358  1,431,851  1,595,596   416,470

  Investments- Gas Operations..   3,097,000          -          -          -         -
  Investments- Other...........     577,000          -          -          -         -
                                 ----------  ---------  ---------  ---------  --------
         Total Revenues........  $14,545,000 $1,957,358 $1,431,851 $1,595,596 $416,470
                                 =========== ========== ========== ========== ========
</TABLE>


<TABLE>
<CAPTION>

                                    OPCo         PSO     SWEPCo        TCC       TNC
                                                     (in thousands)
<S>                              <C>        <C>       <C>        <C>          <C>
 Utility Operations:
   Retail Sales
     Residential..............   $  474,323  $ 402,988 $ 350,386   $ 215,330  $  57,191
     Commercial...............      314,526    275,852   291,859     158,307     28,395
     Industrial...............      522,449    231,638   215,805      43,469      8,199
     Other Retail Sales.......        8,413     83,491     6,478       8,824     11,484
                                 ----------  --------- ---------   ---------  ---------
        Total Retail..........    1,319,711    993,969   864,528     425,930    105,269

  Wholesale
    System Sales and
   Transmission...............      263,397     61,173   147,885     894,509    279,973
     Other Wholesale Revenues.            -          -         -           -          -
     Risk Management Realized.       13,882      3,667     4,325      26,331      9,590
     Risk Management
       Mark-to-Market.........      (11,381)         -     3,439       2,801        911
                                 ----------- --------- ---------   ---------  ---------
        Total Wholesale.......      265,898     64,840   155,649     923,641    290,474

   Other Operating Revenues...       74,766     20,883    66,373     339,696     39,292
   Sales to Affiliates........      584,278     23,130    68,854     141,698     51,625
                                 ----------  --------- ---------   ---------  ---------
        Gross Utility Operations  2,244,653  1,102,822 1,155,404   1,830,965    486,660
   Provision for Rate Refund..            -          -    (8,562)    (83,454)   (20,714)
                                 ----------  --------- ----------  ---------- ----------
        Net Utility Operations    2,244,653  1,102,822 1,146,842   1,747,511    465,946
 Investments- Gas Operations..            -          -         -           -          -
 Investments- Other...........            -          -         -           -          -
                                 ----------  --------- ---------   ---------  ---------
        Total Revenues...........$2,244,653  $1,102,822$1,146,842  $1,747,511 $ 465,946
                                 ==========  ====================  ========== =========
</TABLE>

----------

(a) Includes revenues of other subsidiaries not shown. Intercompany transactions
   have been eliminated, including AEGCo's total revenues of $233,165,000 for
   the year ended December 31, 2003, all of which resulted from its wholesale
   business, including its marketing and trading of power.

Holding Company Regulation

   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 utility 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.

Financing

General

   Companies within the AEP System generally use short-term debt to finance
working capital needs, acquisitions and construction. The companies periodically
issue long-term debt to reduce short-term debt. Short-term debt has in recent
history been provided by AEP's commercial paper program and revolving credit
facilities. Proceeds were made available to subsidiaries under the AEP corporate
borrowing program. Throughout 2003, AEP was successful in accessing the
commercial paper market. 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, 2003, 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. See Management's Financial
Discussion and Analysis of Results of Operations, included in the 2003 Annual
Reports, under the heading entitled Financial Condition for additional
information with respect to AEP's credit agreements.

   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

   In 2003, the rating agencies conducted credit reviews of AEP and its
registrant subsidiaries. The agencies also reviewed many companies in the energy
sector due to issues that impact the entire industry.

   Moody's completed its review of AEP and its rated subsidiaries in February
2003. 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 placed AEP and its rated
subsidiaries on stable outlook.

   S&P completed its review of AEP and its rated subsidiaries in March 2003. 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 placed AEP and its
rated subsidiaries on stable outlook.

   Fitch completed its review of AEP and its rated subsidiaries in March 2003.
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 placed AEP and its rated subsidiaries on stable
outlook.

   See Management's Financial Discussion and Analysis of Results of Operations,
included in the 2003 Annual Reports, 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:

   o The CAA and CAAA and state laws and regulations (including State
     Implementation Plans) that require compliance, obtaining permits and
     reporting as to air emissions. See Management's Financial Discussion and
     Analysis of Results of Operations under the heading entitled The Current
     Air Quality Regulatory Framework.

   o 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 Financial Discussion and
     Analysis of Results of Operations under the headings entitled The Current
     Air Quality Regulatory Framework and New Source Review Litigation and Note
     9 to the consolidated financial statements entitled Commitments and
     Contingencies, included in the 2003 Annual Reports, for further
     information.

   o Rules issued by the EPA and certain states that require substantial
     reductions in SO2, mercury and NOx emissions, some of which became
     effective in 2003. The remaining compliance dates and proposals would take
     effect periodically through as late as 2018. AEP is installing (or has
     installed) emission control technology and is taking other measures to
     comply with required reductions. See Management's Financial Discussion and
     Analysis of Results of Operations under the headings entitled Future
     Reduction Requirements for NOx, SO2 and Hg and Estimated Air Quality
     Investments and Note 7 to the consolidated financial statements entitled
     Commitments and Contingencies, included in the 2003 Annual Reports under
     the heading entitled NOx Reductions for further information.

   o 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
     Financial Discussion and Analysis of Results of Operations, included in the
     2003 Annual Reports, under the heading entitled Superfund and State
     Remediation for further information.

   o The Federal Clean Water Act, which prohibits the discharge of pollutants
     into waters of the United States except pursuant to appropriate permits.
     The EPA recently adopted a new Clean Water Act rule to reduce the number of
     fish and other aquatic organisms killed at once-through cooled power
     plants. See Management's Financial Discussion and Analysis of Results of
     Operations, included in the 2003 Annual Reports, under the heading entitled
     Clean Water Act Regulation for additional information.

   o 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. See Management's
Financial Discussion and Analysis of Results of Operations, included in the 2003
Annual Reports, under the heading entitled Environmental Matters for information
on current environmental issues.

   If our expenditures for pollution control technologies, replacement
generation and associated operating costs are not recoverable from customers
through regulated rates (in regulated jurisdictions) or market prices (in
deregulated jurisdictions), those costs could adversely affect future results of
operations and cash flows, and possibly financial condition.

   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 resulted in a
significant reduction in the estimated economic life of those facilities. See
also Investments--UK Operations for a discussion of AEP's planned disposition of
these assets in 2004.

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

   See Management's Financial Discussion and Analysis of Results of Operations
under the heading entitled Environmental Matters and Note 7 to the consolidated
financial statements entitled Commitments and Contingencies, included in the
2003 Annual Reports, for further information with respect to environmental
matters.

Environmental Investments

   Investments related to improving AEP System plants' environmental performance
and compliance with air and water quality standards during 2002 and 2003 and the
current estimate for 2004 are shown below. Substantial investments in addition
to the amounts set forth below are expected 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 investments could be
significantly greater if litigation regarding whether AEP properly installed
emission control equipment on its plants is resolved against any AEP
subsidiaries or emissions reduction requirements are accelerated or otherwise
become more onerous. See Management's Financial Discussion and Analysis of
Results of Operations under the headings entitled Future Reduction Requirements
for NOx, SO2 and Hg and Estimated Air Quality Investments Note 7 to the
consolidated financial statements, entitled Commitments and Contingencies,
included in the 2003 Annual Reports, for more information regarding this
litigation and environmental expenditures in general.

                                       2002     2003     2004
                                      Actual   Actual  Estimate
                                           (in thousands)
      AEGCo.......................   $  1,200   11,800    9,800
      APCo........................    108,400   70,600  145,500
      CSPCo.......................     25,400   31,400   18,000
      I&M.........................      1,200   14,900   12,100
      KPCo........................    110,600   40,500    3,500
      OPCo........................    110,300   40,000  108,400
      PSO.........................      1,200    1,700        0
      SWEPCo......................      3,400    3,200    2,700
      TCC.........................        600      500        0
      TNC.........................      1,900    2,600      800
                                     -------- -------- --------
      AEP System..................   $364,200 $217,200 $300,800
                                     ======== ======== ========

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 are created by electricity flowing in
transmission and distribution lines, electrical equipment, household wiring, and
appliances.

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

SEC Subpoena, CFTC Complaint ant Other Energy Market Investigations

   AEP received data requests, subpoenas and information requests from the SEC,
CFTC and other state and federal governmental agencies relating to certain
energy market investigations. On September 30, 2003, the CFTC filed a complaint
against AEP in federal district court alleging that it provided false or
misleading information about market conditions and prices of natural gas in an
attempt to manipulate the price of natural gas. See Management's Financial
Discussion and Analysis of Results of Operations, included in the 2003 Annual
Reports, under the heading Energy Market Investigations.

Utility Operations

General

   Utility operations constitute the majority of AEP's business operations.
Utility operations include (i) the generation, transmission and distribution of
electric power to retail customers and (ii) the supplying and marketing of
electric power at wholesale (through the electric generation function) to other
electric utility companies, municipalities and other market participants. AEPSC,
as agent for AEP's public utility subsidiaries performs marketing, generation
dispatch, fuel procurement and power-related risk management and trading
activities.

Electric Generation

Facilities

   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 sales of certain of AEP's generating facilities.
Pursuant to regulatory orders, the AEP public utility subsidiaries operate their
generating facilities as a single interconnected and coordinated electric
utility system. See Item 2 -- Properties for more information regarding AEP's
generation capacity.

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 Interconnection
Agreement has been approved by the FERC.

   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, 2003, the member-load ratios were as
follows:
                               Peak
                               Demand Member-Load
                               (MW) Ratio (%)
         APCo...............  6,873        31.7
         CSPCo..............  3,871        17.9
         I&M................  4,243        19.6
         KPCo...............  1,564         7.2
         OPCo...............  5,121        23.6

   Although the FERC has approved CSPCo's and OPCo's request to withdraw from
the AEP Power Pool as part of its order approving the settlement agreements and
AEP's FERC restructuring application, CSPCo and OPCo plan to remain functionally
separated through at least December 31, 2008 as provided by their rate
stabilization plan filed with the PUCO. See Management's Financial Discussion
and Analysis and Financial Condition, under the heading entitled Corporate
Separation, included in the 2003 Annual Reports and Note 6 to the consolidated
financial statements, entitled Customer Choice and Industry Restructuring,
included in the 2003 Annual Reports, for a discussion of AEP's corporate
separation plan.

   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, 2001, 2002 and 2003:

                                 2001        2002       2003
                              ---------   ---------    -------
                                      (in thousands)
         APCo...............  $ 256,700  $ 127,000   $ 218,000
         CSPCo..............    251,200    267,000     276,800
         I&M................   (166,200) (113,600)    (118,800)
         KPCo...............     27,600    46,500       38,400
         OPCo...............   (369,300) (326,900)    (414,400)

   PSO, SWEPCo, TCC, TNC, and AEPSC are parties to a Restated and Amended
Operating Agreement originally dated as of January 1, 1997 (CSW Operating
Agreement), which has been approved by the FERC. The CSW Operating Agreement
requires the west zone public utility subsidiaries to maintain adequate 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 public utility subsidiaries as capacity commitments. Parties are
compensated for energy delivered to recipients based upon the deliverer's
incremental cost plus a portion of the recipient's savings realized by the
purchaser that avoids the use of more costly alternatives. Revenues and costs
arising from third party sales are shared based on the amount of energy each
west zone public utility subsidiary contributes that is sold to third parties.
Upon the sale of its generation assets, TCC will no longer supply generating
capacity under the CSW Operating Agreement.

   The following table shows the net (credits) or charges allocated among the
parties under the CSW Operating Agreement during the years ended December 31,
2001, 2002 and 2003:

                                     2001      2002      2003
                                   --------  --------   ------
                                         (in thousands)
             PSO.................  $  6,500 $ 53,700  $ 44,000
             SWEPCo..............   (62,300) (67,800)  (46,600)
             TCC.................    13,500  (15,400)  (29,500)
             TNC.................    42,300   29,500    32,100

   Power generated by or allocated or provided under the Interconnection
Agreement or CSW Operating Agreement to any public utility subsidiary is
primarily 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 Regulation -- Rates.

   Under both the Interconnection Agreement and CSW Operating Agreement, power
generated that is not needed to serve the native load of any public utility
subsidiary is sold in the wholesale market by AEPSC on behalf of the generating
subsidiary. See Risk Management and Trading for a discussion of the trading and
marketing of such power.

   AEP's System Integration Agreement, which has been approved by the FERC,
provides for the integration and coordination of AEP's east and west zone
operating subsidiaries. This includes joint dispatch of generation within the
AEP System and the distribution, between the two zones, of costs and benefits
associated with the transfers of power between the two zones (including sales to
third parties and risk management and trading activities). It is designed to
function as an umbrella agreement in addition to the Interconnection Agreement
and the CSW Operating Agreement, each of which controls the distribution of
costs and benefits within each zone.

Risk Management and Trading

   AEPSC, as agent for AEP's public utility subsidiaries, sells excess power
into the market and engages in power and natural gas risk management and trading
activities focused in regions in which AEP traditionally operates. These
activities primarily involve the purchase and sale of electricity (and to a
lesser extent, natural gas) under physical forward contracts at fixed and
variable prices. These contracts include physical transactions, over-the-counter
swaps and exchange-traded futures and options. The majority of physical forward
contracts are typically settled by entering into offsetting contracts. These
transactions are executed with numerous counterparties or on exchanges.
Counterparties and exchanges may require cash or cash related instruments to be
deposited on these transactions as margin against open positions. As of December
31, 2003, counterparties have posted approximately $45 million in cash, cash
equivalents or letters of credit with AEPSC for the benefit of AEP's public
utility subsidiaries. Since open trading contracts are valued based on changes
in market power prices, exposures change daily.

Fuel Supply

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

                                              2001   2002   2003
             Coal..........................   74%    78%    80%
             Natural Gas...................   12%     8%     7%
             Nuclear.......................   11%    11%     9%
             Hydroelectric and other.......    3%     3%     4%

   Variations in the generation of nuclear power are primarily related to
refueling and maintenance outages. Variations in the generation of natural gas
power are primarily related to the availability of cheaper alternatives to
fulfill certain power requirements and the deactivation of certain gas-fired
plants owned by TCC and TNC.

   Coal and Lignite: AEP's public utility subsidiaries 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. Management believes, but cannot provide assurances that,
AEP's public utility subsidiaries will be able to secure coal and lignite of
adequate quality and in adequate quantities to operate their coal and
lignite-fired units. See Investments-Other for a discussion of AEP's coal
marketing and transportation operations.

   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:

                                                      2001     2002    2003
                                                      ----     ----    ----
    Total coal delivered to AEP operated plants
     (thousands of tons)...........................  73,889   76,442  76,042
    Average price per ton of spot-purchased coal...  $27.30   $27.06  $28.91

   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 issues and
weather conditions which may interrupt deliveries. At December 31, 2003, the
System's coal inventory was approximately 42 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
relevant state regulatory agency has prescribed actions to be taken under
specified circumstances by System companies, subject to the jurisdiction of such
agency.

   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 138
billion cubic feet of natural gas during 2003 for generating power. A majority
of the gas-fired power 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 entered into 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. See Deactivation and Planned
Disposition of Generation Facilities for more information about TCC's interest
in STP.

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

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 spent nuclear
fuel 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:

   o Type of decommissioning plan selected;

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

   o Further development of regulatory requirements governing decommissioning;

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

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

   o Availability of nuclear waste disposal facilities; and

   o Approval of the Cook Plant's license extension.

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 Financial Discussion and Analysis of Results of Operations
and Note 7 to the consolidated financial statements, entitled Commitments and
Contingencies, included in the 2003 Annual Reports, 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. There is currently no set date
limiting AEP's access to the Utah facility.

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 mutually agreed to enter into
reliability must run agreements to continue operation of these seven plants.
With ERCOT's approval, AEP deactivated the remaining nine plants. The agreements
allowed ERCOT to terminate the agreement with 90 days notice if the facility was
no longer needed to ensure reliability of the electricity grid. ERCOT provided
such notice with respect to one TNC plant in August 2003 and the plant was
deactivated. AEP and ERCOT agreed to new reliability must run contracts at the
remaining six plants through December 2004, subject to the same termination
provision.

   TCC is conducting an auction to sell all of its generation facilities in
Texas to establish the market value of the assets and TCC's stranded costs in
accordance with the Texas Act. See Texas Regulatory Assets and Stranded Cost
Recovery and Post-Restructuring Wires Charges. The competitive bidding process
began in June 2003 after the PUCT issued a rule confirming TCC's ability to
establish the value of its generation assets and amount of stranded costs by
selling the generation assets. The PUCT has engaged a consultant and designated
a team to monitor the auction and advise TCC on the sale of its generating
assets, including requirements of the Texas Act for establishing stranded costs.

   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
Oklaunion Power Station, a hydroelectric facility and TCC's interest in STP. TCC
has entered into agreements to sell its 7.8% share of Oklaunion Power Station
and 25.2% share in STP and is continuing to evaluate bids for its remaining
generation assets. See Note 6 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, included in the 2003 Annual Reports,
for more information on the planned disposition of TCC generation facilities.

Structured Arrangements Involving Capacity, Energy, and Ancillary Services

   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. OPCo is entitled to
100% of the power generated by the facility, and is responsible for the fuel and
other costs of the facility through 2005. 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.

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, which have been approved by the FERC.

   The I&M Power Agreement provides for the sale by AEGCo to I&M of all the
capacity (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 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 capacity (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.

   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 from its generating capacity 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. The AEP-affiliated owners of OVEC are evaluating
the need for environmental investments related to their ownership interests.

   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 January
23, 2003, was recorded at 1,409,726 kilowatts.

Electric Transmission and Distribution

General

   AEP's public utility subsidiaries (other than AEGCo) 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 and approved by the state utility commissions of the states in which
they operate, and in some instances, approved by the FERC. See Regulation--
Rates. The FERC regulates and approves the rates for wholesale transmission
transactions. See Regulation-- FERC. As discussed below, some transmission
services also are separately sold to non-affiliated companies.

   AEP's public utility subsidiaries (other than AEGCo) 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 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 Competition.


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). The TEA has been approved by the FERC. Sharing
under the TEA 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, 2003, the member-load ratios were as follows:

                                      Peak
                                       Demand    Member-Load
                                        (MW)      Ratio (%)
         APCo...............           6,873       31.7
         CSPCo..............           3,871       17.9
         I&M................           4,243       19.6
         KPCo...............           1,564        7.2
         OPCo...............           5,121       23.6

   The following table shows the net (credits) or charges allocated among the
parties to the TEA during the years ended December 31, 2001, 2002 and 2003:

                                       2001      2002       2003
                                     --------  --------    ------
                                             (in thousands)
          APCo.....................  $ (3,100) $(13,400)$       0
          CSPCo....................    40,200    42,200    38,200
          I&M......................   (41,300)  (36,100)  (39,800)
          KPCo.....................    (4,600)   (5,400)   (5,600)
          OPCo.....................     8,800    12,700     7,200

   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 has been approved by the FERC and establishes a
coordinating committee, which is charged with the responsibility of overseeing
the coordinated planning of the transmission facilities of the 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, 2001, 2002 and 2003:

                                          2001     2002      2003
                                        -------  -------    ------
                                             (in thousands)
            PSO.......................  $ 4,000  $ 4,200  $ 4,200
            SWEPCo....................    5,400    5,000    5,000
            TCC.......................   (3,900)  (3,600)  (3,600)
            TNC.......................   (5,500)  (5,600)  (5,600)

   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 companies. See 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:

   o The allocation of transmission costs and revenues and

   o 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.

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 energy 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
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 may only be partially within AEP's control.

   In December 2002, AEP's public utility subsidiaries 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. The status of these applications is as follows:

o        The IURC conditionally approved the transfer of functional control of
         I&M's transmission assets to an RTO in September 2003, though the
         satisfaction of these conditions is not fully within I&M's or AEP's
         control;

o        In July 2003, the KPSC denied KPCo's request to join PJM based on a
         lack of evidence that it would benefit Kentucky retail customers, but
         granted KPCo's request for rehearing. KPCo filed a cost/benefit study
         in December 2003 and a rehearing has been scheduled for April 2004;

o        CSPCo and OPCo filed an application seeking approval of their plan to
         join PJM in  December  2002.  In  addition,  a group of  complainants
         have filed a  complaint  with the PUCO  alleging  that CSPCo and OPCo
         have  violated  Ohio law by not  participating  in an RTO and seeking
         (i)  a  suspension   of  certain   transmission-related   charges  to
         customers,  (ii)  requiring  that  CSPCo and OPCo  continue  to offer
         service at the prices set forth in their 1999  transition plan filing
         until  January 1, 2006 and (iii) a penalty  of  $25,000  for each day
         that  CSPCo  and  OPCo  do  not  participate  in  an  RTO.  The  PUCO
         consolidated  our  application  with the complaint in February  2003.
         The PUCO has stayed the matter  pending  greater  clarification  with
         respect to RTO matters at the FERC and elsewhere;

o        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 and  thereafter  only with
         VSCC approval.  The legislation  requires a transfer by January 2005.
         In January 2004, APCo filed a supplement to its application  with the
         VSCC consisting of a cost/benefit  analysis of its  participation  in
         PJM and  additional  information  required by the VSCC.  A hearing on
         APCo's Virginia application is scheduled for July 2004.

   In November 2003, the FERC issued an order (i) proposing to exempt AEP's east
zone public utility subsidiaries from Kentucky and Virginia laws requiring state
approval of the AEP east zone public utility subsidiaries' transfer of
functional control of their transmission assets to an RTO and (ii) directing
AEP's east zone public utility subsidiaries to join PJM by October 1, 2004.
Several issues, including whether the FERC may exempt AEP's east zone public
utility subsidiaries from Kentucky and Virginia law preventing them from joining
an RTO, have been heard by an administrative law judge. The FERC has directed
that an initial decision be issued by the ALJ by March 15, 2004.

   SWEPCo and PSO currently intend to transfer functional control of their
transmission assets to SPP subject to receipt of appropriate regulatory
approvals. In February 2004, the FERC conditionally approved SPP as an RTO. The
Arkansas Public Service Commission and LPSC have required filings related to
SWEPCo's and PSO's transfer of functional control of transmission facilities to
an RTO. The remaining west zone public utility subsidiaries (TCC and TNC) are
members of ERCOT.

   See Note 4 to the consolidated financial statements, entitled Rate Matters,
included in the 2003 Annual Reports and Management's Financial Discussion and
Analysis of Results of Operations under the heading entitled RTO Formation for a
discussion of public utility subsidiary participation in RTOs.

   Regional Through and Out Rates

   The FERC has proposed to eliminate our ability to collect certain
transmission charges associated with the transmission assets of our east zone
public utility subsidiaries and implement transitional rates to mitigate the
lost revenues for a two-year period commencing May 1, 2004. The FERC did not
indicate how or if the lost revenues would be recovered after the expiration of
the transitional rates. Management, however, believes that we are entitled to
recover costs of owning and operating these facilities, including a reasonable
rate of return. See Management's Financial Discussion and Analysis of Results of
Operations under the heading entitled FERC Order on Regional Through and Out
Rates for more information.

Regulation

General

   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 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 certain of its
subsidiaries are also subject to the broad regulatory provisions of PUHCA
administered by the SEC.

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 generally reflects 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 is no longer provided for in
Ohio. 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. Its fuel recovery rate was capped through
February 29, 2004 but is expected to return to traditional cost recovery.

   Ohio: CSPCo and OPCo each operates as a functionally separated utility and
provides "default" retail electric service to customers at unbundled rates
pursuant to the Ohio Act through December 31, 2005. Market-based default retail
generation service rates will be determined in accordance with PUCO rules after
December 31, 2005, unless the rate stabilization plan filed by CSPCo and OPCo
(which, among other things, addresses default retail generation service rates
from January 1, 2006 through December 31, 2008) is approved by the PUCO, in
which case retail generation rates would be determined consistent with the rate
stabilization plan until December 31, 2008. CSPCo and OPCo are and will continue
to provide distribution services to retail customers at rates approved by the
PUCO. These rates will be frozen from their levels as of December 31, 2005 to
(i) December 31, 2008 for CSPCo and (ii) December 31, 2007 (December 31, 2008,
if the rate stabilization plan is approved) for OPCo. Transmission services will
continue to be provided at rates established by the FERC. See Note 6 to the
consolidated financial statements, entitled Customer Choice and Industry
Restructuring, included in the 2003 Annual Reports, for more information.

   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 energy 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 energy costs.
Over or under collections of fuel costs for prior periods can be recovered when
new quarterly factors are established. See Note 4 to the consolidated financial
statements, entitled Rate Matters, included in the 2003 Annual Reports, for
information regarding current rate proceedings.

   Texas: The Texas Act requires the legal separation of generation-related
assets from transmission and 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. See Note
4 to the consolidated financial statements, entitled Rate Matters, included in
the 2003 Annual Reports, for information on current rate proceedings.

   In May 2003, the PUCT delayed competition in the SPP area of Texas until at
least January 1, 2007. 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. Management currently believes that implementation of the
plan is unlikely.

   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.

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

<TABLE>
<CAPTION>

                                                                                                   Percentage
                                                                   Fuel Clause Rates                 Of AEP
                                                                                     System Sales    System
                  Status of Base Rates for                                          Profits Shared  Retail
 Jurisdiction  Power Supply   Energy Delivery      Status            Includes        w/Ratepayers   Revenues(1)
 ------------  -------------- ---------------      --------          ----------      -------------- -----------
<S>           <C>            <C>                  <C>             <C>              <C>                 <C>

Ohio           Frozen         Distribution         None             Not applicable   Not applicable      32%
               through        frozen through
               2005(2)        2007 for OPCo and
                              2008 for CSP;
                              Transmission frozen
                              through 2005
 Texas-ERCOT
 (TCC, TNC)    See footnote 3 Not capped or frozen Not applicable   Not applicable   Not applicable       9%(3)
 Texas- SPP
 (SWEPCo, TNC) Not  capped or                      Active           Fuel and fuel    Yes, above base      5%
               frozen                                               portion of       levels
                                                                    purchased
                                                                    power
 Oklahoma      Not  capped or                      Active           Fuel and fuel    Yes                 13%
               frozen                                               portion of
                                                                    purchased
                                                                    power
 Indiana       Capped until                        Active           Fuel and Fuel    No                  10%
               1/1/05 (4)                                           portion of
                                                                    purchased
                                                                    power
 Virginia      Capped until   Capped until         Active           Fuel and fuel    No                  9%
               as late        as late                               portion of
               as 7/1/07(5)   as 7/1/07(5)                          purchased
                                                                    power
 West          Not  capped or                      Suspended(6)     Fuel and fuel    Yes, but             9%
 Virginia      frozen                                               portion of       suspended
                                                                    purchased
                                                                    power
 Louisiana     Capped until                        Active           Fuel and fuel    Yes, above           4%
               6/15/05                                              portion of       base levels
                                                                    purchased
                                                                    power
 Kentucky(7)   Not capped or                       Active           Fuel and fuel    Yes, above           4%
               frozen                                               portion of       base levels
                                                                    purchased
                                                                    power
 Arkansas      Not capped or                       Active           Fuel and fuel    Yes, above           2%
               frozen                                               portion of       base levels
                                                                    purchased
                                                                    power
 Michigan      Capped until   Capped until         Active           Fuel and fuel    Yes, in some         2%
               1/1/05(8)      1/1/05(8)                             portion of       areas
                                                                    purchased
                                                                    power
 Tennessee     Not capped or                       Active           Fuel and fuel    No                   1%
               frozen                                               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, 2003.

(2) CSPCo and OPCo have filed a rate stabilization plan with the PUCO to
   establish (after the market development period) a rate stabilization period
   from January 1, 2006 through December 31, 2008 during which their default
   retail generation rates would be established pursuant to such filing. The
   rate stabilization plan would also extend OPCo's distribution rate freeze
   through the end of 2008.

(3) 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.

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

(5) Base rates are capped until the earlier of July 1, 2007 or a finding by the
   VSCC that a competitive market for generation exists. One-time change in
   non-generation rates is allowed in Virginia.

(6) Expanded net energy clause suspended in West Virginia pursuant to a 1999
   rate case stipulation, but subject to change in a future proceeding.

(7) KPCo applied for an environmental surcharge to recover costs incurred in
   connection with the installation of emission control equipment and in 2003
   the KPSC granted recovery of $18 million.

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


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 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. This was done in connection with the FERC's adoption of a new
test called supply management assessment (SMA). In December 2003, the FERC
issued a staff paper discussing alternatives to SMA and held a technical
conference in January 2004. See Note 7 to the consolidated financial statements,
entitled Commitments and Contingencies, included in the 2003 Annual Reports, for
more information on the current status of this proceeding.

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 has been delayed by the PUCT until at
least 2007. AEP's public utility subsidiaries operate in both the ERCOT and SPP
areas of Texas.

   Implementation of legislation enacted in West Virginia to allow retail
customers to choose their electricity supplier is on hold. 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. Management currently believes that
implementation of the plan is unlikely. In February 2003, Arkansas repealed its
restructuring legislation.

   See Note 5 to the consolidated financial statements, entitled Effects of
Regulation, included in the 2003 Annual Reports, for a discussion of the effect
of restructuring and customer choice legislation on accounting procedures. See
Note 6 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring and Management's Financial Discussion and Analysis and
Financial Condition, included in the 2003 Annual Reports, under the heading
entitled Corporate Separation for a discussion of AEP's corporate separation
plan.

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, 2003, 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.
CSPCo and OPCo have filed a rate stabilization plan with the PUCO that, among
other things, addresses default generation service rates from January 1, 2006
through December 31, 2008. See Regulation--FERC for a discussion of FERC
regulation of transmission rates and Regulation--Rates--Ohio for a discussion of
the impact of restructuring on distribution rates. If the PUCO approves the rate
stabilization plan filed by CSPCo and OPCo, they will remain functionally
separated through at least December 31, 2008.

Texas Restructuring

   Signed into law in June of 1999, the Texas Act substantially amended the
regulatory structure governing electric utilities in Texas in order to allow
retail electric competition for all customers. Among other things, the Texas
Legislation:

o     gave Texas customers the opportunity to choose their REP beginning January
      1, 2002 (delayed until at least 2007 in the SPP portion of Texas),

o     required each utility to legally separate into a REP, a power generation
      company, and a transmission and distribution utility, and

o     required that REPs obtain electricity 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, at the PTB, until
      certain conditions in the Texas Legislation are met.

   The Texas Act provides each affected utility an opportunity to recover its
generation related regulatory assets and stranded costs resulting from the legal
separation of the transmission and distribution utility from the generation
facilities and the related introduction of retail electric competition.
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 (as of December 31,
2001) over the market value of those assets, taking specified factors into
account, as ultimately determined in a PUCT true-up proceeding (the True-Up
Proceeding).

   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 Texas Regulatory Asset and Stranded Cost Recovery and
Post-Restructuring Wires Charges.

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.

Texas  Regulatory  Assets and Stranded  Cost  Recovery and  Post-Restructuring
Wires Charges

   TCC and TNC may recover generation-related regulatory assets and
plant-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. Plant-related stranded
costs consist of the positive excess of the net regulated book value of
generation assets (as of December 31, 2001) 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 generation-related regulatory
assets and, after the 2004 true-up proceeding, the amount of plant-related
stranded costs and remaining generation-related regulatory assets not previously
securitized. Securitization bonds allow for regulatory assets and plant-related
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 plant-related stranded costs or generation-related regulatory assets not
recovered through the sale of securitization bonds may be recovered through a
separate non-bypassable competitive transition charge to transmission and
distribution customers.

Generation-Related 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. Another $185 million of regulatory assets are being recovered through
distribution rates beginning in January 2002. Remaining generation related
regulatory assets of approximately $195 million will be included in TCC's
request to recover stranded costs in the True-Up Proceeding.

Plant-Related Stranded Costs

      It is anticipated that TCC will have significant plant-related stranded
costs following the planned sale of its generation assets. As noted, stranded
costs are ultimately determined in the True-Up Proceeding. The PUCT adopted a
rule regarding the timing of the True-Up Proceedings scheduling TNC's filing
(which has no generation related stranded costs) in May 2004 and TCC's filing in
September 2004 or 60 days after the completion of the sale of TCC's generation
assets, if later.

2004 True-Up Proceedings

      The purpose of the True-Up Proceeding is to (i) quantify and reconcile the
amount of plant-related stranded costs and generation-related regulatory assets
taking into account amounts that have not been securitized; (ii) conduct
wholesale capacity auction true-ups; (iii) establish final fuel recovery
balances; (iv) determine the retail clawback component; and (v) quantify
unrefunded excess earnings (collectively, the True-Up Adjustment). The True-Up
Adjustment will be reflected as either additional charges or credits to retail
customers through transmission and distribution rates collected by REPs and
remitted to the utility.

      After final determination of True-Up Adjustments by the PUCT, TCC may
issue securitization bonds in an amount equal to the sum of (i) its
plant-related stranded costs (where applicable) and (ii) generation-related
regulatory assets, less its generation-related regulatory assets that have been
previously securitized. If securitization bonds are not issued to finance all
such amounts, TCC will seek recovery of these amounts as well as the other
components of the True-Up Adjustments through non-bypassable competition
transition charges in transmission and distribution rates.

      Plant-Related Stranded Cost Determination: The Texas Legislation
authorized the use of several valuation methodologies to quantify plant-related
stranded costs in the True-Up Proceeding, including by the sale of assets. TCC
intends to sell its generation assets in order to obtain their market value for
the purpose of determining plant-related stranded costs for the True-Up
Proceeding and comply with the Texas Legislation. In the True-Up Proceeding, the
amount of plant-related stranded costs under this market valuation methodology
will be the amount by which net book value of TCC's generating assets exceeds
the market value of the generation assets as measured by the net proceeds from
the sale of the assets.

   Wholesale Capacity Auction True-Up Component: The PUCT used a computer model
or projection, called an ECOM model, to estimate stranded costs related to
generation plant assets in the unbundled cost of service proceedings. See Note 4
to the consolidated financial statements, entitled Rate Matters, included in the
2003 Annual Reports for further discussion. 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
Legislation during the period of January 1, 2002 through December 31, 2003 will
be a component of the True-Up Proceeding, either increasing or decreasing the
amount of recovery for TCC. Actual market prices have been lower than the ECOM
model market prices. Therefore, TCC recorded a $480 million regulatory asset and
related revenues for 2002 and 2003.

   Fuel Recovery Balance Determination: 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 and TNC have filed. In 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 True-Up Proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case that established TNC's unrecovered fuel balance, including interest for the
ERCOT service territory, at $6.2 million. This balance will be included in TNC's
2004 true-up proceeding. In 2002, TCC filed with the PUCT to reconcile fuel
costs and to establish its deferred over-recovery of fuel balance for inclusion
in the 2004 True-Up Proceeding. In February 2004, an ALJ issued recommendations
finding a $205 million over-recovery in this fuel proceeding. See TCC Fuel
Reconciliation and TNC Fuel Reconciliation in Note 4 to the consolidated
financial statements, entitled Rate Matters, included in the 2003 Annual
Reports, for further discussion. Any over-recovery, plus interest thereon, will
be credited to customers as a component of the True-Up Proceeding.

   Retail Clawback Component: The Texas Legislation provides for each price to
beat (PTB) retail electricity provider (REP) to refund to its affiliated
transmission and distribution utility the excess of the PTB revenues over market
prices (subject to certain conditions and a limitation of $150 per customer).
This retail clawback applies only to the (i) residential and (ii) small
commercial classes of customers. If 40% of the load for such customer class is
served by competitive REPs, the retail clawback is not applied for such class.
During 2003, TCC and TNC filed to notify the PUCT that competitive REPs serve
over 40% of the load in the small commercial class. The PUCT has ruled that this
threshold has been met with respect to the small commercial class for each of
TCC and TNC. AEP had accrued a total regulatory liability of approximately $66
million for all obligations related to retail clawback on its REP's books. As a
result of the PUCT ruling on the small commercial retail clawback, $9 million of
this regulatory liability was no longer required and was reversed.

   Unrefunded Excess Earnings Component: The Texas Legislation provides, as a
component of the True-Up Proceeding, for an earnings test each year from 1999
through 2001. The Texas Legislation requires PUCT approval of the annual
earnings test calculation. The PUCT has ruled that each of SWEPCo, TCC and TNC
has excess earnings and, in certain instances, has ordered a reduction in
distribution rates for the purpose of eliminating such excess earnings. AEP has
appealed both the methodology of determining excess earnings and the reduction
of distribution rates. See Note 4 to the consolidated financial statements,
entitled Rate Matters, included in the 2003 Annual Reports, for further
discussion, including the specific amounts in dispute. The PUCT rulings and the
reduction in distribution rates effectively removes unrefunded excess earnings
as a component to be determined by the True-Up Proceedings. To the extent AEP
prevails in its appeal of the reduction in distribution rates, unrefunded excess
earnings, as finally determined, would be included in the True-Up Proceedings
and result in a reduction of the True-Up Adjustment.

   Pursuant to PUCT rules, if total stranded costs determined in the 2004
True-Up Proceeding are less than the amount of previously securitized regulatory
assets, the PUCT can implement an offsetting credit to transmission and
distribution rates. The Texas Third Court of Appeals ruled in February 2003 that
the Texas Legislation 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 final
under-recovered fuel amounts. Portions of this ruling have been appealed to the
Texas Supreme Court. See Note 4 to the consolidated financial statements,
entitled Rate Matters, included in the 2003 Annual Reports, for more
information.

   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 currently non-securitized
plant-related 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 currently non-securitized
plant-related 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 6 to the consolidated financial statements entitled
Customer Choice and Industry Restructuring, included in the 2003 Annual Reports.

Competition

   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 (through December 31, 2004) to Centrica, which provides PTB service
to certain former customers of TCC and TNC and must compete for customers. See
Regulation -- Rates for a description of the setting of rates for power sold at
bundled or unbundled state-regulated rates.

   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 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 Financial Discussion and Analysis of Results of Operations
and Note 6 to the consolidated financial statements entitled Customer Choice and
Industry Restructuring, included in the 2003 Annual Reports, for further
information with respect to restructuring legislation affecting AEP
subsidiaries.

   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.

   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.

Seasonality

   The 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 into which
AEP enters. 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.


Investments-Gas Operations

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

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

   o 127 billion cubic feet of storage among two facilities;

   o Five natural gas processing plants; and

   o Certain gas marketing contracts.

   AEP, in operating its natural gas assets, enters into transactions for the
purchase and sale of natural gas. These transactions involve (i) purchases of
natural gas from producers and subsequent sales to end users and local
distribution companies, (ii) physical gas transactions along our natural gas
pipelines to maximize revenue, based on price differences between various
locations along those assets and (iii) physical (some of which involve purchases
of gas that is stored in AEP storage assets) and financial transactions to
mitigate price volatility risk. Gas transactions are executed (i) with numerous
counterparties, (ii) directly with brokers or (iii) 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. As of December
31, 2003, counterparties posted approximately $224 million in cash, cash
equivalents and letters of credit with AEPES to satisfy the counterparties'
obligations in connection with natural gas transactions. AEPES posted
approximately $42 million. Since AEP's open gas trading contracts are valued
based on changes in gas market prices, our exposures change daily.

   AEP's trading and marketing operations are generally limited to risk
management and are focused in regions in which AEP owns assets.

   AEP acquired its Bammel storage facility (which has approximately 118 billion
cubic feet of storage capacity) from Enron Corporation and certain of its
subsidiaries. Because Enron and its relevant subsidiary are now bankrupt, the
bankruptcy trustee and other third parties have taken and may take additional
positions in the bankruptcy proceedings or litigation that seek to limit or
compromise our use of this facility. See Notes 7 and 10 to the consolidated
financial statements entitled Commitments and Contingencies and Acquisitions,
Dispositions, Discontinued Operations, Impairments, Assets Held for Sale and
Assets Held and Used, respectively, included in the 2003 Annual Reports for more
information.

   During the third quarter of 2003, we selected an advisor to review our
options regarding the assets of our gas operations business. In February 2004,
we signed a definitive agreement to sell Louisiana Intrastate Gas (which has
approximately 2000 miles of pipeline) and intend to complete the sale of the
Jefferson Island storage facility (which has approximately 9 billion cubic feet
of storage capacity) in 2004. We are considering our options with respect to our
Houston Pipe Line and related assets. See Note 10 to the consolidated financial
statements entitled Dispositions, Discontinued Operations, Impairments, Assets
Held for Sale and Assets Held and Used, included in the 2003 Annual Reports for
more information.


Investments-UK Operations

   AEP, through certain subsidiaries, operates and owns 4,000 MW of power
generation facilities in the UK and engaged in the following activities
throughout 2003:

   o Selling wholesale power in the UK;

   o Trading and marketing power transactions, with numerous counterparties,
     predominantly limited to risk management around assets used or managed by
     AEP subsidiaries in the UK. Since AEP's open power trading contracts are
     valued based on changes in market power prices, our exposures change daily;
     and

   o Procuring and transporting coal to fuel AEP's UK generation facilities and
     for sale to third parties. Its third party transactions exist because
     transporting coal is more economical in quantities exceeding those required
     to operate AEP assets. AEP uses financial instruments executed with
     numerous counterparties to manage the financial risk of these activities.
     Since AEP's open coal and freight contracts are based on changes in market
     prices, our exposures change daily.

   AEP expects to sell all its UK operations assets and contracts as a going
concern, in one or more transactions, by the end of 2004. During the fourth
quarter of 2003, AEP selected an advisor for the disposition of its UK business.

Investments- Other

General

   AEP, through certain subsidiaries, conducts certain business operations other
than those included in other segments in which it uses and manage a portfolio of
energy-related assets. Consistent with its business strategy, AEP intends to
dispose of many of these non-core assets. The assets currently used and managed
include:

   o 1,354 MW of domestic and 1,235 MW of international power generation
     facilities (of which its ownership is approximately 827 MW and 680 MW,
     respectively);

   o Coal mines and related facilities; and

   o Barge, rail and other fuel transportation related assets.

   These operations include the following activities:

   o 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;

   o Holding and/or operating various properties, coal reserves, mining
     operations and royalty interests in Colorado, Kentucky, Louisiana, Ohio,
     Pennsylvania and West Virginia; and

   o Through MEMCO Barge Line Inc., transporting 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 towboats and two coal handling
     terminals with 20 million tons of annual capacity.

   AEP has in the past two years written down the value of certain of these
investments. See Management's Financial Discussion and Analysis of Results of
Operations and Note 10 to the consolidated financial statements entitled
Acquisitions, Dispositions, Discontinued Operations, Impairments, Assets Held
for Sale and Assets Held and Used, included in the 2003 Annual Reports.

Dow Chemical Cogeneration Facility

   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. AEP's subsidiary, OPCo, 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 for twenty years to Tractebel
Energy Marketing, Inc. (Tractebel). The power supply contract with Tractebel is
in dispute. See Notes 7 and 10 to the consolidated financial statements,
entitled Commitments and Contingencies and Acquisitions, Dispositions,
Discontinued Operations, Impairments, Assets Held for Sale and Assets Held and
Used, respectively, included in the 2003 Annual Reports, for more information.




I
tem 2. Properties

Generation Facilities

General

   At December 31, 2003, 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:

                        Coal    Natural  Hydro  Nuclear  Lignite  Oil   Total
 Company     Stations    MW     Gas MW    MW      MW       MW      MW    MW
 -------     --------  ------   -------  ----   -----     ----    ---- ----

 AEGCo......  1(a)       1,300                                         1,300
 APCo....... 17(b)       5,073            798                          5,871
 CSPCo......  6(e)       2,595                                         2,595
 I&M........ 10(a)       2,295             11    2,143                 4,449
 KPCo.......  1          1,060                                         1,060
 OPCo.......  8(b)(f)    8,472             48                          8,520
 PSO........  8(c)       1,018   3,139                             25  4,182
 SWEPCo.....  9          1,848   1,797                    842          4,487
 TCC........ 12(c)(d)(g)   686   3,175      6      630                 4,497
 TNC........ 12(c)         377     999                             10  1,386
             --          -----    ----    ---     ----    ---      --  -----
 Totals:     84          24,724  9,110    863    2,773    842      35 38,347
             --          ------  -----    ---    -----    ---      -- ------

(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) See Item 1 -- Utility Operations -- Electric Generation -- Deactivation and
   Planned Disposition of Generation Facilities for a discussion of TCC's
   planned disposition of all 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, 2003 is listed below.

                                                  Capacity   Ownership
 Facility                    Fuel      Location   Total MW   Interest    Status
 --------                 ---------    --------  ----------  ---------   ------
 Brush II (a)...........  Natural gas  Colorado      68       47.75%       QF
 Desert Sky Wind Farm...  Wind         Texas        161      100%         EWG
 Mulberry...............  Natural gas  Florida      120       46.25%       QF
 Orange Cogen...........  Natural gas  Florida      103       50%          QF
 Sweeny.................  Natural gas  Texas        480       50%          QF
 Thermo Cogeneration (a)  Natural gas  Colorado     272       50%          QF
 Trent Wind Farm........  Wind         Texas        150      100%         EWG
                                                   ----
 Total U.S.                                       1,354
                                                  -----

 Bajio..................  Natural gas  Mexico       605       50%        FUCO
 Ferrybridge (b)........  Coal         United     2,000      100%        FUCO
                                       Kingdom
 Fiddler's Ferry (b)....  Coal         United     2,000      100%        FUCO
                                       Kingdom
 Nanyang (a)............  Coal         China        250       70%        FUCO
 Southcoast (a).........  Natural gas  United       380       50%        FUCO
                                       Kingdom     ----
 Total International                              5,235
                                                  -----

(a) See Note 10 to the consolidated financial statements entitled Acquisitions,
   Dispositions, Discontinued Operations, Impairments, Assets Held for Sale and
   Assets Held and Used, included in the 2003 Annual Reports, for a discussion
   of AEP's planned use and/or disposition of independent power producer and
   foreign generation assets.

(b) Ferrybridge and Fiddler's Ferry are properties that have been designated as
   discontinued operations and intended to be sold in 2004. See Note 10 to the
   consolidated financial statements entitled Acquisitions, Dispositions,
   Discontinued Operations, Impairments, Assets Held for Sale and Assets Held
   and Used, included in the 2003 Annual Reports, for more information.

Cook Nuclear Plant and STP

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

                                          Cook Plant              STP(a)
                                       Unit 1    Unit 2      Unit 1    Unit 2
 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........................  1,036,000 1,107,000   1,250,600  1,250,600
 Net Capacity Factors
  2003 (c)........................     73.5%     74.5%       62.0%     81.2%
  2002.............................    86.6%     80.5%       99.2%     75.0%
  2001 (d).........................    87.3%     83.4%       94.4%     87.1%

------------
(a) Reflects total plant.

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

(c) The capacity factors for both units of the Cook Plant were reduced in 2003
   due to an unplanned maintenance outage to implement upgrades to the traveling
   water screens system following an alewife fish intrusion.

(d) 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.

   Costs associated with the operation (excluding fuel), maintenance and
retirement of nuclear plants continue to be more significant 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 -- Utility Operations -- Electric 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 7 to the consolidated financial statements
entitled Commitments and Contingencies, incorporated by reference in Item 8, for
information with respect to nuclear incident liability insurance.

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:

                                          Total Overhead
                                          Circuit Miles of
                                          Transmission and   Circuit Miles of
                                         Distribution Lines  765,000-volt Lines
                                         ------------------  ------------------
  AEP System (a).........................   216,685(b)          2,026
  APCo..................................     50,969               644
  CSPCo. (a)............................     14,016                --
  I&M...................................     21,957               615
  Kingsport Power Company...............      1,338                --
  KPCo..................................     10,703               258
  OPCo..................................     30,559               509
  PSO...................................     21,531                --
  SWEPCo................................     20,879                --
  TCC...................................     29,424                --
  TNC...................................     13,622                --
  Wheeling Power Company................      1,688                --

------------
(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 generating facilities 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 AEP's public utility subsidiaries in the realty on
which their facilities are located are considered adequate for use in the
conduct of their 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. AEP's public utility subsidiaries 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, Louisiana,
Michigan, Ohio, Texas, Tennessee, 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, with input from its state utility commissions, continuously
assesses 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. APCo must still receive additional
federal permits, but does not expect that obtaining these will negatively affect
its ability to complete construction.

Construction Expenditures

   The following table shows construction expenditures (including environmental
and non-utility plant expenditures) during 2001, 2002 and 2003 and current
estimates of 2004 construction expenditures, in each case including AFUDC but
excluding assets acquired under leases.

                              2001         2002        2003        2004
                             Actual       Actual      Actual     Estimate
                                           (in thousands)
AEP System (a)........... $1,832,000   $1,709,800   $1,358,400  $1,531,300
  AEGCo..................      6,900        5,300       22,200      18,400
  APCo...................    306,000      276,500      288,800     405,900
  CSPCo..................    132,500      136,800      136,300     130,300
  I&M....................     91,100      159,400      184,600     185,600
  KPCo...................     37,200      178,700       81,700      36,100
  OPCo...................    344,600      354,800      249,700     303,800
  PSO....................    124,900       89,400       86,800      80,100
  SWEPCo.................    112,100      111,800      121,100      99,600
  TCC....................    194,100      151,500      141,800     150,500
  TNC....................     39,800       43,600       46,700      57,800

---------
(a) Includes expenditures of other subsidiaries not shown. Amounts in 2001 and
2002 include construction expenditures related to entities classified in 2003 as
discontinued operations. Those amounts were $186,500,000 and $24,900,000,
respectively.

   See Note 7 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 7 to the
consolidated financial statements, entitled Commitments and Contingencies,
incorporated by reference in Item 8.


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, 2004.

Name                      Age                     Office (a)
Michael G. Morris......   57   Chairman of the Board, President and Chief
                               Executive Officer of AEP and of AEPSC
Thomas V. Shockley, III   58   Vice Chairman of AEP and Vice Chairman and Chief
                               Operating Officer of AEPSC
Henry W. Fayne.........   57   Vice President of AEP, Executive Vice President
                               of AEPSC
Thomas M. Hagan........   59   Executive Vice President-Shared Services of AEPSC
Holly K. Koeppel.......   45   Executive Vice President of AEPSC
Robert P. Powers.......   50   Executive Vice President-Generation of AEPSC
Susan Tomasky..........   50   Vice President of AEP, Executive Vice President-
                               Policy, Finance and Strategic Planning of AEPSC
----------
(a) Messrs. Fayne and Powers and Ms. Tomasky have been employed by AEPSC or
   System companies in various capacities (AEP, as such, has no employees) for
   the past five years. Prior to joining AEPSC in June 2000 as Senior Vice
   President-Governmental Affairs, Mr. Hagan was Senior Vice President-External
   Affairs of CSW (1996-2000). Prior to joining AEPSC 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 AEPSC 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). Prior to joining AEPSC in his current position in January 2004,
   Mr. Morris was Chairman of the Board, President and Chief Executive Officer
   of Northeast Utilities (1997-2003). 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 AEPSC, 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, 2004, 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.

<TABLE>
<CAPTION>

Name                              Age    Position (a)(b)                                      Period
----                             -----   ---------------                                      ------
<S>                              <C>    <C>                                                  <C>
Michael G. Morris (a)(b).......   57     Chairman of the Board, President, Chief Executive    2004-Present
                                         Officer and Director of AEP
                                         Chairman of the Board, Chief Executive
                                         Officer and 2004-Present Director of
                                         AEPSC, APCo, I&M, OPCo, SWEPCo and TCC
                                         Chairman of the Board, President and
                                         Chief Executive 1997-2003 Officer of
                                         Northeast Utilities
Thomas V. Shockley, III (a)....   58     Director and Vice President of APCo, I&M, OPCo,
                                         SWEPCo and TCC                                       2000-Present
                                         Chief Operating Officer of AEPSC                     2001-Present
                                         Vice Chairman of AEP and AEPSC                       2000-Present
                                         President and Chief Operating Officer of CSW         1997-2000
                                         Executive Vice President of CSW                      1990-1997
Henry W. Fayne (a).............   57     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 AEPSC                    2001-Present
                                         Executive Vice President-Finance and Analysis of
                                         AEPSC                                                2000-2001
                                         Executive Vice President-Financial Services of AEPSC 1998-2000
Thomas M. Hagan (a)............   59     Director  and  Vice  President  of  APCo, I&M, OPCo,
                                         SWEPCo and TCC                                       2002-Present
                                         Executive Vice President-Shared Services of AEPSC    2002-Present
                                         Senior Vice President-Governmental Affairs of AEPSC  2000-2002
                                         Senior  Vice  President-External  Affairs of CSW     1996-2000
Holly K. Koeppel...............   45     Executive Vice President of AEPSC                    2002-Present
                                         Vice President-New Ventures                          2000-2002
                                         Regional Vice President of Asia-Pacific Operations
                                         for Consolidated Natural Gas  International          1996-2000
Robert P. Powers (a)...........   50     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 AEPSC                          2001-2003
                                         Senior Vice President-Nuclear Operations of AEPSC    2000-2001
                                         Senior Vice President-Nuclear Generation of AEPSC    1998-2000
Susan Tomasky (a)..............   50     Director  and  Vice  President  of  APCo, I&M, OPCo,
                                         SWEPCo and TCC                                       2000-Present
                                         Executive Vice President-Policy, Finance and
                                         Strategic Planning of AEPSC                          2001-Present
                                         Executive Vice President-Legal, Policy and
                                         Corporate Communications and General Counsel of
                                         AEPSC                                                2000-2001
                                         Senior Vice President and General Counsel of AEPSC   1998-2000
</TABLE>


----------
(a) Messrs. Fayne, Hagan, Morris, Powers and Shockley and Ms. Tomasky are
   directors of AEGCo, CSPCo, KPCo, PSO and TNC. Messrs. Morris and Shockley are
   also directors of AEP.

(b) Mr. Morris is a director of Cincinnati Bell, Inc., Spinnaker Exploration Co.
   and Flint Ink.


PART II


Item 5. Market for Registrants'  Common Equity,  Related  Stockholder  Matters
and Issuer Purchases of Equity Securities

   AEP. The information required by this item is incorporated herein by
reference to the material under Common Stock and Dividend Information in the
2003 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 2003 and 2002 are
incorporated by reference to the material under Statement of Retained Earnings
in the 2003 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 2003 Annual Reports.


Item  7.  Management's   Financial   Discussion  and  Analysis  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 Financial Discussion and Analysis in the 2003
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 Financial
Discussion and Analysis in the 2003 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 Financial Discussion and Analysis in the 2003 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.


Item 9A. Controls and Procedures

   During 2003, AEP's management, including the principal executive officer and
principal financial officer, evaluated AEP's disclosure controls and procedures
relating to the recording, processing, summarization and reporting of
information in AEP's periodic reports that it files with the SEC. These
disclosure controls and procedures have been designed to ensure that (a)
material information relating to AEP, including its consolidated subsidiaries,
is made known to AEP's management, including these officers, by other employees
of AEP and its subsidiaries, and (b) this information is recorded, processed,
summarized, evaluated and reported, as applicable, within the time periods
specified in the SEC's rules and forms. AEP's controls and procedures can only
provide reasonable, not absolute, assurance that the above objectives have been
met.

   As of December 31, 2003, these officers concluded that the disclosure
controls and procedures in place provide reasonable assurance that the
disclosure controls and procedures can accomplish their objectives. AEP
continually strives to improve its disclosure controls and procedures to enhance
the quality of its financial reporting and to maintain dynamic systems that
change as events warrant.

   There have not been any changes in AEP's internal controls over financial
reporting (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the
Exchange Act) during the fourth quarter of 2003 that have materially affected,
or are reasonably likely to affect, AEP's internal control over financial
reporting.



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 2004 annual meeting of shareholders, to be filed within 120 days
after December 31, 2003. 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 2004 annual meeting of
stockholders, to be filed within 120 days after December 31, 2003. 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 2004 annual meeting of stockholders, to be
filed within 120 days after December 31, 2003. 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, 2004, 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.

<TABLE>
<CAPTION>

 Name                             Age              Position (a)                 Period
 ----                            ------            ------------                 ------
<S>                              <C>    <C>                                    <C>

 K. G. Boyd....................   52     Director                               1997-Present
                                         Vice President (Appointed)--Fort
                                         Wayne Region Distribution Operations   2000-Present
                                         Indiana Region Manager                 1997-2000
 John E. Ehler.................   47     Director                               2001-Present
                                         Manager of Distribution Systems-Fort
                                         Wayne District                         2000-Present
                                         Region Operations Manager              1997-2000
 Patrick C. Hale...............   49     Director                               2003-Present
                                         Plant Manager, Rockport Plant          2003-Present
                                         Energy Production Manager, Rockport
                                         Plant                                  2001-2003
                                         Energy Production Manager, Mountaineer
                                         Plant (APCo)                           1997-2001
 David L. Lahrman..............   52     Director and Manager, Region Support   2001-Present
                                         Fort Wayne District Manager            1997-2001
 Marc E. Lewis.................   49     Director                               2001-Present
                                         Assistant General Counsel of the
                                         Service Corporation                    2001-Present
                                         Senior Counsel of AEPSC                2000-2001
                                         Senior Attorney of AEPSC               1994-2000
 Susanne M. Moorman............   54     Director and General Manager,
                                         Community Services                     2000-Present
                                         Manager, Customer Services Operations  1997-2000
 John R. Sampson...............   51     Director and Vice President            1999-Present
                                         Indiana State President                2000-Present
                                         Indiana & Michigan State President     1999-2000
                                         Site Vice President, Cook Nuclear Plant1998-1999
                                         Plant Manager, Cook Nuclear Plant      1996-1998
</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 2004 annual meeting of shareholders to be filed
within 120 days after December 31, 2003.

   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 2004 annual meeting of
stockholders, to be filed within 120 days after December 31, 2003.

   I&M, SWEPCo and TCC. The information required by this item is incorporated
herein by reference to the material under Executive Compensation of the
definitive information statement of APCo for the 2004 annual meeting of
stockholders, to be filed within 120 days after December 31, 2003.


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 2004 annual meeting of
shareholders to be filed within 120 days after December 31, 2003.

   APCo and OPCo. The information required by this item is incorporated herein
by reference to the material under Share Ownership of Directors and Executive
Officers in the definitive information statement of each company for the 2004
annual meeting of stockholders, to be filed within 120 days after December 31,
2003.

   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 2004 annual
meeting of stockholders, to be filed within 120 days after December 31, 2003.

   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, 2004, 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.

                                                         Stock
Name                                   Shares (a)      Units (b)    Total
----                                  ------------     ---------    ------
Karl G. Boyd......................        12,296            248      12,554
E. Linn Draper, Jr................       822,359(c)     125,233     947,592
John E. Ehler.....................            --            --           --
Henry W. Fayne....................       236,177(d)     13,143      249,320
Thomas M. Hagan...................       105,943           149      106,092
Patrick C. Hale...................         3,025            --        3,025
David L. Lahrman..................           497            --          497
Marc E. Lewis.....................         6,364            --        6,364
Susanne M. Moorman................            41            --           41
Michael G. Morris.................            --            --           --
Robert P. Powers..................       139,665         1,378      141,043
John R. Sampson...................        18,005            --       18,005
Thomas V. Shockley, III...........       345,323(d)(e)      --      345,323
Susan Tomasky.....................       231,300(d)      6,502      237,802
All Directors and Executive Officers
Officers..........................     1,920,995(d)(f)  146,653    2,067,648

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

                                       AEP Retirement Savings
               Name                  Plan (Share Equivalents)
               ----                  ------------------------
               Mr. Boyd...............................    96 
               Dr. Draper............................. 4,938 
               Mr. Ehler..............................    -- 
               Mr. Fayne.............................. 6,152 
               Mr. Hagan.............................. 3,617 
               Mr. Hale...............................    25 
               Mr. Lahrman............................   497
               Mr. Lewis.............................. 1,282
               Ms. Moorman............................    41
               Mr. Morris.............................    --
               Mr. Powers.............................   632
               Mr. Sampson............................   805
               Mr. Shockley........................... 7,530
               Ms. Tomasky............................ 1,967
               All Directors and Executive Officers...27,582

   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, 12,000; Dr. Draper,  816,666; Mr. Hagan, 91,833, Mr. Hale, 3,000; Mr.
   Lewis,  5,082;  Mr. Powers,  139,033;  Mr. Sampson,  17,200;  Mr. Shockley,
   300,000; and Mr. Fayne and Ms. Tomasky, 229,333.

(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, 2003:

<TABLE>
<CAPTION>

                                                                                                 Number of securities
                                                                      Number of                  remaining available
                                                                     securities        Weighted  for future issuance
                                                                       to be           average    under equity
                                                                     issued upon       exercise    compensation
                                                                     exercise of       price of       plans
                                                                     outstanding      outstanding   (excluding
                                                                       options,        options,     securities
                                                                       warrants        warrants     reflected in
                                                                      and rights      and rights    column (a))
Plan Category                                                            (a)             (b)           (c)
-------------                                                        -----------      ---------    -----------
 <S>                                                                  <C>            <C>            <C>
Equity  compensation  plans approved by security holders(1).........   9,094,241      $ 33.0294      4,890,143
Equity   compensation   plans  not  approved  by security holders...           0            N/A              0
  Total.............................................................   9,094,241      $ 33.0294      4,890,143
</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). 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.



Item 13. Certain Relationships and Related Transactions

   AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC: None.


Item 14.    Principal Accountants Fees and Services

   AEP. The information required by this item is incorporated herein by
reference to the material under Audit and Non-Audit Fees of the definitive proxy
statement of AEP for the 2004 annual meeting of shareholders to be filed within
120 days after December 31, 2003.

   APCo and OPCo. The information required by this item is incorporated herein
by reference to the material under Audit and Non-Audit Fees of the definitive
information statement of each company for the 2004 annual meeting of
stockholders, to be filed within 120 days after December 31, 2003.

   AEGCo, CSPCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC.

   Each of the above are wholly-owned subsidiaries of AEP and does not have a
separate audit committee. A description of the AEP Audit Committee pre-approval
policies, which apply to these companies, is contained in the definitive proxy
statement of AEP for the 2004 annual meeting of shareholders to be filed within
120 days after December 31, 2003. The following table presents fees for
professional services rendered by Deloitte & Touche LLP for the audit of these
companies' annual financial statements for the years ended December 31, 2002 and
2003, and fees billed for other services rendered by Deloitte & Touche LLP
during those periods. [These fees include an allocation of amounts billed
directly to AEPSC].

<TABLE>
<CAPTION>

                                  AEGCo             CSPCo                 I&M                KPCo
                                  -----             -----                 ---                ----
                             2003      2002     2003      2002       2003     2002       2003     2002
                             ----      ----     ----      ----       ----     ----       ----     ----
<S>                      <C>       <C>       <C>       <C>        <C>       <C>        <C>        <C>

Audit Fees                $136,100  $126,000  $385,000  $269,900   $366,900  $540,400   289,000    251,400
Audit-Related Fees......         0         0         0   155,000          0         0         0          0
Tax Fees................     1,000     1,000   349,000   119,000     26,000   231,000     8,000     34,000
All Other Fees..........         0         0         0         0          0         0         0          0
</TABLE>



<TABLE>
<CAPTION>
                                  PSO                   SWEPCo             TCC                TNC
                                  ---                  ------              ---                ---
                            2003      2002      2003      2002       2003       2002      2003      2002
                            ----      ----      ----      ----       ----       ----      ----      ----
<S>                      <C>       <C>       <C>       <C>        <C>       <C>        <C>        <C>
Audit Fees..............  $187,300  $156,200  $212,900  $178,700   $511,000   $446,770   188,900    92,800
Audit-Related Fees......         0         0         0         0          0    274,800         0   213,000
Tax Fees................    35,000   103,000    89,000   102,000     89,000   $125,000    54,000    77,000
All Other Fees..........         0         0         0         0          0          0         0         0
</TABLE>


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


PART IV


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>
AEGCo:
  Statements of Income for the years ended December 31, 2003, 2002, and 2001;
  Statements of Retained Earnings for the years ended December 31, 2003, 2002,
  and 2001; Balance Sheets as of December 31, 2003 and 2002; Statements of Cash
  Flows for the years ended December 31, 2003, 2002, and 2001; Statements of
  Capitalization as of December 31, 2003 and 2002; Combined Notes to Financial
  Statements; Independent Auditors' Report.
AEP and Subsidiary Companies:
  Consolidated Statements of Operations for the years ended December 31, 2003,
  2002, and 2001; Consolidated Balance Sheets as of December 31, 2003 and 2002;
  Consolidated Statements of Cash Flows for the years ended December 31, 2003,
  2002, and 2001; Consolidated Statements of Common Shareholders' Equity and
  Comprehensive Income for the years ended December 31, 2003, 2002, and 2001;
  Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries at
  December 31, 2003 and 2002; Schedule of Consolidated Long-term Debt of
  Subsidiaries at December 31, 2003 and 2002; 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, 2003, 2002,
  and 2001; Consolidated Statements of Comprehensive Income for the years ended
  December 31, 2003, 2002, and 2001; Consolidated Statements of Retained
  Earnings for the years ended December 31, 2003, 2002, and 2001; Consolidated
  Balance Sheets as of December 31, 2003 and 2002; Consolidated Statements of
  Cash Flows for the years ended December 31, 2003, 2002, and 2001; Consolidated
  Statements of Capitalization as of December 31, 2003 and 2002; Schedule of
  Long-term Debt as of December 31, 2003 and 2002; Combined Notes to
  Consolidated Financial Statements; Independent Auditors' Report.
KPCo, OPCo and TNC:
  Statements of Income (or Statements of Operations) for the years ended
  December 31, 2003, 2002, and 2001; Statements of Comprehensive Income for the
  years ended December 31, 2003, 2002, and 2001; Statements of Retained Earnings
  for the years ended December 31, 2003, 2002, and 2001; Balance Sheets as of
  December 31, 2003 and 2002; Statements of Cash Flows for the years ended
  December 31, 2003, 2002, and 2001; Statements of Capitalization as of December
  31, 2003 and 2002; Schedule of Long-term Debt as of December 31, 2003 and
  2002; Combined Notes to Financial Statements; Independent Auditors' Report.
   2. FINANCIAL STATEMENT SCHEDULES:
      Financial Statement Schedules are listed in the Index to Financial              S-1
  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, SWEPCo, TCC         E-1
  and TNC are listed in the Exhibit Index and are incorporated herein by 
  reference
</TABLE>


(b) Reports on Forms 8-K:

  Company Reporting  Date of Report    Item Reported
  -----------------  ----------------  -------------------
  CSPCo............  December 3, 2003  Item 5. Other Events and Regulation FD 
                                               Disclosure

                                       Item 7. Financial Statements and Exhibits
  SWEPCo...........  October 3, 2003   Item 5. Other Events and Regulation FD 
                                               Disclosure
                                       Item 7. Financial Statements and Exhibits


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




                                   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 10, 2004


   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
<S>                                     <C>                                  <C>

(i) Principal Executive Officer:

         *MICHAEL G. MORRIS              Chairman of the Board, President,    March 10, 2004
                                              Chief Executive Officer
                                                   And Director

(ii)Principal Financial Officer:

          /s/ SUSAN TOMASKY                Vice President, Secretary and      March 10, 2004
           (Susan Tomasky)                    Chief Financial Officer

(iii) Principal Accounting Officer:

       /s/ JOSEPH M. BUONAIUTO                    Controller and              March 10, 2004
        (Joseph M. Buonaiuto)                Chief Accounting Officer

(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 10, 2004

*By:      /s/ SUSAN TOMASKY
  (Susan Tomasky, Attorney-in-Fact)

</TABLE>



                                   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 10, 2004

   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
<S>                                     <C>                                  <C>


(i) Principal Executive Officer:

         *MICHAEL G. MORRIS                   Chairman of the Board,          March 10, 2004
                                       Chief Executive Officer and Director


(ii) Principal Financial Officer:

          /s/ SUSAN TOMASKY                 Vice President, Secretary,        March 10, 2004
           (Susan Tomasky)             Chief Financial Officer and Director

(iii) Principal Accounting Officer:

       /s/ JOSEPH M. BUONAIUTO                    Controller and              March 10, 2004
        (Joseph M. Buonaiuto)                Chief Accounting Officer

(iv) A Majority of the Directors:

          *JEFFREY D. CROSS
           *HENRY W. FAYNE
          *THOMAS M. HAGAN
            *A. A. PENA
          *ROBERT P. POWERS
        *THOMAS V. SHOCKLEY, III
          *STEPHEN P. SMITH                                                   March 10, 2004

*By:      /s/ SUSAN TOMASKY
  (Susan Tomasky, Attorney-in-Fact)
</TABLE>




                                   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 10, 2004

   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
<S>                                        <C>                               <C>

(i) Principal Executive Officer:

         *MICHAEL G. MORRIS                   Chief Executive Officer         March 10, 2004
                                                   and Director


(ii)Principal Financial Officer:

          /s/ SUSAN TOMASKY                 Vice President, Secretary,        March 10, 2004
           (Susan Tomasky)                    Chief Financial Officer
                                                   and Director

(iii)Principal Accounting Officer:

       /s/ JOSEPH M. BUONAIUTO                    Controller and              March 10, 2004
        (Joseph M. Buonaiuto)                Chief Accounting Officer

  (iv) A Majority of the Directors:

             *K. G. BOYD 
            *JOHN E. EHLER 
            *HENRY W. FAYNE
          *THOMAS M. HAGAN
           *PATRICK C. HALE
          *DAVID L. LAHRMAN
           *MARC E. LEWIS
         *SUSANNE M. MOORMAN
          *ROBERT P. POWERS
          *JOHN R. SAMPSON
         *THOMAS V. SHOCKLEY, III                                             March 10, 2004

*By:      /s/ SUSAN TOMASKY
  (Susan Tomasky, Attorney-in-Fact)
</TABLE>




<PAGE>

                     INDEX TO FINANCIAL STATEMENT SCHEDULES


                                                                            Page
INDEPENDENT AUDITORS' REPORT..............................................  S-2
The following  financial statement schedules are included in this report on
the pages indicated
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY  COMPANIES             S-3
     Schedule II-- Valuation and Qualifying Accounts and  Reserves........
AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
     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 CONSOLIDATED
     Schedule II-- Valuation and Qualifying Accounts and Reserves.........  S-5
PUBLIC SERVICE COMPANY OF OKLAHOMA
     Schedule II-- Valuation and Qualifying Accounts and Reserves.........  S-5
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
     Schedule II-- Valuation and Qualifying Accounts and Reserves.........  S-6



<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, 2003 and 2002, and
for each of the three years in the period ended December 31, 2003, and have
issued our reports thereon dated March 5, 2004 (which reports express
unqualified opinions and include explanatory paragraphs concerning the adoption
of new accounting pronouncements in 2002 and 2003); such financial statements
and reports are included in the 2003 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.

/s/ Deloitte & Touche LLP

Columbus, Ohio
March 5, 2004





<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, 2003     $107,578   $55,087     $ 7,234      $46,214        $123,685
                                  ========   =======     =======      =======        ========
 Year Ended December 31, 2002(c)   $68,429   $87,044     $11,767      $59,662        $107,578
                                   =======   =======     =======      =======        ========
 Year Ended December 31, 2001(c)   $31,460  $108,760     $20,763      $92,554         $68,429
                                   =======   ========    =======      =======         =======
</TABLE>

----------
(a)   Recoveries on accounts previously written off. 
(b)   Uncollectible accounts written off.
(c)   2002 and 2001 amounts have been adjusted to reflect the treatment of LIG
      and UK generation assets as discontinued operations in AEP's Consolidated
      Statements of Operations.


                   AEP TEXAS CENTRAL COMPANY 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, 2003    $     346    $1,712        $--         $ 348        $1,710
                                    ======    ======        ===         =====        ======
Year Ended  December 31, 2002    $     186     $ 162        $ 1         $   3         $ 346
                                    ======     =====        ===         =====         =====
Year Ended  December 31, 2001    $   1,675     $ 186        $--        $1,675         $ 186
                                    ======     =====        ===        ======         =====
</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, 2003      $5,041     $ 123       $--        $4,989        $ 175
                                    ======     =====       ===        ======        =====
 Year Ended  December 31, 2002        $196    $4,846       $17         $  18       $5,041
                                      ====    ======       ===         =====       ======
 Year Ended  December 31, 2001        $288     $  13       $35         $ 140        $ 196
                                      ====     =====       ===         =====        =====
</TABLE>

----------
(a)Recoveries on accounts previously written off. 
(b)Uncollectible accounts written off.


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


<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, 2003..   $13,439    $4,708    $   433       $16,495       $ 2,085
                                   =======    ======    =======       =======       =======
 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
                                    ======    ======    =======        ======       =======
</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, 2003       $  634     $  96     $   --         $ 199         $ 531
                                    ======     =====     ======         =====         =====
Year Ended  December 31, 2002       $  745     $(100)    $   --         $  11         $ 634
                                    ======     =====     ======         =====         =====
Year Ended  December 31, 2001       $  659     $ 331     $   --         $ 245         $ 745
                                    ======     =====     ======         =====         =====
</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, 2003        $  578     $  37       $ --         $  84         $ 531
                                    ======     =====       ====         =====         =====
Year Ended  December 31, 2002       $  741     $(161)      $ --         $   2         $ 578
                                    ======     =====       ====         =====         =====
Year Ended  December 31, 2001       $  759     $  65       $  3         $  86         $ 741
                                    ======     =====       ====         =====         =====
</TABLE>

----------
(a) Recoveries on accounts previously written off. 
(b) Uncollectible accounts written off.


                             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, 2003         $192     $   8       $912        $ 376          $ 736
                                      ====     =====       ====        =====          =====
Year Ended  December 31, 2002         $264     $ (68)      $ --        $   4          $ 192
                                      ====     =====       ====        =====          =====
Year Ended  December 31, 2001         $282     $  --       $(24)       $  (6)         $ 264
                                      ====     =====       ====        =====          =====
</TABLE>

-----------
(a) Recoveries on accounts previously written off. 
(b) Uncollectible accounts written off.


                         OHIO POWER COMPANY CONSOLIDATED
         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, 2003       $  909     $  42       $ 18        $ 180          $ 789
                                    ======     =====       ====        =====          =====
Year Ended  December 31, 2002       $1,379     $(457)      $ --        $  13          $ 909
                                    ======     =====       ====        =====          =====
Year Ended  December 31, 2001       $1,054     $ 554       $ --        $ 229         $1,379
                                    ======     =====       ====        =====         ======
</TABLE>

----------
(a) Recoveries on accounts previously written off. 
(b) Uncollectible accounts written off.


                       PUBLIC SERVICE COMPANY OF OKLAHOMA
         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, 2003         $ 84     $  37        $--        $  84          $  37
                                      ====     =====        ===        =====          =====
Year Ended  December 31, 2002         $ 44     $   7        $33        $  --          $  84
                                      ====     =====        ===        =====          =====
Year Ended  December 31, 2001         $467     $  44        $--        $ 467          $  44
                                      ====     =====        ===        =====          =====
</TABLE>

----------
(a) Recoveries on accounts previously written off. 
(b) Uncollectible accounts written off.


               SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
         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, 2003       $2,128     $ 103      $   --       $ 138          $2,093
                                    ======     =====      ======       =====          ======
Year Ended  December 31, 2002       $   89    $2,036      $    4       $   1          $2,128
                                    ======    ======      ======       =====          ======
Year Ended  December 31, 2001       $  911     $  89      $   --       $ 911           $  89
                                    ======     =====      ======       =====           =====
</TABLE>

----------
(a) Recoveries on accounts previously written off. 
(b) Uncollectible accounts written off.



<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.

Exhibit Number                        Description

  AEGCo
    3(a)       -- 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)       -- Capital Funds Agreement dated as of December 30, 1988
                  between AEGCo and AEP [Registration Statement No. 33-32752,
                  Exhibit 28(a)].
   10(b)(1)    -- 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)    -- 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)       -- 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 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) which are
                  incorporated by reference in this filing.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  AEP++
    3(a)       -- 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)       -- 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 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)       -- By-Laws of AEP, as amended through December 15, 2003. 
    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); Registration Statement No. 333-105532, Exhibits 4(d),
                  and 4(e) and 4(f)].
    4(b)       -- Forward Purchase Contract Agreement, dated as of June 11,
                  2002, between AEP and The Bank of New York, as Forward
                  Purchase Contract Agent [Annual Report on Form 10-K of AEP for
                  the fiscal year ended December 31, 2002, File No. 1-3525,
                  Exhibit 4(c)].
   10(a)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, OPCo and I&M and with AEPSC, 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 [Annual
                  Report on Form 10-K of AEP for the fiscal year ended December
                  31, 2002, File No. 1-3525; Exhibit 10(b)].
   10(c)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo and with AEPSC 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 [Annual Report on
                  Form 10-K of AEP for the fiscal year ended December 31, 2002,
                  File No. 1-3525; Exhibit 10(d)].
   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 AEPSC [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 December 10, 2003.
 *+10(k)(2)    -- AEP Stock Unit Accumulation Plan for Non-Employee
                  Directors, as amended December 10, 2003.
  +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 AEPSC 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 [Annual Report on Form 10-K of AEP for the
                  fiscal year ended December 31, 2002, File No. 1-3525; Exhibit
                  10(1)(1)(c)].
 *+10(l)(2)    -- AEP System Supplemental Retirement Savings Plan, Amended
                  and Restated as of January 1, 2003 (Non-Qualified)
  +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 AEP, AEPSC and Michael G.
                  Morris dated December 15, 2003.
  +10(m)(2)    -- Memorandum of agreement between Susan Tomasky and AEPSC
                  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)    -- Letter Agreement dated June 23, 2000 between AEPSC and
                  Holly K. Koeppel [Annual Report on Form 10-K of AEP for the
                  Fiscal year ended December 31, 2002, File No. 1-3525; Exhibit
                  10(m)(3)(A)].
  +10(m)(4)    -- Employment Agreement dated July 29, 1998 between AEPSC and
                  Robert P. Powers [Annual Report on Form 10-K of AEP for the
                  Fiscal year ended December 31, 2002, File No. 1-3525; Exhibit
                  10(m)(4)].
  +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 [Annual Report
                  on Form 10-K of AEP for the fiscal year ended December 31,
                  2002, File No. 1-3525; Exhibit 10(o)(2)].
  +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 Amended and
                  Restated as of January 1, 2003.
  +10(r)       -- AEP System Nuclear Performance Long Term Incentive
                  Compensation Plan dated August 1, 1998 [Annual Report on Form
                  10-K of AEP for the fiscal year ended December 31, 2002, file
                  No. 1-3525; Exhibit 10(r)].
  +10(s)       -- Nuclear Key Contributor Retention Plan dated May 1, 2000
                  [Annual Report on Form 10-K of AEP for the Fiscal year ended
                  December 31, 2002, File No. 1-3525; Exhibit 10(s)].
  +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, as amended
                  December 10, 2003.
  +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)    -- Certified AEP Utilities, Inc. (formerly CSW) Board
                  Resolutions of July 16, 1996.
  +10(v)(4)    -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                  March 13, 1992].
  +10(v)(5)    -- 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 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) which are
                  incorporated by reference in this filing.
  *21          -- List of subsidiaries of AEP.
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  APCo++
    3(a)       -- 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)       -- 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)       -- 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 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)       -- 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)       -- 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)].
    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); and
                  Annual Report on Form 10-K of APCo for fiscal year ended
                  December 31, 2002, File 1-3457, Exhibit 4(c)].
   *4(c)       -- Company Order and Officer's Certificate, dated May 5, 2003,
                  establishing terms of 3.60% Senior Notes, Series G, due 2008
                  and 5.95% Senior Notes, Series H, due 2033.
   10(a)(1)    -- 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)    -- 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)    -- 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)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, OPCo and I&M and with AEPSC, 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)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo and with AEPSC 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)       -- Modification No. 1 to the AEP System Interim Allowance
                  Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo,
                  OPCo and AEPSC [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)].
  +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 [Annual Report on Form 10-K of APCo for the
                  fiscal year ended December 31, 2002, File No. 1-3457; Exhibit
                  10(h)(1)(B)].
 *+10(h)(2)    -- AEP System Supplemental Retirement Savings Plan, Amended
                  and Restated as of January 1, 2003 (Non-Qualified).
  +10(h)(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(i)(1)    -- Employment Agreement between AEP, AEPSC and Michael G.
                  Morris dated December 15, 2003.
  +10(i)(2)    -- Memorandum of agreement between Susan Tomasky and AEPSC
                  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 [Annual Report on Form 10-K of APCo for the
                  fiscal year ended December 31, 2002, File No. 1-3457; Exhibit
                  10(i)(3)].
  +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 [Annual Report
                  on Form 10-K of APCo for the fiscal year ended December 31,
                  2002, File No. 1-3457; Exhibit 10(j)(2)].
  +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, as amended
                  December 10, 2003.
  +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)    -- Certified AEP Utilities, Inc. (formerly CSW) Board
                  Resolutions of July 16, 1996.
  +10(n)(4)    -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                  March 13, 1992].
 *+10(o)(1)    -- AEP System Incentive Compensation Deferral Plan Amended and
                  Restated as of January 1, 2003.
  +10(p)       -- AEP System Nuclear Performance Long Term Incentive
                  Compensation Plan dated August 1, 1998 [Annual Report on Form
                  10-K of APCo for the fiscal year ended December 31, 2002, file
                  No. 1-3457; Exhibit 10(p)].
  +10(q)       -- Nuclear Key Contributor Retention Plan dated May 1, 2000
                  [Annual Report on Form 10-K of APCo for the fiscal year ended
                  December 31, 2002, File No. 1-3457; Exhibit 10(q)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the APCo 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21].
  *23          -- Consent of Deloitte & Touche LLP
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  CSPCo++
    3(a)       -- Amended Articles of Incorporation of CSPCo, as amended to
                  March 6, 1992 [Registration Statement No. 33-53377, Exhibit
                  4(a)].
    3(b)       -- 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 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)       -- 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)       -- 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)       -- 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)].
   *4(c)       -- First Supplemental Indenture between CSPCo and Deutsche
                  Bank Trust Company Americas, as Trustee, dated November 25,
                  2003, establishing terms of 4.40% Senior Notes, Series E, due
                  2010.
   *4(d)       -- Indenture (for unsecured debt securities), dated as of
                  February 1, 2003, between CSPCo and Bank One, N.A., as Trustee
   *4(e)       -- First Supplemental Indenture, dated as of February 1, 2003,
                  between CSPCo and Bank One, N.A., as trustee, establishing the
                  terms of 5.50% Senior Notes, Series A, due 2013 and 5.50%
                  Senior Notes, Series C, due 2013.
   *4(f)       -- Second Supplemental Indenture, dated as of February 1,
                  2003, between CSPCo and Bank One, N.A. establishing the terms 
                  of 6.60% Senior Notes, Series B, due 2033 and 6.60% Senior 
                  Notes, Series D, due 2033.
   10(a)(1)    -- 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)    -- 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)    -- 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)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, OPCo and I&M and AEPSC, 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)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo, and with AEPSC 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)       -- Modification No. 1 to the AEP System Interim Allowance
                  Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo,
                  OPCo and AEPSC [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 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21]
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(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)       -- 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)       -- 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 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)       -- 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)].
    4(a)       -- 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)       -- 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); Registration Statement No. 333-108975, Exhibits
                  4(b), 4(c) and 4(d)].
   10(a)(1)    -- 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)    -- 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)    -- 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)    -- 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)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, I&M, and OPCo and with AEPSC, 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)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo and with AEPSC 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)       -- Modification No. 1 to the AEP System Interim Allowance
                  Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo,
                  OPCo and AEPSC [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)       -- 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(f)(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(f)(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 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21].
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  KPCo++
    3(a)       -- 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)       -- 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)       -- 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 4(e) and 4(f); Annual Report on Form 10-K of KPCo for
                  the fiscal year ended December 31, 2002, File No. 1-6858,
                  Exhibits 4(c), 4(d) and 4(e)].
   *4(b)       -- Company Order and Officer's Certificate, dated June 13,
                  2003 establishing certain terms of the 5.625% Senior Notes,
                  Series D, due 2032.
   10(a)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, I&M and OPCo and with AEPSC, 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)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo and with AEPSC 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)       -- Modification No. 1 to the AEP System Interim Allowance
                  Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo,
                  OPCo and AEPSC [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 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) which are
                  incorporated by reference in this filing.
  *23          -- Consent of Deloitte & Touche LLP
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  OPCo++
    3(a)       -- 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)       -- 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)       -- 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)       -- 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 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)].
    3(f)       -- 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)       -- 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)       -- 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); Registration Statement No. 333-106242, Exhibit 4(b),
                  4(c) and 4(d); Registration Statement No. 333-75783, Exhibits
                  4(b) and 4(c)].
   *4(c)       -- First Supplemental Indenture between OPCo and Deutsche Bank
                  Trust Company Americas, as Trustee, dated July 11, 2003,
                  establishing terms of 4.85% Senior Notes, Series H, due 2014.
   *4(d)       -- Second Supplemental Indenture between OPCo and Deutsche
                  Bank Trust Company Americas, as Trustee, dated July 11, 2003,
                  establishing terms of 6.375% Senior Notes, Series I, due 2033.
   *4(e)       -- Indenture (for unsecured debt securities), dated as of
                  February 1, 2003, between OPCo and Bank One, N.A., as Trustee
   *4(f)       -- First Supplemental Indenture, dated as of February 1, 2003,
                  between OPCo and Bank One, N.A., as Trustee, establishing the
                  terms of 5.50% Senior Notes, Series D, due 2013 and 5.50%
                  Senior Notes, Series F, due 2013.
   *4(g)       -- Second Supplemental Indenture, dated as of February 1,
                  2003, between OPCo and Bank One, N.A., as Trustee,
                  establishing the terms of 6.60% Senior Notes, Series E, due
                  2033 and 6.60% Senior Notes, Series G, due 2033.
   10(a)(1)    -- 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)    -- 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)    -- 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)       -- Interconnection Agreement, dated July 6, 1951, among APCo,
                  CSPCo, KPCo, I&M and OPCo and with AEPSC, 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)       -- Transmission Agreement, dated April 1, 1984, among APCo,
                  CSPCo, I&M, KPCo, OPCo and with AEPSC 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)       -- Modification No. 1 to the AEP System Interim Allowance
                  Agreement, dated July 28, 1994, among APCo, CSPCo, I&M, KPCo,
                  OPCo and AEPSC [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)       -- 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 [Annual Report on Form 10-K of OPCo for the
                  fiscal year ended December 31, 2002, File No. 1-6543; Exhibit
                  10(i)(1)(B)].
 *+10(i)(2)    -- AEP System Supplemental Retirement Savings Plan, Amended
                  and Restated as of January 1, 2003 (Non-Qualified).
  +10(i)(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(j)(1)    -- Employment Agreement between AEP, AEPSC and Michael G.
                  Morris dated December 15, 2003.
  +10(j)(2)    -- Memorandum of agreement between Susan Tomasky and AEPSC
                  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 [Annual Report on Form 10-K of OPCo for the
                  fiscal year ended December 31, 2002, File No. 1-6543; Exhibit
                  10(j)(3)].
  +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 [Annual Report
                  on Form 10-K of OPCo for the fiscal year ended December 31,
                  2002, File No. 1-6543; Exhibit 10(k)(2)].
  +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, as amended December
                  10, 2003.
  +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)    -- Certified AEP Utilities, Inc. (formerly CSW) Board
                  Resolutions of July 16, 1996.
  +10(o)(4)    -- CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW,
                  March 13, 1992].
 *+10(p)(1)    -- AEP System Incentive Compensation Deferral Plan Amended and
                  Restated as of January 1, 2003.
  +10(q)       -- AEP System Nuclear Performance Long Term Incentive
                  Compensation Plan dated August 1, 1998 [Annual Report on Form
                  10-K of OPCo for the fiscal year ended December 31, 2002, File
                  No. 1-6543; Exhibit 10(q)].
  +10(r)       -- Nuclear Key Contributor Retention Plan dated May 1, 2000
                  [Annual Report on Form 10-K of OPCo for the fiscal year ended
                  December 31, 2002, File No. 1-6543; Exhibit 10(r)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the OPCo 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21].
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(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].
                  (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); [Annual Report on Form 10-K of PSO for the fiscal
                  year ended December 31, 2002, File No. 0-343; Exhibit 4(c)].
   *4(d)       -- Third Supplemental Indenture, dated as of September 15,
                  2003, between PSO and The Bank of New York, as Trustee,
                  establishing terms of the 4.85% Senior Notes, Series C, due
                  2010.
   10(a)       -- Restated and Amended Operating Agreement, dated as of
                  January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual
                  Report on Form 10-K of PSO for the fiscal year ended December
                  31, 2002, File No. 0-343; Exhibit 10(a)].
   10(b)       -- Transmission Coordination Agreement, dated October 29,
                  1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on
                  Form 10-K of PSO for the fiscal year ended December 31, 2002,
                  File No. 0-343; Exhibit 10(b)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the PSO 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) which are
                  incorporated by reference in this filing.
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(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) Subordinated Indenture, dated as of September 1, 2003,
                       between SWEPCo and The Bank of New York, as Trustee.
                  (2)  Amended and Restated Trust Agreement of SWEPCo Capital
                       Trust I, dated as of September 1, 2003, among SWEPCo, as
                       Depositor, The Bank of New York, as Property Trustee, The
                       Bank of New York (Delaware), as Delaware Trustee, and the
                       Administrative Trustees.
                  (3)  Guarantee Agreement, dated as of September 1, 2003,
                       delivered by SWEPCo for the benefit of the holders of
                       SWEPCo Capital Trust I's Preferred Securities.
                  (4)  First Supplemental Indenture dated as of October 1, 2003,
                       providing for the issuance of Series B Junior
                       Subordinated Debentures between SWEPCo, as Issuer and The
                       Bank of New York, as Trustee
                  (5)  Agreement as to Expenses and Liabilities, dated as of
                       October 1, 2003 between SWEPCo and SWEPCo Capital Trust I
                       (included in Item (4) above as exhibit 4(f)(i)(A).
    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); Registration Statement No. 333-100632, Exhibit 4(b);
                  Registration Statement No. 333-108045 Exhibit 4(b)].
   *4(d)       -- Third Supplemental Indenture, between SWEPCo and The Bank
                  of New York, as Trustee, dated April 11, 2003, establishing
                  terms of 5.375% Senior Notes, Series C, due 2015.
   10(a)       -- Restated and Amended Operating Agreement, dated as of
                  January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual
                  Report on Form 10-K of SWEPCo for the fiscal year ended
                  December 31, 2002, File No. 1-3146; Exhibit 10(a)].
   10(b)       -- Transmission Coordination Agreement, dated October 29,
                  1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on
                  Form 10-K of SWEPCo for the fiscal year ended December 31,
                  2002, File No. 1-3146; Exhibit 10(b)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the SWEPCo 2003 Annual Report
                  (for the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21]
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(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 [Annual Report on Form 10-K of
                  TCC for the fiscal year ended December 31, 2002, File No.
                  0-346; Exhibit 3(b)].
    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].
                  (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)].
   *4(d)       -- Indenture (for unsecured debt securities), dated as of
                  February 1, 2003, between TCC and Bank One, N.A., as Trustee
   *4(e)       -- First Supplemental Indenture, dated as of February 1, 2003,
                  between TCC and Bank One, N.A., as Trustee, establishing the
                  terms of 5.50% Senior Notes, Series A, due 2013 and 5.50%
                  Senior Notes, Series D, due 2013.
   *4(f)       -- Second Supplemental Indenture, dated as of February 1,
                  2003, between TCC and Bank One, N.A., as Trustee, establishing
                  the terms of 6.65% Senior Notes, Series B, due 2033 and 6.65%
                  Senior Notes, Series E, due 2033.
   *4(g)       -- Third Supplemental Indenture, dated as of February 1, 2003,
                  between TCC and Bank One, N.A., as Trustee, establishing the
                  terms of 3.00% Senior Notes, Series C, due 2005 and 3.00%
                  Senior Notes, Series F, due 2005.
   *4(h)       -- Fourth Supplemental Indenture, dated as of February 1,
                  2003, between TCC and Bank One, N.A., as Trustee, establishing
                  the terms of Floating Rate Notes, Series A, due 2005 and
                  Floating Rate Notes, Series B, due 2005.
   10(a)       -- Restated and Amended Operating Agreement, dated as of
                  January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual
                  Report on Form 10-K of TCC for the fiscal year ended December
                  31, 2002, File No. 0-346; Exhibit 10(a)].
   10(b)       -- Transmission Coordination Agreement, dated October 29,
                  1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on
                  Form 10-K of TCC for the fiscal year ended December 31, 2002,
                  File No. 0-346; Exhibit 10(b)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the TCC 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) 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, 2003, File No.
                  1-3525, Exhibit 21]
  *23          -- Consent of Deloitte & Touche LLP.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(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 [Annual Report on Form 10-K of
                  TNC for the fiscal year ended December 31, 2002, File No.
                  0-340; Exhibit 3(b)].
    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)].
   *4(b)       -- Indenture (for unsecured debt securities), dated as of
                  February 1, 2003, between TNC and Bank One, N.A., as Trustee
   *4(c)          -- First Supplemental Indenture, dated as of February 1, 2003,
                  between TNC and Bank One, N.A., as Trustee, establishing the
                  terms of 5.50% Senior Notes, Series A, due 2013 and 5.50%
                  Senior Notes, Series D, due 2013.
   10(a)       -- Restated and Amended Operating Agreement, dated as of
                  January 1, 1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual
                  Report on Form 10-K of TNC for the fiscal year ended December
                  31, 2002, File No. 0-340; Exhibit 10(a)].
   10(b)       -- Transmission Coordination Agreement, dated October 29,
                  1998, among PSO, TCC, TNC, SWEPCo and AEPSC [Annual Report on
                  Form 10-K of TNC for the fiscal year ended December 31, 2002,
                  File No. 0-340; Exhibit 10(b)].
  *12          -- Statement re: Computation of Ratios.
  *13          -- Copy of those portions of the TNC 2003 Annual Report (for
                  the fiscal year ended December 31, 2003) which are
                  incorporated by reference in this filing.
  *24          -- Power of Attorney.
  *31(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *31(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 302 of the Sarbanes-Oxley Act of 2002.
  *32(a)       -- Certification of Chief Executive Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.
  *32(b)       -- Certification of Chief Financial Officer Pursuant to
                  Section 1350 of Chapter 63 of Title 18 of the United States
                  Code.

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

   ++ 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.





                                                                    EXHIBIT 4(b)

June 13, 2003


                     Company Order and Officers' Certificate
                     5.625% Senior Notes, Series D, due 2032

Deutsche Bank Trust Company Americas, as Trustee
Corporate Trust & Agency Services
280 Park Avenue,  MS-NYC03-0914
New York, NY  10017

Ladies and Gentlemen:

Pursuant to Article Two of the Indenture, dated as of September 1, 1997 (as it
may be amended or supplemented, the "Indenture"), from Kentucky Power Company
(the "Company") to Bankers Trust Company, now Deutsche Bank Trust Company
Americas, as trustee (the "Trustee"), and the Board Resolutions dated April 22,
2002, a copy of which certified by the Secretary or an Assistant Secretary of
the Company is being delivered herewith under Section 2.01 of the Indenture, and
unless otherwise provided in a subsequent Company Order pursuant to Section 2.04
of the Indenture,

                  1. the Company's 5.625% Senior Notes, Series D, due 2032 (the
                  "Notes") are hereby established. The Notes shall be in
                  substantially the form attached hereto as Exhibit 1.

                  2. the terms and characteristics of the Notes shall be as
                  follows (the numbered clauses set forth below corresponding to
                  the numbered subsections of Section 2.01 of the Indenture,
                  with terms used and not defined herein having the meanings
                  specified in the
 Indenture):

                  (i) the aggregate principal amount of Notes which shall
                  initially be authenticated and delivered under the Indenture
                  is $75,000,000, except as contemplated in Section 2.01(i) of
                  the Indenture;

                  (ii) the date on which the principal of the Notes shall be
                  payable shall be December 1, 2032;

                  (iii) interest shall accrue from the date of authentication of
                  the Notes; the Interest Payment Dates on which such interest
                  will be payable shall be June 1 and December 1, and the
                  Regular Record Date for the determination of holders to whom
                  interest is payable on any such Interest Payment Date shall be
                  the May 15 or November 15 preceding the relevant Interest
                  Payment Date; provided that the first Interest Payment Date
                  shall be December 1, 2003 and interest payable on the Stated
                  Maturity Date or any Redemption Date shall be paid to the
                  Person to whom principal shall be paid;

                  (iv) the interest rate at which the Notes shall bear interest
                  shall be 5.625% per annum;

                  (v) the Notes shall be redeemable at the option of the
                  Company, in whole at any time or in part from time to time,
                  upon not less than thirty but not more than sixty days'
                  previous notice given by mail to the registered owners of the
                  Notes at a redemption price equal to the greater of (i) 100%
                  of the principal amount of the Notes being redeemed and (ii)
                  the sum of the present values of the remaining scheduled
                  payments of principal and interest on the Notes being redeemed
                  (excluding the portion of any such interest accrued to the
                  date of redemption) discounted (for purposes of determining
                  present value) to the redemption date on a semi-annual basis
                  (assuming a 360-day year consisting of twelve 30-day months)
                  at the Treasury Rate (as defined below) plus 30 basis points,
                  plus, in each case, accrued interest thereon to the date of
                  redemption.

                  "Treasury Rate" means, with respect to any redemption date,
                  the rate per annum equal to the semi-annual equivalent yield
                  to maturity of the Comparable Treasury Issue, assuming a price
                  for the Comparable Treasury Issue (expressed as a percentage
                  of its principal amount) equal to the Comparable Treasury
                  Price for such redemption date.

                  "Comparable Treasury Issue" means the United States Treasury
                  security selected by an Independent Investment Banker as
                  having a maturity comparable to the remaining term of the
                  Notes that would be utilized, at the time of selection and in
                  accordance with customary financial practice, in pricing new
                  issues of corporate debt securities of comparable maturity to
                  the remaining term of the Notes.

                  "Comparable Treasury Price" means, with respect to any
                  redemption date, (i) the average of the bid and asked prices
                  for the Comparable Treasury Issue (expressed in each case a
                  percentage of its principal amount) on the third Business Day
                  preceding such redemption date, as set forth in the daily
                  statistical release (or any successor release) published by
                  the Federal Reserve Bank of New York and designated "Composite
                  3:30 p.m. Quotations for U. S. Government Securities" or (ii)
                  if such release (or any successor release) is not published or
                  does not contain such prices on such third Business Day, the
                  Reference Treasury Dealer Quotation for such redemption date.
                  "Independent Investment Banker" means one of the Reference
                  Treasury Dealers appointed by the Company and reasonably
                  acceptable to the Trustee.

                  "Reference Treasury Dealer" means a primary U.S. government
                  securities dealer in New York City selected by the Company and
                  reasonably acceptable to the Trustee.

                  "Reference Treasury Dealer Quotation" means, with respect to
                  the Reference Treasury Dealer and any redemption date, the
                  average, as determined by the Trustee, of the bid and asked
                  prices for the Comparable Treasury Issue (expressed in each
                  case as a percentage of its principal amount) quoted in
                  writing to the Trustee by such Reference Treasury Dealer at or
                  before 5:00 p.m., New York City time, on the third Business
                  Day preceding such redemption date.

                  (vi) (a) the Notes shall be issued in the form of a Global
                  Note; (b) the Depositary for such Global Note shall be The
                  Depository Trust Company; and (c) the procedures with respect
                  to transfer and exchange of Global Notes shall be as set forth
                  in the form of Note attached hereto;

                  (vii) the title of the Notes shall be "5.625% Senior Notes,
                  Series D, due 2032";

                  (viii) the form of the Notes shall be as set forth in
                  Paragraph 1, above;

                  (ix) not applicable;

                  (x) the Notes may be subject to a Periodic Offering;

                  (xi) not applicable;

                  (xii) not applicable;

                  (xiii) the Company will pay the principal of the Notes and any
                  premium and interest payable at redemption, if any, or at
                  maturity in immediately available funds at the office of
                  Deutsche Bank Trust Company Americas, Corporate Trust and
                  Agency Services, 60 Wall Street, MSNYC 602515, New York, New
                  York 10005;

                  (xiv) the Notes shall be issuable in denominations of $1,000
                  and any integral multiple thereof;

                  (xv) not applicable;

                  (xvi) the Notes shall not be issued as Discount Securities;

                  (xvii) not applicable;

                  (xviii) not applicable; and

                  (xix) So long as any of the Notes are outstanding, the Company
                  will not create or suffer to be created or to exist any
                  additional mortgage, pledge, security interest, or other lien
                  (collectively "Liens") on any of its utility properties or
                  tangible assets now owned or hereafter acquired to secure any
                  indebtedness for borrowed money ("Secured Debt"), without
                  providing that the Notes will be similarly secured. This
                  restriction does not apply to the Company's subsidiaries, nor
                  will it prevent any of them from creating or permitting to
                  exist Liens on their property or assets to secure any Secured
                  Debt. Further, this restriction on Secured Debt does not apply
                  to the Company's existing first mortgage bonds that have
                  previously been issued under its Mortgage and Deed of Trust,
                  dated as of May 1, 1949, between the Company and Deutsche Bank
                  Trust Company Americas (formerly Bankers Trust Company), as
                  Trustee or any indenture supplemental thereto; provided that
                  this restriction will apply to future issuances thereunder
                  (other than issuances of refunding first mortgage bonds). In
                  addition, this restriction does not prevent the creation or
                  existence of:

                           (a) Liens on property existing at the time of
                  acquisition or construction of such property (or created
                  within one year after completion of such acquisition or
                  construction), whether by purchase, merger, construction or
                  otherwise, or to secure the payment of all or any part of the
                  purchase price or construction cost thereof, including the
                  extension of any Liens to repairs, renewals, replacements,
                  substitutions, betterments, additions, extensions and
                  improvements then or thereafter made on the property subject
                  thereto;

                           (b) Financing of the Company's accounts receivable
                  for electric service;

                           (c) Any extensions, renewals or replacements (or
                  successive extensions, renewals or replacements), in whole or
                  in part, of liens permitted by the foregoing clauses; and

                           (d) The pledge of any bonds or other securities at
                  any time issued under any of the Secured Debt permitted by the
                  above clauses.

                  In addition to the permitted issuances above, Secured Debt not
                  otherwise so permitted may be issued in an amount that does
                  not exceed 15% of Net Tangible Assets as defined below.

                  "Net Tangible Assets" means the total of all assets (including
                  revaluations thereof as a result of commercial appraisals,
                  price level restatement or otherwise) appearing on the
                  Company's balance sheet, net of applicable reserves and
                  deductions, but excluding goodwill, trade names, trademarks,
                  patents, unamortized debt discount and all other like
                  intangible assets (which term shall not be construed to
                  include such revaluations), less the aggregate of the
                  Company's current liabilities appearing on such balance sheet.
                  For purposes of this definition, the Company's balance sheet
                  does not include assets and liabilities of its subsidiaries.

                  This restriction also does not apply to or prevent the
                  creation or existence of leases made, or existing on property
                  acquired, in the ordinary course of business.

                  3. You are hereby requested to authenticate $75,000,000
                  aggregate principal amount of 5.625% Senior Notes, Series D,
                  due 2032, executed by the Company and delivered to you
                  concurrently with this Company Order and Officers'
                  Certificate, in the manner provided by the Indenture.

                  4. You are hereby requested to hold the Notes as custodian for
                  DTC in accordance with the Blanket Letter of Representations
                  dated June 11, 2003, from the Company to DTC.

                  5. Concurrently with this Company Order and Officers'
                  Certificate, an Opinion of Counsel under Sections 2.04 and
                  13.06 of the Indenture is being delivered to you.

                  6. The undersigned Henry W. Fayne and Thomas G. Berkemeyer,
                  the President and Assistant Secretary, respectively, of the
                  Company do hereby certify that:

                  (i) we have read the relevant portions of the Indenture,
                  including without limitation the conditions precedent provided
                  for therein relating to the action proposed to be taken by the
                  Trustee as requested in this Company Order and Officers'
                  Certificate, and the definitions in the Indenture relating
                  thereto;

                  (ii) we have read the Board Resolutions of the Company and the
                  Opinion of Counsel referred to above;

                  (iii) we have conferred with other officers of the Company,
                  have examined such records of the Company and have made such
                  other investigation as we deemed relevant for purposes of this
                  certificate;

                  (iv) in our opinion, we have made such examination or
                  investigation as is necessary to enable us to express an
                  informed opinion as to whether or not such conditions have
                  been complied with; and

                  (v) on the basis of the foregoing, we are of the opinion that
                  all conditions precedent provided for in the Indenture
                  relating to the action proposed to be taken by the Trustee as
                  requested herein have been complied with.


Kindly acknowledge receipt of this Company Order and Officers' Certificate,
including the documents listed herein, and confirm the arrangements set forth
herein by signing and returning the copy of this document attached hereto.

Very truly yours,

KENTUCKY POWER COMPANY


By: /s/ Henry W. Fayne
          President


And: /s/ Thomas G. Berkemeyer
           Assistant Secretary


Acknowledged by Trustee:


By: /s/ Susan Johnson
          Authorized Signatory




EXHIBIT 12

KENTUCKY POWER COMPANY
Computation of Ratios of Earnings to Fixed Charges
(in thousands except ratio data)

Year Ended December 31,
1999
2000
2001
2002
2003
Fixed Charges:            
  Interest on First Mortgage Bonds   $12,712   $9,503   $6,178   $2,206   $-  
  Interest on Other Long-term Debt   13,525   16,367   18,300   23,429   26,467  
  Interest on Short-term Debt   2,552   3,295   2,329   1,751   1,104  
  Miscellaneous Interest Charges   869   2,523   1,059   1,084   1,772  
  Estimated Interest Element in Lease Rentals   1,200   1,700   1,200   1,000   600  





     Total Fixed Charges   $30,858   $33,388   $29,066   $29,470   $29,943  





Earnings:  
  Net Income Before Cumulative Effect  
   of Accounting Change   $25,430   $20,763   $21,565   $20,567   $33,464  
  Plus Federal Income Taxes   12,993   17,884   9,553   9,235   9,764  
  Plus State Income Taxes (Credits)   2,784   2,457   489   1,627   (89 )
  Plus Fixed Charges (as above)   30,858   33,388   29,066   29,470   29,943  





     Total Earnings   $72,065   $74,492   $60,673   $60,899   $73,082  





Ratio of Earnings to Fixed Charges   2.33   2.23   2.08   2.06   2.44  










2003 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>






                                  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                   INDEX TO ANNUAL REPORTS

                                                                                                                Page
                                                                                                                ----
   <C>                                                                                                          <C> 
   Glossary of Terms                                                                                            

   Forward-Looking Information                                                                                  

   AEP Common Stock and Dividend Information                                                                    

                         American Electric Power Company, Inc. and Subsidiary Companies:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries              
                              Schedule of Consolidated Long-term Debt                                           
                              Index to Notes to Consolidated Financial Statements                               
                              Independent Auditors' Report                                                      
                              Management's Responsibility                                                       

                         AEP Generating Company:
                              Selected Financial Data                                                           
                              Management's Narrative Financial Discussion and Analysis                          
                              Financial Statements                                                              
                              Statements of Capitalization
                                                      
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         AEP Texas Central Company and Subsidiary:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         AEP Texas North Company:
                              Selected Financial Data                                                           
                              Management's Narrative Financial Discussion and Analysis                          
                              Financial Statements                                                              
                              Statements of Capitalization                                                      
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Appalachian Power Company and Subsidiaries:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Columbus Southern Power Company and Subsidiaries:
                              Selected Consolidated Financial Data                                              
                              Management's Narrative Financial Discussion and Analysis                          
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Indiana Michigan Power Company and Subsidiaries:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Kentucky Power Company:
                              Selected Financial Data                                                           
                              Management's Narrative Financial Discussion and Analysis                          
                              Financial Statements                                                              
                              Statements of Capitalization                                                      
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Ohio Power Company Consolidated:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Public Service Company of Oklahoma:
                              Selected Financial Data                                                           
                              Management's Narrative Financial Discussion and Analysis                          
                              Financial Statements                                                              
                              Statements of Capitalization                                                      
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      

                         Southwestern Electric Power Company Consolidated:
                              Selected Consolidated Financial Data                                              
                              Management's Financial Discussion and Analysis                                    
                              Consolidated Financial Statements                                                 
                              Consolidated Statements of Capitalization                                         
                              Schedule of Long-term Debt                                                        
                              Index to Notes to Respective Financial Statements                                 
                              Independent Auditors' Report                                                      



                         Notes to Respective Financial Statements                                               




                         Registrants' Combined Management's Discussion and Analysis       
</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
               ----                                -------
<C>                                <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 other true-up items and the recovery of such amounts.
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 and consolidated affiliates.
AEP Credit                         AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated domestic electric utility companies.
AEP East companies                 APCo, CSPCo, I&M, KPCo and OPCo.
AEPES                              AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR                               AEP Resources, Inc.
AEP System or the System           The American Electric Power System, an integrated electric utility system, owned and operated by
                                            AEP's electric utility subsidiaries.
AEPSC                              American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP System Power Pool or           Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of Pool 
AEP Power Pool                              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.
ALJ                                Administrative Law Judge.
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.
APB 18                             Accounting   Principles  Board  Opinion  Number  18:  The  Equity  Method  of  Accounting  for
                                            Investments in Common Stock.
APCo                               Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission                Arkansas Public Service Commission.
Buckeye                            Buckeye Power, 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.
CSPCo                              Columbus Southern Power Company, an AEP electric utility subsidiary.  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. 
DETM                               Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE                                United States Department of Energy.
ECOM                               Excess Cost Over Market.
EITF                               The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3                          Emerging  Issues Task Force Issue No.  02-3:  Issues  Involved in  Accounting  for  Derivative
                                            Contracts  Held For Trading  Purposes and  Contracts  Involved in Energy  Trading and
                                            Risk Management Activities.
ERCOT                              The Electric Reliability Council of Texas.
EWGs                               Exempt Wholesale Generators.
FASB                               Financial Accounting Standards Board.
Federal EPA                        United States Environmental Protection Agency.
FERC                               Federal Energy Regulatory Commission.
FIN 45                             FASB  Interpretation  No.  45,  "Guarantor's   Accounting  and  Disclosure   Requirements  for
                                            Guarantees, Including Indirect Guarantees of Indebtedness of Others."
FIN 46                             FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."
FUCOs                              Foreign Utility Companies.
GAAP                               Generally Accepted Accounting Principles.
I&M                                Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR                                Interchange Cost Reconstruction.
IRS                                Internal Revenue Service.
IURC                               Indiana Utility Regulatory Commission.
ISO                                Independent System Operator.
JMG                                JMG Funding LP.
KPCo                               Kentucky Power Company, an AEP electric utility subsidiary.
KPSC                               Kentucky Public Service Commission.
KV                                 Kilovolt.
KWH                                Kilowatthour.
LIG                                Louisiana Intrastate Gas, an AEP subsidiary.
LPSC                               Louisiana Public Service Commission.
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.
MW                                 Megawatt.
MWH                                Megawatthour.
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.
NRC                                Nuclear Regulatory Commission.
OCC                                The Corporation Commission of the State of Oklahoma.
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.
PTB                                Price-to-Beat.
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.
Risk Management Contracts          Trading and non-trading derivatives, including those derivatives designated as cash flow and 
                                            fair value hedges, and non-derivative contracts held for trading purposes that were 
                                            subject to mark-to-market accounting prior to January 1, 2003.
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.
                                            -------------------------------------------------------------
SFAS 143                           Statement  of  Financial  Accounting  Standards  No.  143,  
                                            Accounting  for Asset  Retirement Obligations.
                                            ---------------------------------------------
SFAS 149                           Statement of Financial Accounting Standards No. 149, 
                                            Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
                                            ---------------------------------------------------------------------------
SFAS 150                           Statement  of  Financial  Accounting  Standards  No. 150,  
                                            Accounting  for Certain  Financial Instruments with Characteristics of both Liabilities
                                            ---------------------------------------------------------------------------------------
                                            and Equity.
                                            ----------
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.
Tenor                              Maturity of a contract.
Texas Legislation                  Legislation enacted in 1999 to restructure the electric utility industry in Texas. TNC AEP 
                                            Texas North Company, an AEP electric utility subsidiary.
TVA                                Tennessee Valley Authority.
U.K.                               The United Kingdom.
VaR                                Value at Risk, a method to quantify risk exposure.
Virginia SCC                       Virginia State Corporation Commission.
WVPSC                              Public Service Commission of West Virginia.
WPCo                               Wheeling Power Company, an AEP electric distribution subsidiary.
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

     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 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     Weather conditions.
  o     Available sources and costs of fuels.
  o     Availability of generating capacity and the performance of AEP's 
        generating plants. 
  o     The ability to recover regulatory assets and stranded costs in
        connection with deregulation. 
  o     New legislation and government regulation including requirements for 
        reduced emissions of sulfur, nitrogen, mercury, carbon and other 
        substances. 
  o     Resolution of pending and future rate cases, negotiations and other 
        regulatory decisions (including rate or other recovery for 
        environmental compliance).
  o     Oversight and/or investigation of the energy sector or its 
        participants.
  o     Resolution of litigation (including pending Clean Air Act enforcement
        actions and disputes arising from the bankruptcy of Enron Corp.). 
  o     AEP's ability to reduce its operation and maintenance costs. 
  o     The success of disposing of investments that no longer match AEP's 
        corporate profile.
  o     AEP's ability to sell assets at attractive prices and on other 
        attractive terms.
  o     International and country-specific developments affecting foreign 
        investments including the disposition of any current 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     AEP's ability to develop and execute on a point of view regarding 
        prices of electricity, natural gas, and other energy-related 
        commodities. 
  o     Changes in the creditworthiness and number of participants in the 
        energy trading market.
  o     Changes in the financial markets, particularly those affecting the 
        availability of capital and AEP's ability to refinance existing debt 
        at attractive rates.
  o     Actions of rating agencies, including changes in the ratings of debt 
        and preferred stock. 
  o     Volatility and changes in markets for electricity, natural gas, and 
        other energy-related commodities. 
  o     Changes in utility regulation, including the establishment of a 
        regional transmission structure. 
  o     Accounting pronouncements periodically issued by accounting 
        standard-setting bodies. 
  o     The performance of AEP's pension plan.
  o     Prices for power that we generate and sell at wholesale.
  o     Changes in technology and other risks and unforeseen events, 
        including wars, the effects of terrorism (including increased
        security costs), embargoes and other catastrophic events.



<PAGE>

<TABLE>
<CAPTION>


                                            AEP COMMON STOCK AND DIVIDEND INFORMATION
                                            -----------------------------------------

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


                                                                                                            Quarter-end
     Quarter Ended                        High                  Low                 Closing Price            Dividend
     -------------                        ----                  ---                 -------------           -----------

     <C>                                 <C>                  <C>                      <C>                    <C>         
     December 2003                       $30.59               $26.69                   $30.51                 $0.35 
     September 2003                       30.00                26.58                    30.00                  0.35 
     June 2003                            31.51                22.56                    29.83                  0.35 
     March 2003                           30.63                19.01                    22.85                  0.60 

     December 2002                       $30.55               $15.10                   $27.33                 $0.60 
     September 2002                       40.37                22.74                    28.51                  0.60 
     June 2002                            48.80                39.00                    40.02                  0.60 
     March 2002                           47.08                39.70                    46.09                  0.60 

</TABLE>


     AEP common stock is traded principally on the New York Stock Exchange. At
     December 31, 2003, AEP had approximately 150,000 registered shareholders.




<PAGE>

<TABLE>
<CAPTION>




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




                                                            2003           2002             2001            2000           1999
                                                            ----           ----             ----            ----           ----
             OPERATIONS STATEMENTS DATA                                                 (in millions)
------------------------------------------------------                                                                    
<C>                                                       <C>             <C>             <C>             <C>             <C>    
Total Revenues                                            $14,545         $13,308         $12,753         $10,743         $9,695 
Operating Income                                            1,632           1,804           2,223           1,758          2,053 
Income Before Discontinued Operations, Extraordinary
 Items and Cumulative Effect                                  522             485             960             177            865 
Discontinued Operations Income (Loss)                        (605)           (654)             41             134            116 
Extraordinary Losses                                            -               -             (48)            (44)            (9)
Cumulative Effect of Accounting Changes Gain (Loss)           193            (350)             18               -              -    
Net Income (Loss)                                             110            (519)            971             267            972 


                 BALANCE SHEET DATA                                                  
------------------------------------------------------                                                                    
Property, Plant and Equipment                             $36,033         $34,127         $32,993         $31,472        $30,476   
Accumulated Depreciation and Amortization                  14,004          13,539          12,655          12,398         11,895   
                                                          --------        --------        --------        --------       --------
Net Property, Plant and Equipment                         $22,029         $20,588         $20,338         $19,074        $18,581   
                                                          ========        ========        ========        ========       ========

Total Assets                                              $36,744         $35,890         $40,432         $47,703        $36,297   

Common Shareholders' Equity                                 7,874           7,064           8,229           8,054          8,673   

Cumulative Preferred Stocks
  of Subsidiaries (a) (d)                                     137             145             156             161            182   

Trust Preferred Securities (b)                                  -             321             321             334            335   

Long-term Debt (a) (b)                                     14,101          10,190           9,409           8,980          9,471   

Obligations Under Capital Leases (a)                          182             228             451             614            610   


                  COMMON STOCK DATA
------------------------------------------------------                                                                    
Earnings (Loss) per Common Share:
Before Discontinued Operations, Extraordinary Items
  and Cumulative Effect                                     $1.35           $1.46           $2.98           $0.55          $2.69   
Discontinued Operations                                     (1.57)          (1.97)           0.13            0.42           0.36   
Extraordinary Losses                                            -               -           (0.16)          (0.14)         (0.02)  
Cumulative Effect of Accounting Changes                      0.51           (1.06)           0.06               -              -   
                                                          --------        --------        --------        --------       --------

Earnings (Loss) Per Share                                   $0.29          $(1.57)          $3.01           $0.83          $3.03   
                                                          ========        ========        ========        ========       ========

Average Number of Shares Outstanding (in millions)            385             332             322             322            321   
Market Price Range: 
    High                                                   $31.51          $48.80          $51.20          $48.94         $48.19   
    Low                                                     19.01           15.10           39.25           25.94          30.56   

Year-end Market Price                                       30.51           27.33           43.53           46.50          32.13   

Cash Dividends on Common (c)                                $1.65           $2.40           $2.40           $2.40          $2.40   
Dividend Payout Ratio(c)                                   569.0%         (152.9)%          79.7%          289.2%          79.2%  
Book Value per Share                                       $19.93          $20.85          $25.54          $25.01         $26.96   

</TABLE>


(a) Including portion due within one year.
(b) See Note 17 of the Notes to Consolidated Financial Statements. 
(c) Based on AEP historical dividend rate.
(d) Includes Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory
    Redemption which are classified in 2003 as Non-Current Liabilities.



<PAGE>


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

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

We have 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 many of our market areas. Utility generating capacity of
        4,500 megawatts located in Texas and approximately 280 megawatts of
        independent power generation located in Colorado and Florida are
        expected to be sold during 2004
  o     39,000 miles of transmission lines, the backbone of the electric 
        interconnection grid in the Eastern U.S.
  o     210,000 miles of distribution lines that deliver electricity to 
        customers
  o     Substantial coal  transportation  assets (7,000  railcars,  
        1,800 barges,  37 towboats and two coal handling  terminals with 20 
        million tons of annual capacity)
  o     6,400 miles of gas pipelines in Louisiana and Texas with 127 Bcf of 
        gas storage facilities. We have entered into an agreement to sell 
        2,000 miles of pipeline and plan to sell 9 Bcf of storage located in
        Louisiana related to our disposal of LIG
  o     4,000 megawatts of generating capacity in the U.K., a market which 
        we plan to exit by the end of 2004

BUSINESS STRATEGY
-----------------

We will continue to concentrate our efforts on our domestic utilities. Our
objectives are to be an economical, reliable and safe provider of energy to the
markets that we serve. We will achieve economic advantage by designing,
building, improving and operating low cost efficient sources of power and
maximizing the volumes of power delivered from these facilities. We will
maintain and enhance our position as a safe and reliable provider of energy by
making significant investments into environmental and reliability upgrades. We
will seek to recover the cost of our new utility investments in a manner that
results in reasonable rates for our customers and that provides a fair return
for our shareholders through a stable stream of cash flows enabling us to pay
competitive dividends.

We are addressing many challenges in our unregulated business. We have
substantially reduced our trading activities that are not related to the sale of
power from our owned-generation. We have written down the value of several
investments to reflect deterioration in market conditions and sold or plan to
sell assets that no longer fit our core business strategy. We have identified
certain assets as "held-for-sale" and will move others to "held-for-sale" as we
formalize and approve our plans for disposition. We will continue to operate HPL
as we evaluate our future plans for this investment.

In summary our business strategy calls for us to:

     Operations
     ----------
  o     Invest in technology that improves the environment of the communities 
        in which we operate 
  o     Maximize the value of our transmission assets and protect our revenue 
        stream through membership in PJM 
  o     Continue maintaining and improving distribution service quality 
  o     Optimize generation assets by increasing availability and consequently 
        increasing sales 
  o     Complete the sales of our non-core assets

     Regulation
     ----------
  o     Focus on the regulatory process to maximize our earnings while providing
        fair and reasonable rates to our customers 
  o     Complete the sale of our generation assets in Texas and recognize and 
        recover the associated stranded costs in compliance with the law
  o     Complete the integration of the operation of our transmission system
        into PJM consistent with applicable regulatory requirements

     Financial
     ---------
  o     Operate only those unregulated investments that are consistent with our
        energy expertise and risk tolerance and that provide reasonable
        prospects for a fair return and moderate growth
  o     Continue to improve credit quality and maintain acceptable levels of 
        liquidity
  o     Achieve moderate but steady earnings growth

2003 OVERVIEW
-------------

2003 was a year of transition for AEP. We repositioned ourselves to take
advantage of, and maximize, the value of our utility assets. At the same time we
took significant strides to exit non-core investments.

Our utility operations had a year of continued improvement resulting from strong
wholesale results and our efforts to control and reduce operating costs. We
reduced our losses from unregulated investments by reducing transitional trading
losses and cutting related administrative expenses.

During 2003 we further stabilized our financial strength by:
  o     Issuing approximately $1.1 billion in common stock
  o     Completing a cost reduction initiative which led to a $392 million
        decline in operations and maintenance expenses during 2003 as compared
        to 2002. Savings of approximately $139 million are attributable to our
        utility operations
  o     Minimizing future capital requirements associated with non-core assets
  o     Reducing our cash flow risk by limiting our trading activities to a 
        level consistent with the scope of our generation fleet 
  o     Stabilizing our credit ratings

We have redirected our business strategy by:
  o     Continuing to streamline our trading activities principally to support
        the sale of power from our core assets
  o     Actively pursuing the sale of all of our U.K. generation and our gas 
        pipeline operations located in Louisiana; we expect each of these 
        dispositions to be completed during 2004

OUTLOOK FOR 2004
----------------

We remain focused on the fundamental earning power of our utilities, and we are
committed to strengthening our balance sheet. Our strategy for achieving these
goals is well planned. We will: 
  o      Continue to identify opportunities to further reduce both our 
         operations and maintenance expenses and to efficiently manage our 
         capital expenditures
  o      Seek rate changes that are fair and reasonable and that allow us to 
         make the necessary operational and environmental improvements to our 
         system 
  o      Dispose of various unregulated assets to eliminate the negative 
         earnings and cash consequences of these operations 
  o      Use the proceeds from our dispositions to reduce debt and strengthen 
         our capital structure 
  o      Successfully operate certain unregulated investments such as our wind 
         farms and our barge and river transport groups, which compliment
         our core capabilities
  o      Evaluate opportunities to hold and operate HPL under a revised 
         business model that reduces commodity risk and earns reasonable 
         returns for shareholders


Our objective is excellence in operations and results. There are, nevertheless,
certain risks and challenges. We discuss these matters in detail in the Notes to
Financial Statements and later in Management's Discussion and Analysis under the
heading of Significant Factors. We will diligently resolve these matters by
finding workable solutions that balance the interests of our customers, our
employees and our investors.

RESULTS OF OPERATIONS
---------------------

In 2003, AEP's principal operating business segments and their major activities
were: 
  o     Utility Operations: 
           o Domestic generation of electricity for sale to retail and 
             wholesale customers 
           o Domestic electricity transmission and distribution 
  o     Investments-Gas Operations:* 
           o Gas pipeline and storage services
  o     Investments-UK Operations:** 
           o International generation of electricity for sale to wholesale 
             customers 
           o Coal procurement and transportation to AEP plants and third 
             parties 
  o     Investments-Other:
           o Coal mining, bulk commodity barging operations and other energy 
             supply related businesses

     *  Operations of Louisiana Intrastate Gas were classified as discontinued
        during 2003. 
     ** UK Operations were classified as discontinued during 2003.

American Electric Power Company's consolidated Net Income (Loss) for the years
ended December 31, 2003, 2002 and 2001 were as follows (Earnings and Average
Shares Outstanding in millions):


<TABLE>
<CAPTION>

                                                    2003                          2002                            2001
                                           ---------------------         ----------------------         ----------------------
                                           Earnings        EPS           Earnings         EPS           Earnings        EPS
                                           --------        ---           --------         ---           --------        ---

<C>                                         <C>           <C>             <C>           <C>               <C>          <C>   
Utility Operations                          $1,218        $3.17           $1,154         $3.47            $941         $2.92 
Investments - Gas Operations                  (290)        (.76)             (99)         (.29)             91           .28 
Investments - UK Operations                     -            -                 -             -               -             - 
Investments - Other                           (277)        (.72)            (522)        (1.58)              -             - 
All Other*                                    (129)        (.34)             (48)         (.14)            (72)         (.22)
                                            -------       ------          -------       -------           -----        ------
Income Before Discontinued
 Operations, Extraordinary  Items
 and Cumulative Effect                         522         1.35              485          1.46             960          2.98 

Investments - Gas Operations                   (91)        (.24)               8           .02              (4)         (.01)
Investments - UK Operations                   (507)       (1.32)            (472)        (1.42)            (41)         (.13)
Investments - Other                             (7)        (.01)            (190)         (.57)             86           .27
                                            -------       ------          -------       -------           -----        ------
Discontinued Operations                       (605)       (1.57)            (654)        (1.97)             41           .13 

Extraordinary Loss                              -            -                -             -              (48)         (.16)

Cumulative Effect of
 Accounting Changes                            193          .51            (350)        (1.06)             18           .06
                                            -------       ------          -------       -------           -----        ------

Total Net Income (Loss)                       $110         $.29            $(519)       $(1.57)           $971         $3.01
                                            =======       ======          =======       =======           =====        ======
Average Shares Outstanding                                  385                            332                           322
                                                          ======                        =======                        ======
</TABLE>


* All Other includes the parent company interest income and expense, as well as
  other non-allocated costs.   

2003 Compared to 2002
---------------------

Income Before Discontinued Operations, Extraordinary Items and Cumulative Effect
in 2003 increased compared to 2002 due to increased wholesale earnings, lower
impairment and other charges, and reduced operations and maintenance expenses.
This increase was offset, in part, by milder weather and continuing weakness in
the economy. Our Net Income for 2003 of $110 million or $.29 per share includes
a loss, net of taxes, on discontinued operations of $605 million and $193
million of income, net of taxes, from the cumulative effect of changing our
accounting for asset retirement obligations and for certain trading activities.
Our Net Loss for 2002 of $519 million or ($1.57) per share includes a loss, net
of taxes, on discontinued operations of $654 million and a $350 million, net of
tax, charge for implementing a newly issued accounting pronouncement related to
the impairment of goodwill. During the fourth quarter of 2003 we concluded that
the U.K. operations and LIG were not part of our core business and we began
actively marketing each of these investments. The U.K. operations consist of our
generation and trading operations that sell to wholesale customers. LIG's
operations include 2,000 miles of intrastate gas pipelines and 9 Bcf of natural
gas storage capacity. In addition, we recognized that poor market conditions
also affected our merchant generation, other gas pipeline and storage assets,
goodwill associated with these investments and various other assets. Based on
market factors, as measured by a combination of indicative bids from unrelated
interested buyers, independent appraisals, and estimates of cash flows, we
recognized impairment losses of $960 million, net of taxes.

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


2002 Compared to 2001
---------------------

Our Net Loss was $519 million or a loss of $1.57 per share in 2002 which was a
$1.5 billion decline from 2001. Income Before Discontinued Operations,
Extraordinary Items and Cumulative Effect was negatively affected by plant
availability, lower wholesale prices, reduced trading activity and write-offs to
reduce the valuation of the under-performing assets. In the fourth quarter 2002,
we recognized impairments on under-performing assets and recorded losses, net of
taxes, of $854 million. The losses in the fourth quarter 2002 were caused by the
extended decline in domestic and international energy markets. In addition to
the fourth quarter impairment losses, we had losses on discontinued operations
of $654 million including U.K. operations, SEEBOARD, Citipower and other
investments and a loss for transitional goodwill impairment of $350 million
related to SEEBOARD and Citipower that resulted from the adoption of a newly
issued accounting standard related to the impairment of goodwill.

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

Utility Operations
------------------

                         Summary of Selected Sales Data
                             For Utility Operations
               For the Years Ended December 31, 2003, 2002 and 2001

                                  2003              2002             2001
                                  ----              ----             ----
Energy Summary                              (in millions of KWH)        
Retail
  Residential                     45,479           46,805           43,498  
  Commercial                      37,104           36,487           35,589  
  Industrial                      51,856           53,686           52,443  
  Miscellaneous                    3,035            3,216            2,208
                                 --------         --------         --------
       Total                     137,474          140,194          133,738
                                 --------         --------         --------
Wholesale                         72,977           70,661           79,288
                                 --------         --------         --------



                                  2003              2002             2001
                                  ----              ----             ----
Weather Summary                               (in degree days)            
Eastern Region
--------------
Actual - Heating                   5,314            4,963            4,679  
Normal - Heating*                  5,182            5,177            5,232  

Actual - Cooling                     757            1,252            1,021  
Normal - Cooling*                    975            1,013              997  

Western Region
--------------
Actual - Heating                   1,020            1,044            1,134  
Normal - Heating*                  1,062            1,034            1,060  

Actual - Cooling                   2,220            2,369            2,377  
Normal - Cooling*                  2,217            2,224            2,233  

*Normal Heating/Cooling represents the 30-year average of degree days.

2003 Compared to 2002
---------------------

Earnings from Utility Operations increased $64 million to $1,218 million in
2003. Decreased operating expenses were partially offset by decreases in
revenues net of related fuel and purchased power.

Utility revenues net of related fuel and purchased power decreased as follows:

  o     Residential demand decreased principally as a consequence of milder
        weather, and industrial demand was down due to the continued slow
        economic recovery. The combination of these factors reduced revenues
        net of related fuel and purchased power by approximately $65 million.
  o     Reserves for final fuel factor decisions in Texas as well as other
        disallowances and associated rate reserves of $102 million and lower
        regulatory deferrals for ECOM-based stranded costs of $44 million
        reduced earnings. The provisions for stranded cost recovery in Texas
        recognize a regulatory asset or liability for the difference between
        the actual price received from the state-mandated auction of 15% of
        generation capacity and the earlier estimate of market price derived by
        a PUCT model.
  o     Fuel and purchased power costs increased by approximately $40 million 
        due in part to nuclear plant outages.
  o     During the fourth quarter of 2002, we exited trading activities that
        were not related to the sale of power from our owned-generation. The
        loss of these contributions from exiting the related trading positions
        reduced utility earnings by approximately $70 million.

The decreases in utility revenues net of related fuel and purchased power were
partially offset as follows:

  o     Off-system  sales,  including  optimization  activities,  increased  
        by  approximately  $160  million  primarily  due to  increased  prices
        and plant availability.
  o     Transmission revenues increased by approximately $45 million, due 
        principally to increased wholesale power sales volumes.

Utility operating expenses decreased as follows:

  o     Maintenance and Other Operation expense decreased $139 million due to 
        continuing efforts to reduce costs, primarily labor and insurance, 
        despite severe storm damage in the Midwest.
  o     Taxes Other Than Income Taxes decreased $17 million primarily due to 
        reduced gross receipts tax as a result of the sale of the Texas REPs. 
  o     Depreciation and Amortization expense decreased $18 million due to the
        change in our accounting for asset retirement obligations. The 
        accounting change caused similar offseting increases in Maintenance and 
        Other Operation expenses.

2002 Compared to 2001
---------------------

Earnings from Utility Operations increased $213 million to $1,154 million in
2002 due to an $84 million gain on the sale of the Texas REPs and capital cost
reductions of $104 million, partially offset by a reduction in operating income.

Capital costs decreased due to reductions in short-term interest rates, lower
outstanding balances of short-term debt and the refinancing of long-term debt at
favorable interest rates. These reductions were partially offset by an increase
in the amount of long-term debt outstanding.

Increased operating expenses were partially offset by increases in revenues net
of related fuel and purchased power.

Utility revenues net of related fuel and purchased power increased as follows:

  o     ECOM-based Texas stranded cost deferrals increased $262 million.
  o     Retail demand increased  approximately  $180 million due to increased 
        usage by residential customers. Eastern region cooling degree days 
        were up 23% over 2001.

The increases in utility revenues net of related fuel and purchased power were
partially offset as follows:

  o     Off-system sales net of related fuel and purchased power decreased 
        $126 million primarily due to lower plant availability, lower 
        wholesale prices, the loss of certain municipal and co-op customers, 
        and customers switching from FERC tariff-based to market-based rates.
  o     Trading operations, which decreased $214 million as a result of our
        previously announced plan to exit trading activities that are not
        related to the sale of power from our owned-generation.

Utility operating expenses increased as follows:

  o     Maintenance and Other Operation expense increased $102 million due to 
        increased  benefit costs of $48 million, increased post September 11 
        insurance cost of $35 million and increased nuclear maintenance and 
        other expenses of $19 million.
  o     Depreciation and Amortization expense increased $46 million as a 
        result of additional generation, transmission and distribution assets.
  o     Taxes Other Than Income Taxes increased $70 million due to increased 
        property and payroll taxes.

Investments - Gas Operations
----------------------------     

2003 Compared to 2002
---------------------

The loss from our Gas Operations of $290 million increased $191 million from
2002. This increase is primarily due to impairments recorded to reflect the
reduction in the value of our gas assets. In the fourth quarter 2003, we
recognized impairments and other related charges of $228 million, net of tax,
associated with HPL assets and goodwill based on market indicators supported by
indicative bids received for LIG. These bids led us to conclude that purchasers
were no longer willing to pay higher multiples for historic cash flows which
included trading activities. Our previous operating strategy included higher
risk tolerances associated with trading activities in order to achieve such
operating results.

Partially offsetting the 2003 impairments, gas operations earnings have improved
approximately $68 million from 2002 due to a $40 million decrease in losses
associated with the options trading portfolio that we are no longer actively
trading and exiting through a transition plan (our transition gas trading
portfolio) and a $28 million reduction in operating expenses. These earnings
improvements were partially offset by $15 million of losses due to unexpected
late February 2003 sales to Entex, at fixed prices, when the Houston Ship 
Channel prices were at historic highs, a decrease in March deliveries due to 
unseasonably mild weather, and a decline in trading optimization of $28 million
due to lower risk tolerances and limits compared to the previous year.

2002 Compared to 2001
---------------------

The loss from our Gas Operations of $99 million increased $190 million from
2001. The increase is due to significant trading losses in 2002 compared with
strong trading results in 2001.

Investments - UK Operations
---------------------------

2003 Compared to 2002
---------------------

The loss from our UK Operations of $507 million for 2003 increased by $35
million from 2002 and was due primarily to $375 million, net of tax, of
impairment and other related charges recorded during the fourth quarter. During
2003, we concluded that the UK Operations were not part of our core business and
we began actively marketing our investment. As a result, we devalued our UK
investment based on bids received from interested unrelated buyers. The loss
includes $157 million of pre-tax losses associated with commitments for below
market forward sales of power, which are beyond the date of the anticipated sale
of these plants. We also experienced operating losses as a result of the
deterioration of pretax trading margins of $83 million associated with U.K.
power and $29 million associated with coal and freight.

2002 Compared to 2001
---------------------

Our loss in 2002 from UK Operations of $472 million increased by $431 million
from 2001. Our operations in the U.K. were dramatically expanded in December
2001 with the acquisition of two 2,000 MW generation stations. Goodwill and
asset impairment charges of $414 million, net of tax, contributed to our 2002
losses. The oversupply conditions throughout 2002 worsened in the fourth quarter
after the British government's decision to subsidize British Energy, a
financially troubled, dominant generator of power in the U.K. This intervention
in the competitive market kept inefficient generation in the marketplace. The
write-down of our two U.K. power plants was the result of our analyses that
indicated U.K. power prices would not recover to levels that would permit us to
carry the plants at their original purchase prices. In addition to unfavorable
U.K. power and coal markets, higher than anticipated operating costs contributed
to the loss in 2002.

Investments - Other
-------------------

2003 Compared to 2002
---------------------

The loss from our Other investments decreased by $245 million to $277 million in
2003. The decrease was primarily due to asset impairment charges of $257
million, net of tax, compared to impairments of $392 million, net of tax,
recorded in 2002. 2003 impairments included losses of $45 million, net of tax,
for two of our independent generation facilities due to market conditions; $168
million, net of tax, for the Dow facility due to the current market conditions
and litigation; and coal mining asset impairments of $44 million, net of tax,
based on bids from unrelated parties. Additionally we incurred lower
international development costs and reduced interest expenses during 2003.

2002 Compared to 2001
---------------------

The loss from our Other investment operations of $522 million resulted from $392
million of asset impairment charges, net of tax. These write-downs in the fourth
quarter of 2002 recognized the lower valuation in our investments in a utility
in Brazil, AEP Communications and other under-performing assets. There were no
such write-downs in 2001.

All Other
---------

Our parent company's 2003 expenses increased $81 million over 2002 primarily
from higher interest costs due to increased debt at the parent level and reduced
reliance on short-term borrowings as well as the recognition of estimated losses
from certain litigation contingencies. Expenses in 2002 declined $24 million
from 2001 due to lower interest costs.

FINANCIAL CONDITION
-------------------

We measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows. During 2003 we improved our financial
condition as a consequence of the following actions and events:

  o     We issued approximately $1.1 billion of new common equity
  o     We reduced our quarterly dividend in June 2003 to $.35 per share 
        which reduced our annualized cash outflows by approximately $395 
        million 
  o     We reduced short-term debt by $2.8 billion, restructured our lines of 
        credit into two $750 million facilities, completed approximately 
        $1.3 billion of optional long-term debt redemptions, paid-off $225 
        million of our Steelhead financing, and funded $1.4 billion of debt 
        maturities 
  o     We limited our energy trading activity to levels necessary to optimize
        earnings from sales of our owned-generation 
  o     Despite downgrades of certain debt ratings during the first quarter 
        and continued uncertainty in the industry, we have maintained stable 
        credit ratings across the AEP System


<TABLE>
<CAPTION>

Capitalization
--------------
                                                                  2003                    2002                    2001
                                                                  ----                    ----                    ----
<C>                                                               <C>                     <C>                     <C>
Common Equity                                                      35%                     32%                     36%
Preferred Stock                                                     1                       1                       1   
Long-term Debt, including amounts due within one year              63                      50                      43   
Short-term Debt                                                     1                      14                      17   
Minority Interest in Finance Subsidiary                             -                       3                       3   
                                                                  ----                    ----                    ----
Total Capitalization                                              100%                    100%                    100%
                                                                  ====                    ====                    ====
</TABLE>


Our capital was affected by the following, during 2003:

  o     We recognized $960 million of impairment losses related to our 
        unregulated investments while reducing our ratio of debt to total 
        capital 
  o     We substantially reduced our short-term debt commitments, thereby 
        reducing refinancing and cash flow risks 
  o     We improved our percentage of common equity outstanding to total
        capitalization, in part through the issuance of approximately $1.1 
        billion of new equity.

Liquidity 
---------

Liquidity, or access to cash, is an important factor in determining our
financial stability due to volatility in wholesale power prices and the effects
of credit rating downgrades. We are committed to preserving an adequate
liquidity position.

Credit Facilities
-----------------

We manage our liquidity by maintaining adequate external financing commitments.
We had an available liquidity position of approximately $3.5 billion as
illustrated in the table below:
                                              Amount             Maturity
                                              ------             --------
                                           (in millions)
      Commercial Paper Backup:
        Lines of Credit                        $ 750           May 2004
        Lines of Credit                        1,000           May 2005
        Lines of Credit                          750           May 2006
      Euro Revolving Credit
        Facility                                 189           October 2004
      Letter of Credit Facility                  200           September 2006
                                              ------
      Total                                    2,889
      Available Cash and Temporary 
       Investments                               920*
                                              ------
      Total Liquidity Sources                  3,809
      Less: AEP Commercial Paper
                 Outstanding                     282**
               Letters of Credit
                 Outstanding                      35
                                              ------
            
      Net Available Liquidity                 $3,492
                                              ======

     *  Available Cash and Temporary Investments of $920 million and $262 
        million in unavailable cash on hand make up the $1.2 billion Cash and 
        Cash Equivalents balance on our Consolidated Balance Sheet at December 
        31, 2003.
     ** Amount does not include JMG Funding LP (JMG) commercial paper
        outstanding in the amount of $26 million. This commercial paper is
        specifically associated with the Gavin scrubber lease.  This commercial
        paper does not reduce available liquidity to AEP.

Debt Covenants
--------------

Our revolving credit agreements require us to maintain our percentage of debt
to total capitalization at a level that does not exceed 67.5%.  The method for
calculating our outstanding debt and other capital is contractually defined.
At December 31, 2003, this percentage was 58.8%.  Non-performance of these 
covenants may result in an event of default under these credit agreements. 
At December 31, 2003, we complied with the covenants contained in these credit 
agreements. In addition, the acceleration of the payment obligations of us, or 
certain of our subsidiaries, prior to maturity under any other agreement or 
instrument relating to debt outstanding in excess of $50 million would cause 
an event of default under these credit agreements and permit the lenders to 
declare the amounts outstanding thereunder payable.

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

Under an SEC order, AEP and its utility subsidiaries cannot incur additional
indebtedness if the issuer's common equity would constitute less than 30% (25%
for TCC due to its securitization bonds) of its capital. In addition, this order
restricts AEP and the utility subsidiaries from issuing long-term debt unless
that debt will be rated investment grade by at least one nationally recognized
statistical rating organization.

Dividend Restrictions
---------------------

Provisions within the Articles of Incorporation relating to the preferred stock
of certain of our subsidiaries restrict the payment of cash dividends or other
distributions on their common and preferred stock. PUHCA prohibits our
subsidiaries from making loans or advances to the parent company, AEP. In
addition, under PUHCA, AEP and its public utility subsidiaries can only pay
dividends out of retained or current earnings.

Credit Ratings
--------------

We also manage our liquidity by continuing to maintain investment grade credit
ratings and a stable credit outlook and are taking steps to improve our credit
quality, including plans during 2004 to further reduce our outstanding debt
through the use of proceeds from the planned dispositions. If we receive a 
downgrade in our credit ratings by these agencies, our borrowing costs could
increase. The rating agencies currently have AEP and our rated subsidiaries on 
stable outlook. Current ratings for AEP are as follows:

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


Cash Flow
---------

Our cash flows are a major factor in managing and maintaining our liquidity
strength.


<TABLE>
<CAPTION>

                                                                              2003               2002              2001
                                                                              ----               ----              ----
                                                                                            (in millions)
    <C>                                                                      <C>               <C>                <C>    
    Cash and Cash Equivalents at Beginning of Period                         $1,199              $194               $232   
                                                                             -------           -------            -------
    Net Cash Flows From Operating Activities                                  2,308             2,067              2,818   
    Net Cash Flows Used For Investing Activities                             (1,888)             (378)            (3,292)  
    Net Cash Flows (Used For) From Financing Activities                        (437)             (681)               437   
    Effect of Exchange Rate Changes on Cash                                       -                (3)                (1)  
                                                                             -------           -------            -------
    Net Increase (Decrease) in Cash and Cash Equivalents                        (17)            1,005                (38)  
                                                                             -------           -------            -------
    Cash and Cash Equivalents at End of Period                               $1,182            $1,199               $194   
                                                                             =======           =======            =======
</TABLE>


Cash from operations, combined with a bank-sponsored receivables purchase
agreement and short-term borrowings provide working capital and meet other
short-term cash needs. We use our corporate borrowing program to meet the
short-term borrowing needs of our subsidiaries. The corporate borrowing program
includes a utility money pool which funds the utility subsidiaries and a
non-utility money pool which funds the majority of the non-utility subsidiaries.
In addition, we also fund, as direct borrowers, the short-term debt requirements
of other subsidiaries that are not participants in the non-utility money pool
for regulatory or operational reasons. As of December 31, 2003, we had credit
facilities totaling $2.9 billion to support our commercial paper program. We
generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding mechanisms are arranged.
Sources of long-term funding include issuance of common stock, preferred stock
or long-term debt and sale-leaseback or leasing agreements. Money pool and
external borrowings may not exceed SEC authorized limits.

Operating Activities
--------------------


<TABLE>
<CAPTION>

                                                                       
                                                                                2003               2002               2001
                                                                                ----               ----               ----   
                                                                                              (in millions)
    <C>                                                                       <C>                <C>                <C>  
    Net Income (Loss)                                                           $110              $(519)              $971 
    Plus:  Discontinued Operations                                               605                654                (41)
                                                                              -------            -------            -------
    Income from Continuing Operations                                            715                135                930 
    Noncash Items Included in Earnings                                         1,798              2,734                976 
    Changes in Assets and Liabilities                                           (205)              (802)               912
                                                                              -------            -------            -------
    Net Cash Flows From Operating Activities                                  $2,308             $2,067             $2,818
                                                                              =======            =======            =======
</TABLE>


2003 Operating Cash Flow
------------------------

Our cash flows from operating activities were $2.3 billion for 2003. We produced
income from continuing operations of $715 million during the period. Income from
continuing operations for 2003 included noncash items of $1.5 billion for
depreciation, amortization, and deferred taxes, $193 million for the cumulative
effects of accounting changes, and $720 million for impairment losses and other
related charges. In addition, there is a current period impact for a net $122
million balance sheet change for risk management contracts that are
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. Changes in Assets and Liabilities represent those items that had a
current period cash flow impact, such as changes in working capital, as well as
items that represent future rights or obligations to receive or pay cash, such
as regulatory assets and liabilities. The current period activity in these asset
and liability accounts relates to a number of items; the most significant are
presented below:

  o     The wholesale capacity auction true-up (ECOM) resulted in stranded cost
        deferrals of $218 million, which are not recoverable in cash until the
        conclusion of our Texas true-up proceeding. These proceedings are not
        expected to be finalized earlier than April 2005.
  o     Net changes in accounts receivable and accounts payable of $269 million
        related, in large part, to the settlement of risk management positions
        during 2002 and payments related to those settlements during 2003.
        These payments include $90 million in settlement of power and gas
        transactions to the Williams Companies. The earnings effects of
        substantially all payments were reflected in earlier periods.
  o     Increases in inventory levels of $71 million resulting primarily from 
        higher procurement prices.
  o     Reserves for disallowed fuel costs, principally related to Texas, 
        which will be a component of our 2004 final Texas true-up order of 
        the PUCT.


2002 Operating Cash Flow
------------------------

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

2001 Operating Cash Flow
------------------------
Our cash flows from operating activities were $2.8 billion for 2001. Income from
continuing operations was $930 million during the period. Income from continuing
operations for 2001 included noncash items of $1.5 billion for depreciation,
amortization, and deferred taxes, and $18 million related to the cumulative
effect of an accounting change. There was a current period impact for a net $294
million balance sheet change for risk management contracts that were
marked-to-market. These contracts have an unrealized earnings impact as market
prices move, and a cash impact upon settlement or upon disbursement or receipt
of premiums. The activity in the asset and liability accounts was primarily
attributable to increased levels of trading activities as compared to 2002 and
2003. During the fourth quarter of 2002 we exited trading that was not related
to the sale of power from our owned-generation.

Investing Activities
--------------------


<TABLE>
<CAPTION>

                                                                        
                                                                              2003                2002                2001
                                                                              ----                ----                ----   
                                                                                              (in millions)
    <C>                                                                      <C>                 <C>               <C>     
    Construction Expenditures                                                $(1,358)            $(1,685)          $(1,646)
    Business Acquisitions/Sales Proceeds, net                                     82               1,263              (621)
    Other                                                                       (612)                 44            (1,025)
                                                                             --------            --------          --------
    Net Cash Flows Used for Investing Activities                             $(1,888)              $(378)          $(3,292)
                                                                             ========            ========          ========
</TABLE>



Our cash flows used for investing activities increased $1.5 billion in 2003 from
$378 million during the prior year. This increase was due to additional sales
proceeds in 2002 related to SEEBOARD, CitiPower, and the Texas REPs as well as
increased investments in our U.K. operations during 2003. These increases were
partially offset by a reduction of our capital expenditures in 2003 as compared
to 2002.

In 2002, our cash flows used for investing activities decreased $2.9 billion
from 2001. This decrease resulted from the HPL and UK acquisitions during 2001
as well as the net increase in proceeds received from asset sales during 2002.

We forecast $5.8 billion of construction expenditures for 2004-2006.

Financing Activities
--------------------


<TABLE>
<CAPTION>

                                                                              2003                2002                2001
                                                                              ----                ----                ----   
                                                                                              (in millions)
    <C>                                                                       <C>                 <C>                 <C> 
    Issuances of Equity Securities (common stock/equity units)                $1,142               $990                $11 
    Issuances/Retirements of Debt, net                                          (727)              (868)               460 
    Retirement of Preferred Stock                                                 (9)               (10)                (5)
    Issuance/Retirement of Minority Interest                                    (225)                -                 744 
    Dividends                                                                   (618)              (793)              (773)
                                                                              -------             ------              -----
    Net Cash Flows (Used for) From Financing Activities                        $(437)             $(681)              $437
                                                                              =======             ======              =====
</TABLE>



Our cash flows used for financing activities decreased $244 million in 2003 from
$681 million during the prior year. This decrease was due to additional proceeds
from the issuance of common stock and the reduction of our common stock dividend
in 2003.

In 2002 we used $681 million for financing activities compared to $437 million
provided by the same activities in 2001. The increase in cash used pertained
primarily to the debt retirements that occurred in 2002.

The following financing activities occurred during 2003 and 2002:

     Common Stock and Equity Units:
     -----------------------------

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

  o     In June 2002, we issued 16 million shares of common stock at $40.90 per
        share and 6.9 million equity units at $50 per unit and received
        combined net proceeds of $979 million. We used the proceeds to pay down
        short-term debt and establish a cash liquidity reserve fund.

     Debt:
     ----
  o     We use our corporate borrowing program to meet the short-term borrowing
        needs of our subsidiaries. The corporate borrowing program includes a
        utility money pool which funds the utility subsidiaries and a
        non-utility money pool which funds the majority of the non-utility
        subsidiaries. In addition, we also fund, as direct borrowers, the
        short-term debt requirements of other subsidiaries that are not
        participants in the non-utility money pool for regulatory or
        operational reasons. As of December 31, 2003, we had credit facilities
        totaling $2.9 billion to support our commercial paper program. At
        December 31, 2003, we had $282 million outstanding in short-term
        borrowings supported by these credit facilities. In addition, JMG has
        commercial paper outstanding in the amount of $26 million. This
        commercial paper is specifically associated with the Gavin scrubber
        lease. This commercial paper does not reduce available liquidity.

  o     In February 2003, we issued over $2 billion of senior notes through our
        Ohio and Texas subsidiaries. The proceeds were used to repay the bank
        facility that was due to mature in April 2003, retire short-term debt
        and for other general corporate purposes. During the remainder of the
        year, our subsidiaries issued an additional $2.3 billion in senior
        notes and refinanced approximately $465 million in pollution control
        revenue bonds. The proceeds of these issuances were used to term-out
        short-term debt, fund long-term debt maturities and fund optional
        redemptions.

  o     In March 2003, AEP issued a $500 million senior unsecured note. The
        proceeds of this issuance were used to pay-down $225 million of the
        Steelhead financing and to prefund a portion of the AEP Resources bond
        that matured in December 2003.

  o     In May 2003, a third party exercised its option to call our $250
        million of 5.50% putable callable notes, issued in May 2001, for
        purchase and remarketing. On May 15, 2003, AEP issued $300 million of
        5.25% senior notes due 2015, a portion of which was an exchange for the
        $250 million putable callable notes due in 2003 that were outstanding 
        at that time.

  o     AEP Credit extended its sale of receivables agreement from its May 28,
        2003 expiration to July 25, 2003, when the agreement was renewed for an
        additional 364 days. The sale of receivables agreement, which expires
        on July 23, 2004, provides commitments of $600 million to purchase
        receivables from AEP Credit. At December 31, 2003, $385 million of
        commitments to purchase accounts receivable were outstanding under the
        receivables agreement. All receivables sold represent affiliate
        receivables. AEP Credit maintains a retained interest in the
        receivables sold and this interest is pledged as collateral for the
        collection of receivables sold. The fair value of the retained interest
        is based on book value due to the short-term nature of the accounts
        receivable less an allowance for anticipated uncollectible accounts.

  o     In September 2003, we closed on a $200 million revolving loan and
        letter of credit facility. The facility is available for the issuance
        of letters of credit and for general corporate purposes. The facility
        will expire in September 2006.

Minority Interest and Off-balance Sheet Arrangements
----------------------------------------------------

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

Minority Interest in Finance Subsidiary
---------------------------------------
We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was convertible into our 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 for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. SubOne is the managing member of Caddis. As a result SubOne and all of
its subsidiaries, including Caddis, HPL and LIG, are included in our
Consolidated financial statements.

Steelhead is an unconsolidated special purpose entity and had an original
capital structure of $750 million (currently approximately $525 million) of
which 3% is equity from investors with no relationship to us or any of our
subsidiaries and 97% is debt from a syndicate of banks. The $525 million
invested in Caddis by Steelhead was loaned to SubOne. The loan to SubOne is due
August 2006. Net proceeds from the planned sale of LIG will be used to reduce
the outstanding balance of the loan from Caddis.

On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis,
which included amounts previously reported as Minority Interest in Finance
Subsidiary ($759 million at December 31, 2002 and $533 million at June 30,
2003). As a result, a $527 million note payable to Caddis is part of our
Long-Term Debt at December 31, 2003. Application of FIN 46 is prospective and
we, therefore, did not change the presentation of Minority Interest in Finance
Subsidiary in periods prior to July 1, 2003.

On May 9, 2003, we reduced the outstanding balance of our note payable to Caddis
by $225 million. Caddis used these proceeds to reduce the preferred interest in
Caddis that was held by Steelhead. This payment eliminated the convertible
preferred stock of AEP Gas Holding which under certain conditions had been
convertible to AEP stock.

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,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of our outstanding debt in excess of $50 million
would be an event of default under the credit agreement.

SubOne has deposited $422 million in a cash reserve fund in order to comply with
certain covenants in the credit agreement. Pursuant to the terms of the credit
agreement, SubOne subsequently loaned these funds to affiliates, and we
guaranteed the repayment obligations of these affiliates. These loans must be
repaid in the event our credit ratings fall below investment grade.

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. Liquidation of Caddis could negatively impact our
liquidity.

AEP Credit
----------

AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, AEP Credit sells an interest
in the receivables it acquires to the commercial paper conduits and banks and
receives cash. This transaction constitutes a sale of receivables in accordance
with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance
sheet and allowing AEP Credit to repay any debt obligations. AEP has no
ownership interest in the commercial paper conduits and 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.

AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 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. 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.

Rockport Plant Unit 2
---------------------

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee), an unrelated unconsolidated trustee
for Rockport Plant Unit 2 (the plant). The Owner Trustee was capitalized with
equity from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and certain institutional
investors.  The future minimum lease payments for each respective company are
$1.4 billion.

The FASB and other accounting constituencies continue to interpret the 
application of FIN 46 (revised December 2003) (FIN 46R).  As a result, we are
continuing to review the application of this new interpretation as it relates
to the Rockport Unit 2 transaction.

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. Neither
AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of
these entities guarantee its debt.

Railcars
--------

In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years. We intend to renew the lease for
the full twenty years.

At the end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the purchase
price amount specified in the lease, projected at the lease inception to be the
then fair market value, or (c) return the railcars and arrange a third party
sale (return-and-sale option). The lease is accounted for as an operating lease
with the future payment obligations included in the annual lease footnote. This
operating lease agreement allows us to avoid a large initial capital
expenditure, and to spread our railcar costs evenly over the expected
twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under
the return-and-sale option discussed above will equal at least a lessee
obligation amount specified in the lease, which declines over time from
approximately 86% to 77% of the projected fair market value of the equipment. At
December 31, 2003, the maximum potential loss was approximately $31.5 million
($20.5 million net of tax) assuming the fair market value of the equipment is
zero at the end of the current lease term. The railcars are subleased for one
year to an unaffiliated company under an operating lease. The sublessee may
renew the lease for up to four additional one-year terms. AEP has other railcar
lease arrangements that do not utilize this type of financing structure.

Summary Obligation Information
------------------------------

Our contractual obligations include amounts reported on the Consolidated Balance
Sheets and other obligations disclosed in the footnotes. The following table
summarizes our contractual cash obligations at December 31, 2003:


<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
----------------------------                 ----------------    ---------      ---------      -------------    -----

<C>                                               <C>             <C>            <C>             <C>           <C>    
Long-term Debt                                    $1,779          $3,460         $1,711           $7,151       $14,101
Short-term Debt                                      326               -              -                -           326
Preferred Stock Subject to
 Mandatory Redemption                                  -               -             21               55            76
Capital Lease Obligations                             63              77             49               31           220
Unconditional Purchase
 Obligations (a)                                   1,720           2,132          1,101            1,785         6,738
Noncancellable Operating Leases                      291             492            441            2,331         3,555
                                                  -------         -------        -------         --------      --------
  Total                                           $4,179          $6,161         $3,323          $11,353       $25,016
                                                  =======         =======        =======         ========      ========

</TABLE>


(a)   Represents contractual obligations to purchase coal and natural gas as
      fuel for electric generation along with related transportation of the
      fuel.

Some of the transactions, described under "Minority Interest and Off-Balance
Sheet Arrangements" above, include contractual cash obligations reported in the
above table. The lease of Rockport Unit 2 and Railcars are reported in
Noncancellable Operating Leases. The Minority Interest in Finance Subsidiary is
reported in Long-term Debt.

In addition to the amounts disclosed in the contractual cash obligations table
above, we make additional commitments in the normal course of business. These
commitments include standby letters of credit, guarantees for the payment of
obligation performance bonds, and other commitments. Our commitments outstanding
at December 31, 2003 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
----------------------------                ----------------    ---------     ---------     -------------     -----

<C>                                            <C>                 <C>            <C>            <C>         <C>   
Standby Letters of Credit (a)                    $175               $43            $-              $9          $227  
Guarantees of the Performance of 
 Outside Parties (b)                                -                18             1             134           153  
Guarantees of our Performance                   1,083               107             -               8         1,198  
Transmission Facilities for
 Third Parties (c)                                 99               110            54               -           263  
Other Commercial
 Commitments (d)                                   14                14             -               -            28  
                                               -------             -----          ----           -----       -------
Total Commercial Commitments                   $1,371              $292           $55            $151        $1,869  
                                               =======             =====          ====           =====       =======

</TABLE>


(a)   We have issued standby letters of credit to third parties. These letters
      of credit cover gas and electricity risk management contracts,
      construction contracts, insurance programs, security deposits, debt
      service reserves and credit enhancements for issued bonds. All of these
      letters of credit were issued in the ordinary course of business. The
      maximum future payments of these letters of credit are $227 million with
      maturities ranging from January 2004 to January 2011. As the parent of all
      of these subsidiaries, we hold all assets of the subsidiaries as
      collateral. There is no recourse to third parties in the event these
      letters of credit are drawn.
(b)   These amounts are the balances drawn, not the maximum guarantee disclosed
      in Note 8.
(c)   As construction agent for third party owners of transmission facilities,
      we have committed by contract terms to complete construction by dates
      specified in the contracts. Should we default on these obligations,
      financial payments could be required including liquidating damages of up
      to $8 million and other remedies required by contract terms.
(d)   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 which could be up to 20% of the plant's capacity.

Expenditures for domestic electric utility construction are estimated to be $5.8
billion for the next three years. Approximately 80% of those construction
expenditures is expected to be financed by internally generated funds.

Other
-----

Power Generation Facility
-------------------------

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Construction of the Facility was begun by Katco Funding, Limited Partnership
(Katco), an unrelated unconsolidated special purpose entity. Katco assigned its
interest in the Facility to Juniper in June 2003.

Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after
construction is completed.

At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation (COD). In
the fourth quarter of 2003, we chose to not seek funding from Juniper for 
budgeted and approved pipeline construction costs related to the Facility. 
In order to continue reporting the Facility as an off-balance sheet financing,
we were required to seek funding of our construction costs from Juniper.
As a result, we recorded $496 million of construction work in progress (CWIP) 
and the related financing liability for the debt and equity as of December 31, 
2003. At December 31, 2003, the lease of the Facility is reported as an owned 
asset under a lease financing transaction. Since the debt obligations of the 
Facility are recorded on our financial statements, the obligations under the 
lease agreement are excluded from the above table of future minimum lease 
payments.

We are the construction agent for Juniper. We expect to achieve COD in the
spring of 2004, at which time the obligation to make payments under the lease
agreement will begin to accrue and we will sublease the Facility to The Dow
Chemical Company (Dow). If COD does not occur on or before March 14, 2004,
Juniper has the right to terminate the project. In the event the project is
terminated before COD, we have the option to either purchase the Facility for
100% of Juniper's acquisition cost (in general, the outstanding debt and equity
associated with the Facility) or terminate the project and make a payment to
Juniper for 89.9% of project costs (in general, the acquisition cost less
certain financing costs).

The initial term of the lease agreement between Juniper and AEP commences on COD
and continues for five years. The lease contains extension options, and if all
extension options are exercised, the total term of the lease will be 30 years.
AEP's lease payments to Juniper during the initial term and each extended term
are sufficient for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to the
investors in Juniper. We have the right to purchase the Facility for the
acquisition cost during the last month of the initial term or on any monthly
rent payment date during any extended term. In addition, we may purchase the
Facility from Juniper for the acquisition cost at any time during the initial
term if we have arranged a sale of the Facility to an unaffiliated third party.
A purchase of the Facility from Juniper by AEP should not alter Dow's rights to
lease the Facility or our contract to purchase energy from Dow. If the lease
were renewed for up to a 30-year lease term, we may further renew the lease at
fair market value subject to Juniper's approval, purchase the Facility at its
acquisition cost, or sell the Facility, on behalf of Juniper, to an independent
third party. If the Facility is sold and the proceeds from the sale are
insufficient to pay all of Juniper's acquisition costs, we may be required to
make a payment (not to exceed $396 million) to Juniper of the excess of
Juniper's acquisition costs over the proceeds from the sale, provided that we
would not be required to make any payment if we have made the additional rental
prepayment described below. We have guaranteed the performance of our
subsidiaries to Juniper during the lease term. Because we now report the debt
related to the Facility on our balance sheet, the fair value of the liability
for our guarantee (the $396 million payment discussed above) is not separately
reported.

At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496
million, and total costs for the completed Facility are currently expected to be
approximately $525 million. For the 30-year extended lease term, the base lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently,
as market interest rates increase, the base rental payments under the lease will
also increase. Annual payments of approximately $18 million represent future
minimum payments for interest on Juniper's financing structure during the
initial term calculated using the indexed LIBOR rate (1.15% at December 31,
2003). An additional rental prepayment (up to $396 million) may be due on June
30, 2004 unless Juniper has refinanced its present debt financing on a long-term
basis. Juniper is currently planning to refinance by June 30, 2004. The Facility
is collateral for the debt obligation of Juniper. At December 31, 2003, we
reflected $396 million of the $496 million recorded obligation as long-term debt
due within one year. Our maximum required cash payment as a result of our
financing transaction with Juniper is $396 million as well as interest payments
during the lease term. Due to the treatment of the Facility as a financing of an
owned asset, the recorded liability of $496 million is greater than our maximum
possible cash payment obligation to Juniper.

Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.

On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable, or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms to the extent we do not
fully recover claimed termination value damages from TEM. The corporate parent
of TEM has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM
basically argued that in the absence of mutually agreed upon protocols there was
no commercially reasonable means to obtain or deliver the electric power
products and therefore the PPA is not enforceable. TEM further argued that the
creation of the protocols is not subject to arbitration. The arbitrator ruled in
favor of TEM on February 11, 2004 and concluded that the "creation of protocols"
was not subject to arbitration, but did not rule upon the merits of TEM's claim
that the PPA is not enforceable.

If commercial operation is not achieved for purposes of the PPA by April 30,
2004, TEM may claim that it can terminate the PPA and is owed liquidating
damages of approximately $17.5 million. TEM may also claim that we are not
entitled to receive any termination value for the PPA.

The current litigation between TEM and ourselves, combined with a substantial
oversupply of generation capacity in the markets where we would otherwise sell
the power freed up by the TEM contract termination, triggered us to review the
project for possible impairment of its reported values. We determined that the
value of the Facility was impaired and recorded a $258 million pre-tax
impairment in December 2003 on the CWIP.

SIGNIFICANT FACTORS
-------------------

Possible Divestitures
---------------------  

We are firmly committed to continually evaluating the need to reallocate
resources to areas that effectively match our investments with our business
strategy, providing the greatest potential for financial returns. We are
committed to disposing of investments that no longer meet these goals.

We are seeking to divest significant components of our non-regulated assets,
including certain domestic and international unregulated generation, part of our
gas pipeline and storage business, a coal business, independent power producers
(IPPs) and a communications business. In June 2003, we began actively seeking
buyers for 4,497 megawatts of unregulated generating capacity in Texas. The
value received from this disposition will also be used to calculate our stranded
costs in Texas (see Note 6). We are currently evaluating bids received during
the fourth quarter of 2003 and are in negotiations to sell these assets.

During the second quarter of 2003, we also hired an advisor to evaluate our coal
business, which has resulted in the receipt of non-binding bids. We are
currently negotiating the anticipated sale of certain assets from this business.
In the fourth quarter of 2003, in connection with the evaluation of this
business, we recorded a $66.6 million pre-tax charge related to asset
impairments, remediation accruals and other exit costs (see Note 10).

During the third quarter of 2003, management hired advisors to review business
options regarding various investment components of our Gas Operations. We
distributed an initial offering memorandum and request for proposal on the sale
of our Louisiana Intrastate Gas and Jefferson Island Storage Facility operations
during the fourth quarter of 2003. We are currently evaluating the proposals
that we received. We are evaluating the merits of retaining our interest in
Houston Pipe Line, which is part of Gas Operations. In connection with our
review of the Gas Operations, we recorded $133.9 million in pre-tax charges
related to LIG and $315 million in pre-tax charges related to HPL (see Note 10).
We signed a sale agreement for the pipeline portion of LIG in the first quarter
of 2004 and we expect the sale to close shortly with an immaterial impact on 
2004 results of operations.

During the third quarter of 2003, we initiated an effort to sell four domestic
IPP investments. Based on studies using current market assumptions, we believe
that two of the facilities had declines in fair value that are other than
temporary in nature. As a consequence, we recorded an impairment of $70 million
pre-tax ($45.5 million net of tax) in the third quarter of 2003 (see Note 10).
During the fourth quarter of 2003, we distributed an information memorandum
related to the possible sale of our interest in these IPPs. We have received and
are reviewing final bids and anticipate a sale of the four domestic IPP
investments in 2004.

During the fourth quarter of 2003, we engaged an advisor for the disposition of
our U.K. business and are planning to dispose of these assets in 2004. In
connection with the evaluation of this business, we recorded a pre-tax charge of
$577.4 million during the fourth quarter of 2003 based on indications of value
received from potential buyers (see Note 10).

Management continues to have periodic discussions with various parties on
business alternatives for certain of our other non-core investments.

The ultimate timing for a disposition of one or more of these assets will depend
upon market conditions and the value of any buyer's proposal. We may realize
losses from operations or upon disposition of these assets that, in the
aggregate, could have a material impact on our results of operations, cash flows
and financial condition.

Corporate Separation 
--------------------

In Texas, we are in the process of divesting our TCC generating assets in
accordance with provisions of the Texas Legislation concerning stranded cost
recovery (see Note 6). In order to sell these assets, we anticipate retiring
TCC's first mortgage bonds by making open market purchases or defeasing the 
bonds.  Once such generating assets are sold, which we expect to be finalized 
in 2004, we will effectively accomplish the structural separation requirements 
of the Texas Legislation for those assets.

In Ohio, the PUCO has encouraged utilities to file rate stabilization plans to
provide rate certainty and stability for customers who do not choose alternative
suppliers, for the period of January 1, 2006 through December 31, 2008, which is
after the expiration of the current market development period. On February 9,
2004, CSPCo and OPCo filed such a rate stabilization plan with the PUCO. The
plan, in part, provides that both CSPCo and OPCo will remain functionally
separated. Approval of the rate stabilization plan is currently pending before
the PUCO.

Unless otherwise directed by the PUCO in an order on the rate stabilization
plan, CSPCo and OPCo will remain functionally separated through at least the end
of the rate stabilization plan period, December 31, 2008, and therefore, are not
planning to legally separate, or to change the affiliate pooling agreement for
the AEP East companies, in the foreseeable future.

Management continues to evaluate the most appropriate approach for complying
with the Texas Legislation's structural separation requirements for TNC,
including appropriate regulatory approvals to implement its structural
separation.

RTO Formation
-------------

The FERC's AEP-CSW merger approval and many of the settlement agreements with
the state regulatory commissions to approve the AEP-CSW merger required the
transfer of functional control of our subsidiaries' transmission systems to
RTOs. Further, legislation in some of our states requires RTO participation.

In May 2002, we announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to be
negotiated. In July 2002, FERC issued an order accepting our decision to
participate in PJM, subject to specified conditions. AEP and other parties
continue to work on the resolution of those conditions.

In December 2002, our subsidiaries that operate in the states of Indiana,
Kentucky, Ohio and Virginia filed for state regulatory commission approval of
their plans to transfer functional control of their transmission assets to PJM.
Proceedings in Ohio remain pending. 

In February 2003, the state of Virginia enacted legislation preventing APCo 
from joining an RTO prior to July 1, 2004 and thereafter only with the approval
of the Virginia SCC, but required such transfers by January 1, 2005. In January
2004, APCo filed a cost/benefit study with the Virginia SCC covering the time 
period through 2014 as required by the Virginia SCC. The study results show a 
net benefit of approximately $98 million for APCo over the 11-year study period
from AEP's participation in PJM.

In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In December 2003,
AEP filed with the KPSC a cost/benefit study showing a net benefit of
approximately $13 million for KPCo over the five-year study period from AEP's
participation in PJM. A hearing has been scheduled in April 2004.

In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
deferral of the costs for future recovery.

In April 2003, FERC approved our transfer of functional control of the AEP East
companies' transmission system to PJM. FERC also accepted our proposed rates for
joining PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings. Settlement discussions continue on certain rate
matters.

On September 29 and 30, 2003, the FERC held a public inquiry regarding RTO
formation, including delays in AEP's participation in PJM. In November 2003, the
FERC issued an order preliminarily finding that AEP must fulfill its CSW merger
commitment to join an RTO by fully integrating into PJM (transmission and
markets) by October 1, 2004. The FERC set several issues for public hearing
before an ALJ. Those issues include whether the laws, rules, or regulations of
Virginia and Kentucky are preventing AEP from joining an RTO and whether the
states' provisions meet either of the two exceptions under PURPA. The FERC
directed the ALJ to issue his initial decision by March 15, 2004.

If AEP East companies do not obtain regulatory approval to join PJM, we are
committed to reimburse PJM for certain project implementation costs (presently
estimated at $24 million for AEP's share of the entire PJM integration project).
AEP also has $28 million, at December 31, 2003, of deferred RTO
formation/integration costs for which we plan to seek recovery in the future.
See Note 4 for further discussion.

AEP West companies are members of ERCOT or SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and SPP. State
public utility commissions also regulate our SPP companies. The Louisiana and
Arkansas commissions filed responses to the FERC's RTO order indicating that
additional analysis was required. Subsequently, the proposed SPP/MISO
combination was terminated. On October 15, 2003, SPP filed a proposal at FERC
for recognition as an RTO. In February 2004, FERC granted RTO status to the SPP,
subject to fulfilling specified requirements. Regulatory activities concerning
various RTO issues are ongoing in Arkansas and Louisiana.

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

Pension Plans
-------------

We maintain qualified, defined benefit pension plans (Qualified Plans), which
cover a substantial majority of 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, we have entered into individual retirement agreements with certain
current and retired executives that provide additional retirement benefits.

Our net periodic pension expense was an income item for all pension plans
approximating $3 million and $44 million for the years ended December 31, 2003
and 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. In 2002 and 2003, the long-term return was assumed to be 9.00%,
and for 2004, the long-term rate of return was lowered to 8.75%. In developing
the expected long-term rate of return assumption, we evaluated input from
actuaries and investment consultants, including their reviews of asset class
return expectations as well as long-term inflation assumptions. Projected
returns by such actuaries and consultants are based on broad equity and bond
indices. We also considered historical returns of the investment markets as well
as our 10-year average return, for the period ended December 2003, of
approximately 10.0%. We anticipate that the investment managers we employ for
the pension fund will continue to generate long-term returns of at least 8.75%.

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



<TABLE>
<CAPTION>
                                                                  2003                   2004             Assumed/Expected
                                                                 Actual                 Target             Long-term Rate
                                                            Asset Allocation       Asset Allocation          of Return
                                                            ----------------       ----------------       ----------------
                                                                                    (in percentage)
    <C>                                                               <C>                  <C>                     <C>  
    Equity                                                             71                   70                     10.5 
    Fixed Income                                                       27                   28                        5 
    Cash and Cash Equivalents                                           2                    2                        2 
                                                                      ----                 ----
    Total                                                             100                  100
                                                                      ====                 ====

    Overall Expected Return (weighted average)                                                                     8.75
                                                                                                                   ====

</TABLE>


We regularly review the actual asset allocation and periodically rebalance the
investments to our targeted allocation when considered appropriate. We believe
that 8.75% is a reasonable long-term rate of return on the Qualified Plans'
assets despite the recent market volatility in which the Qualified Plans' assets
had a loss of 11.2% for the twelve months ended December 31, 2002, and a gain of
23.8% for the twelve months ended December 31, 2003. We will continue to
evaluate the actuarial assumptions, including the expected rate of return, at
least annually, and will adjust them as necessary.

We base our determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of December 31, 2003, we had
cumulative losses of approximately $325 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 we utilize 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 6.75% at December 31, 2002, to 6.25% at December 31, 2003.
Due to the effect of the unrecognized actuarial losses and based on an expected
rate of return on the Qualified Plans' assets of 8.75%, a discount rate of 6.25%
and various other assumptions, we estimate that the pension expense for all
pension plans will approximate $41 million, $78 million and $103 million in
2004, 2005 and 2006, respectively. Future actual pension cost 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
0.5% (from 9.0% to 8.5%) would have increased pension cost for 2003 by
approximately $18 million (income of $3 million would have become $15 million in
pension expense). Lowering the discount rate by 0.5% would have reduced pension
income for 2003 by approximately $0.5 million.

The value of the Qualified Plans' assets has increased from $2.795 billion at
December 31, 2002 to $3.180 billion at December 31, 2003. The Qualified Plans
paid out $292 million in benefits to plan participants during 2003 (the
nonqualified plans paid out $7 million in benefits). Our plans remain in an
underfunded position (plan assets are less than projected benefit obligations)
of $508 million at December 31, 2003. Due to the pension plans currently being
underfunded, we recorded a charge to Other Comprehensive Income (OCI) of $585
million in 2002, and recorded a Deferred Income Tax Asset of $315 million,
offset by a Minimum Pension Liability of $662 million and a reduction to prepaid
costs and adjustment for unrecognized costs of $238 million. In 2003, the income
recorded in OCI was $154 million, and the reduction in the Deferred Income Tax
Asset was $76 million, offset by a reduction in Minimum Pension Liability of
$234 million and a reduction to adjustment for unrecognized costs of $4 million.
The charge to OCI does not affect earnings or cash flow. Due to the current
underfunded status of the Qualified Plans, we expect to make cash contributions
to the pension plans of approximately $41 million in 2004.

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

Nuclear Plant Outages 
---------------------

In April 2003, engineers at STP, during inspections conducted regularly as part
of refueling outages, found wall cracks in two bottom mounted instrument guide
tubes of STP Unit 1. These tubes were repaired and the unit returned to service
in August 2003. Our share of the cost of repair for this outage was
approximately $6 million. We had commitments to provide power to customers
during the outage. Therefore, we were subject to fluctuations in the market
prices of electricity and purchased replacement energy.

In April 2003, both units of Cook Plant were taken offline due to an influx of
fish in the plant's cooling water system which caused a reduction in cooling
water to essential plant equipment. After repair of damage caused by the fish
intrusion, Cook Plant Unit 1 returned to service in May and Unit 2 returned to
service in June following completion of a scheduled refueling outage.

Litigation
----------

Federal EPA Complaint and Notice of Violation
---------------------------------------------

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

Enron Bankruptcy
----------------

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, certain subsidiaries of 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 from Enron 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
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.

We also entered into an agreement with BAM Lease Company which grants HPL the
exclusive right to use approximately 65 billion cubic feet of cushion gas
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on
55 billion cubic feet of this cushion gas. These banks claim to have certain
rights to the cushion gas in certain events of default. In connection with our
acquisition of HPL, the banks and Enron entered into an agreement granting HPL's
exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks
released HPL from all prior and future liabilities and obligations in connection
with the financing arrangement. After the Enron bankruptcy, HPL was informed by
the banks of a purported default by Enron under the terms of the financing
arrangement. In July 2002, the banks filed a lawsuit against HPL in the state
court of Texas seeking a declaratory judgment that they have a valid and
enforceable security interest in gas purportedly in the Bammel storage facility
which would permit them to cause the withdrawal of up to 55 billion cubic feet
of gas from the storage facility.  In September 2002, HPL filed a general denial
and certain counterclaims against the banks including that Enron was a necessary
and indispensable party to the Texas state court proceeding initiated by BOA.
HPL also filed a motion to dismiss, which was denied. In December 2003, the
Texas state court granted partial summary judgment in favor of the banks. HPL
appealed this decision. We have considered the possible outcomes of these 
issues in our impairment analysis of HPL; however, actual results could differ 
from those estimates. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows and financial 
condition.

In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against
BOA in the United States District Court for the Southern District of Texas. On
January 8, 2004, this lawsuit was amended and seeks damages for BOA's breach of
contract, negligent misrepresentation and fraud in connection with transactions
surrounding our acquisition of HPL from Enron including entering into the Bammel
storage facility lease arrangement with Enron and the cushion gas arrangements
with BOA and Enron. BOA led a lending syndicate involving the 1997 gas
monetization that Enron and its subsidiaries undertook and the leasing of the
Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA
made misrepresentations and engaged in fraud to induce and promote the stock
sale of HPL, that BOA directly benefited from the sale of HPL and that AEP
undertook the stock purchase and entered into the Bammel storage facility lease
arrangement with Enron and the cushion gas arrangement with Enron and BOA based
on misrepresentations that BOA made about Enron's financial condition that BOA
knew or should have known were false including that the 1997 gas monetization
did not contravene or constitute a default of any federal, state, or local
statute, rule, regulation, code or any law.

In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. We will
assert our right to offset trading payables owed to various Enron entities
against trading receivables due to several AEP subsidiaries. Management is
unable to predict the outcome of this lawsuit or its impact on our results of
operations, cash flows or financial condition.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.

During 2002 and 2001, we expensed a total of $53 million ($34 million net of
tax) for our estimated loss from the Enron bankruptcy. The amount expensed was
based on an analysis of contracts where AEP and Enron entities are
counterparties, the offsetting of receivables and payables, the application of
deposits from Enron entities and management's analysis of the HPL related
purchase contingencies and indemnifications. As noted above, Enron has
challenged our offsetting of receivables and payables and the Bammel storage
facility lease agreement and cushion gas agreement. Management is unable to
predict the final resolution of these disputes, however the impact on results of
operations, cash flows and financial condition could be material.

Bank of Montreal Claim
----------------------

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit against BOM claiming BOM had acted contrary to the appropriate trading
contract and industry practice in terminating the contract and calculating
termination and liquidation amounts and that BOM had acknowledged just prior to
the termination and liquidation that it owed us approximately $68 million. We
are claiming that BOM owes us at least $45 million. 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.

Arbitration of Williams Claim
-----------------------------

In 2002, we filed a 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.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter had an immaterial
impact on results of operations and financial condition. See Note 7 for further
discussion.

Arbitration of PG&E Energy Trading, LLC Claim
---------------------------------------------

In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement with AEP paying approximately $11
million to PGET. The settlement amount approximated the amount payable that, in
the ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the settlement payment did not have a
material impact on results of operations, cash flows or financial condition.

Energy Market Investigations
----------------------------

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

In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC seeking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.

On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 2004. Although management is
unable to predict the outcome of this case, we recorded a provision in 2003 and
the action is not expected to have a material effect on results of operations.

In January 2004, the CFTC issued a request for documents and other information
in connection with a CFTC investigation of activities affecting the price of
natural gas in the fall of 2003. We are responding to that request.

Management cannot predict what, if any further action, any of these governmental
agencies may take with respect to these matters.

Shareholders' Litigation
------------------------

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

California Lawsuit
------------------

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 has been dismissed
from the case. See Note 7 for further discussion.

Cornerstone Lawsuit
-------------------

In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Shortly thereafter, a similar action was filed in the same court against
eighteen companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. These cases
are in the initial pleading stage. Management believes that the cases are
without merit and intends to vigorously defend against them.

TEM Litigation
--------------

See discussion of TEM litigation within the "Financial Condition - Other"
section of Management's Financial Discussion and Analysis.

Texas Commercial Energy, LLP Lawsuit
------------------------------------

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against us and
four AEP subsidiaries, certain unaffiliated energy companies and ERCOT alleging
violations of the Sherman Antitrust Act, fraud, negligent misrepresentation,
breach of fiduciary duty, breach of contract, civil conspiracy and negligence.
The allegations, not all of which are made against the AEP companies, range from
anticompetitive bidding to withholding power. TCE alleges that these activities
resulted in price spikes requiring TCE to post additional collateral and
ultimately forced it into bankruptcy when it was unable to raise prices to its
customers due to fixed price contracts. The suit alleges over $500 million in
damages for all defendants and seeks recovery of damages, exemplary damages and
court costs. Management believes that the claims against us are without merit.
We intend to vigorously defend against the claims. See Note 7 for further
discussion.

COLI Litigation
---------------

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. We filed an appeal of the
U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit. In April 2003, the Appeals Court ruled against AEP. The U.S. Supreme
Court has declined to hear this issue.

Snohomish Settlement 
--------------------

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 and paid $59 million to us. The settlement amount was
less than the amount receivable that, in the ordinary course of business, we
recorded using MTM accounting. As a result, we incurred a $10 million pre-tax
loss.

Other Litigation
----------------

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

Potential Uninsured Losses
--------------------------

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

Environmental Matters
---------------------

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

  o     Legislative and regulatory proposals to adopt stringent controls on
        sulfur dioxide (SO2), nitrogen oxide (NOx) and mercury emissions from
        coal-fired power plants,
  o     New Clean Water Act rules to reduce the impacts of water intake 
        structures on aquatic species at certain of our power plants, and 
  o     Possible future requirements to reduce carbon dioxide emissions to 
        address concerns about global climatic change.

In addition to achieving full compliance with all applicable legal requirements,
we strive to go beyond compliance in an effort to be good environmental
stewards. For example, we invest in research, through groups like the Electric
Power Research Institute, to develop, implement and demonstrate new emission
control technologies. We plan to continue in a leadership role to protect and
preserve the environment while providing vital energy commodities and services
to customers at fair prices. We have a proven record of efficiently producing
and delivering electricity and gas while minimizing the impact on the
environment. We invested over $2 billion, from 1990 through 2003, to equip many
of our facilities with pollution control technologies.  We will continue to 
make investments to improve the air emissions from our generating stations 
because this is the most cost effective generation source for our customers'
electricity needs.

The Current Air Quality Regulatory Framework
--------------------------------------------

The Clean Air Act (CAA) is the legislation that establishes the federal
regulatory authority and oversight for emissions from our fossil-fired
generating plants. The states, with oversight and approval from the Federal EPA,
administer and enforce these laws and related regulations.

Title I of the CAA
------------------

National Ambient Air Quality Standards 
--------------------------------------

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

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

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

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

The Federal EPA also granted four petitions filed by certain eastern states
seeking essentially the same levels of control on emission sources outside of
their states and issued a Section 126 Rule. All of the states in which we
operate that were subject to the NOx Rule have submitted the required SIP
revisions. In response, the Federal EPA issued the NOx Rule and the Section 126
Rule, which are discussed below.

The compliance date for the NOx Rule is May 31, 2004. In 2000, the Federal EPA
also adopted a revised Section 126 Rule which granted petitions filed by four
northeastern states. The revised Section 126 Rule imposes emissions reduction
requirements comparable to the NOx Rule also beginning May 31, 2004, for most of
our coal-fired generating units.

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

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

AEP's electric utility units are currently subject to SIP requirements that
control SO2 and particulate matter emissions in all states, and that control NOx
emissions in certain states. Our generating plants comply with applicable SIP
limits for SO2, NOx and particulate matter.

Hazardous Air Pollutants 
------------------------

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

New Source Performance Standards and New Source Review 
------------------------------------------------------

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

Different NSR requirements apply in attainment and non-attainment areas.

In attainment areas:
  o     An air quality review must be performed, and
  o     The best available control technology must be employed to reduce new
        emissions.

In non-attainment areas,
  o     Requirements reflecting the lowest achievable emission rate are 
        applied to new or modified sources, and
  o     All new emissions must be offset by reductions in emissions of the same
        pollutant from other sources within the same control area.

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

Title IV of the CAA (Acid Rain)
-------------------------------

The 1990 Amendments to the CAA included a market-based emission reduction
program designed to reduce the amount of SO2 emitted from electric utility units
by approximately 50 percent from 1980 levels. This program also established a
nationwide cap on utility SO2 emissions of 8.9 million tons per year. The
Federal EPA administers its SO2 program through an allowance allocation and
trading system. Allowances are allocated to specific units based on statutory
formulas. Annually each utility unit must surrender one allowance for each ton
of SO2 that it emits. Emission sources that install controls and no longer need
all of their allowances can bank those allowances for future use or trade them
to other emission sources.

Title IV also contains requirements for utility sources to reduce NOx emissions
through the use of available combustion controls. Units must meet NOx emission
rates standards which are specific to that unit or units may participate in an
annual averaging program for utility units that are under common control.

Future Reduction Requirements for SO2, NOx, and Mercury
-------------------------------------------------------

In 1997, the Federal EPA adopted new, more stringent NAAQS for fine particulate
matter and ground-level ozone. The Federal EPA is in the process of developing
final designations for fine particulate matter and ground-level ozone
non-attainment areas. The Federal EPA has identified SO2 and NOx emissions as
precursors to the formation of fine particulate matter. NOx emissions are also
identified as a precursor to the formation of ground-level ozone. As a result,
requirements for future reductions in emissions of NOx and SO2 from our
generating units are highly probable. In addition, the Federal EPA has proposed
a set of options for future mercury controls at coal-fired power plants.

Multi-emission control legislation, known as the Clear Skies Act, was introduced
in Congress and is supported by the Bush Administration. This legislation would
regulate NOx, SO2, and mercury emissions from electric generating plants. We
support enactment of this comprehensive, multi-emission legislation so that
compliance planning can be coordinated and collateral emission reductions
maximized. We believe the Bush Administration's Clear Skies Act would establish
stringent emission reduction targets and achievable compliance timetables
utilizing a cost-effective nationwide cap and trade program. Although the
prospects for enactment of the Clear Skies Act are low, there are alternative
regulatory approaches which will likely require us to substantially reduce SO2,
NOx and mercury emissions over the next ten years.

Regulatory Emissions Reductions
-------------------------------

On January 30, 2004, the Federal EPA published two proposed rules that would
collectively require reductions of approximately 70% in emissions of SO2, NOx
and mercury from coal-fired electric generating units by 2015 (2018 for
mercury). This initiative has two major components:

  o     The Federal EPA proposed an interstate air quality rule for reducing
        SO2 and NOx emissions across the eastern half of the United States (29
        states and the District of Columbia) to address attainment of the fine
        particulate matter and ground-level ozone NAAQS. These reductions could
        also satisfy these states' obligations to make reasonable progress
        towards the national visibility goal under the regional haze program.
  o     The Federal EPA proposed to regulate mercury emissions from coal-fired
        electric generating units.

The interstate air quality rule would require affected states to include, in
their SIPs, a program to reduce NOx and SO2 emissions from coal-fired electric
utility units. SO2 and NOx emissions would be reduced in two phases, which would
be implemented through a cap-and-trade program. Regional SO2 emissions would be
reduced to 3.9 million tons by 2010 and to 2.7 million tons by 2015. Regional
NOx emissions would be reduced to 1.6 million tons by 2010 and to 1.3 million
tons by 2015. Rules to implement the SO2 and NOx trading programs have not yet
been proposed.

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

The Federal EPA recommends, and we support, a second mercury emission reduction
option. The second option would permit mercury emission reductions to be
achieved from existing sources through a national cap-and-trade approach. The
cap-and-trade approach would include a two-phase mercury reduction program for
coal-fired utilities. This approach would coordinate the reduction requirements
for mercury with the SO2 and NOx reduction requirements imposed on the same
sources under the proposed interstate air quality rule. Coordination is
significantly more cost-effective because technologies like scrubbers and SCRs,
that can be used to comply with the more stringent SO2 and NOx requirements,
have also proven highly effective in reducing mercury emissions on certain
coal-fired units that burn bituminous coal. The second option contemplates
reducing mercury emissions from 48 million tons to 34 million tons by 2010 and
to 15 million tons by 2018.

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

While uncertainty remains as to whether future emission reduction requirements
will result from new legislation or regulation, it is certain under either
outcome that we will invest in additional conventional pollution control
technology on a major portion of our fleet of coal-fired power plants.
Finalization of new requirements for further SO2, NOx and/or mercury emission
reductions will result in the installation of additional scrubbers, SCR systems
and/or the installation of emerging technologies for mercury control.

Estimated Air Quality Environmental Investments
-----------------------------------------------

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

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

  o     Timing of implementation
  o     Required levels of reductions
  o     Allocation requirements of the new rules, and
  o     Our selected compliance alternatives.

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

All of the costs discussed below are incremental to our current investment base
and operating cost structure. These expenditures for pollution control
technologies, replacement generation and associated operating costs are
recoverable from customers through regulated rates (in regulated jurisdictions)
and should be recoverable through market prices (in deregulated jurisdictions).
If not, those costs could adversely affect future results of operations and 
cash flows, and possibly financial condition.

Estimated Investments for NOx Compliance
----------------------------------------

We estimate that we will make future investments of approximately $600 million
to comply with the Federal EPA's NOx Rule, the Texas Commission on Environmental
Quality Rule and other final Federal EPA NOx-related requirements. Approximately
$500 million of these investments are reflected in our estimated construction
expenditures for 2004 - 2006. As of December 31, 2003, we have invested
approximately $1.1 billion to comply with various NOx requirements.

Estimated Investments for SO2 Compliance
----------------------------------------

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

  o     Receive in the annual allowance allocation by the Federal EPA, 
  o     Obtain through participation in the annual allowance auction, 
  o     Purchase in the allowance market, and 
  o     Obtained as bonus allowances for installing controls early.

Decreasing SO2 allowance allocations, a diminishing SO2 allowance bank, and
increasing allowance prices in the market will require us to install additional
controls on certain of our generating units. We plan to install 3,500 MW of
additional scrubbers over the next 4 years to comply with our Title IV SO2
obligations. In total we estimate these additional capital costs to be
approximately $1.2 billion. Of this total, we estimate that $900 million will be
expended during 2004-2006 and this amount is included in our total estimated
construction expenditures for 2004 - 2006.

Estimated Investments to Comply with Future Reduction Requirements
------------------------------------------------------------------

Our planning assumptions for the levels and timing of emissions reductions
parallel the reduction levels and implementation time periods stated in the
proposed rules issued by the Federal EPA in January 2004. We have also assumed
that the Federal EPA will implement a mercury trading option and will design its
proposed cap and trade mechanism for SO2, NOx and mercury emissions in a manner
similar to existing cap and trade programs. Based on these assumptions,
compliance would require additional capital investment of approximately $1.7
billion by 2010, the end of the first phase for each proposed rule. We also
estimate that we would incur increases in variable operation and maintenance
expenses of $150 million for the periods by 2010, due to the costs associated
with the maintenance of additional control systems, disposal of scrubber
by-products and the purchase of reagents. We estimate that we will invest $200
million of this amount through 2006, and this amount is included in our total
estimated construction expenditures for 2004 - 2006.

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

Beyond 2010, we expect to incur additional costs for pollution control
technology retrofits and associated operation and maintenance of the equipment.
We cannot estimate these additional costs because of the uncertainties
associated with the final control requirements and our associated compliance
strategy, but these capital and operating costs will be significant.

New Source Review Litigation
----------------------------

Under the CAA, if a plant undertakes a major modification that directly results
in an emissions increase, permitting requirements might be triggered and the
plant may be required to install additional pollution control technology. This
requirement does not apply to activities such as routine maintenance,
replacement of degraded equipment or failed components, or other repairs needed
for the reliable, safe and efficient operation of the plant.

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints
against our subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by certain
special interest groups, with the Federal EPA case. The alleged modifications
relate to costs that were incurred at our generating units over a 20-year
period.

We are unable to estimate the loss or range of loss related to the contingent
liability for civil penalties under the CAA proceedings. We are also unable to
predict the timing of resolution of these matters due to the number of alleged
violations and the significant number of issues yet to be determined by the
Court. If we do not prevail, any capital and operating costs of additional
pollution control equipment that may be required, as well as any penalties
imposed, would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered through
regulated rates and market prices for electricity.

Superfund and State Remediation
-------------------------------

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

Superfund addresses clean-up of hazardous substances at disposal sites and
authorized the Federal EPA to administer the clean-up programs. As of year-end
2003, subsidiaries of AEP are named by the Federal EPA as a PRP for five sites.
There are six additional sites for which our subsidiaries have received
information requests which could lead to PRP designation. Our subsidiaries have
also been named potentially liable at 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 we have been named a PRP or defendant, our
disposal or recycling activities were in accordance with the then-applicable
laws and regulations. Unfortunately, Superfund does not recognize compliance as
a defense, but imposes strict liability on parties who fall within its broad
statutory categories.

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

Global Climate Change
---------------------

At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997, more than
160 countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly CO2, which many scientists
believe are contributing to global climate change. The U.S. signed the Kyoto
Protocol on November 12, 1998, but the treaty was not submitted to the Senate
for its advice and consent by President Clinton. In March 2001, President Bush
announced his opposition to the treaty. Ratification of the treaty by a majority
of the countries' legislative bodies is required for it to be enforceable.
Enforceability of the protocol is now contingent on ratification by Russia,
which has expressed concerns about doing so.

On August 28, 2003, the Federal EPA issued a decision in response to a petition
for rulemaking seeking reductions of CO2 and other greenhouse gas emissions from
mobile sources. The Federal EPA denied the petition and issued a memorandum
stating that it does not have the authority under the Clean Air Act to regulate
CO2 or other greenhouse gas emissions that may affect global warming trends. The
Circuit Court of Appeals for the District of Columbia is reviewing these
actions.

We do not support the Kyoto Protocol but have been working with the Bush
Administration on a voluntary program aimed at meeting the President's goal of
reducing the greenhouse gas intensity of the economy by 18% by 2012. For many
years, we have been a leader in pursuing voluntary actions to control greenhouse
gas emissions. We expanded our commitment in this area in 2002 by joining the
Chicago Climate Exchange, a pilot greenhouse gas emission reduction and trading
program, under which we are obligated to reduce or offset 18 million tons of CO2
emissions during 2003-2006.

We acquired 4,000 MW of coal-fired generation in the United Kingdom in December
2001. These assets may have future CO2 emission control obligations beginning in
2005. We plan to dispose of our investment in this generation during 2004.

Costs for Spent Nuclear Fuel and Decommissioning
------------------------------------------------

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a
significant future financial commitment to safely dispose of SNF and to
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law I&M and TCC participate in the DOE's
SNF disposal program which is described in Note 7. Since 1983 I&M has collected
$316 million from customers for the disposal of nuclear fuel consumed at the
Cook Plant. We deposited $117 million of these funds in external trust funds to
provide for the future disposal of SNF and remitted $199 million to the DOE. TCC
has collected and remitted to the DOE, $56 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
with a trial scheduled in March 2004. As long as the delay in the availability 
of a government approved storage repository for SNF continues, the cost of 
both temporary and permanent storage of SNF and the cost of decommissioning 
will continue to increase.

The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed SNF disposal program. Studies completed in 2003 estimate the cost to
decommission the Cook Plant ranges from $821 million to $1.08 billion in 2003
non-discounted dollars. External trust funds have been established with amounts
collected from customers to decommission the plant. At December 31, 2003, the
total decommissioning trust fund balance for Cook Plant was $720 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, 2003, the total
decommissioning trust fund for TCC's share of STP was $125 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, our future
results of operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning continues to
increase and cannot be recovered.

Clean Water Act Regulation
--------------------------

On February 16, 2004, the Federal EPA signed a rule pursuant to the Clean Water
Act that will require all large existing power plants to meet certain 
performance standards to reduce the mortality of juvenile and adult fish or 
other larger organisms pinned against a plant's cooling water intake screens. 
A subset of these plants that are located on sensitive water bodies will be 
required to meet additional performance standards for reducing the number of
smaller organisms passing through the water screens and the cooling system. 
Sensitive water bodies are defined as oceans, estuaries, the Great Lakes, and 
small rivers with large plants. These rules will result in additional capital 
and operation and maintenance expenses to ensure compliance.

Other Environmental Concerns
----------------------------

We perform environmental reviews and audits on a regular basis for the purpose
of identifying, evaluating and addressing environmental concerns and issues. In
addition to the matters discussed above we are managing other environmental
concerns which we do not believe are material or potentially material at this
time. If they become significant or if any new matters arise that we believe
could be material, they could have a material adverse effect on results of
operations, cash flows and possibly financial condition.

Critical Accounting Policies
----------------------------

In the ordinary course of business, we use a number of estimates and assumptions
relating to the reporting of results of operations and financial condition in
the preparation of our financial statements in conformity with accounting
principles generally accepted in the United States of America, including amounts
related to legal matters and contingencies. Actual results can differ
significantly from those estimates under different assumptions and conditions.

We 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
---------------------

Our consolidated financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate-regulated. We recognize regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) for the economic effects of
regulation. Specifically, we match the timing of our expense recognition with
the recovery of such expense in regulated revenues. Likewise, we match income
with its passage to customers through regulated revenues in the same accounting
period. We also record regulatory liabilities for refunds, or probable refunds,
to customers that have not yet been made.

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

Traditional Electricity Supply and Delivery Activities
------------------------------------------------------

We recognize revenues on the accrual or settlement basis for normal retail and
wholesale electricity supply sales and electricity transmission and distribution
delivery services. That is, we recognize and record revenues when the energy is
delivered to the customer and include estimated 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
--------------------------------------------

We recognize revenues from domestic gas pipeline and storage services when gas
is delivered to contractual meter points or when services are provided, with the
exception of certain physical forward gas purchase and sale contracts that are
derivatives and are required to be accounted for using mark-to-market accounting
(Resale Gas Contracts).

Energy Marketing and Risk Management Activities
-----------------------------------------------

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

In October 2002, EITF 02-3 precluded mark-to-market accounting for risk
management contracts that were not derivatives pursuant to SFAS 133. We
implemented this standard for all non-derivative wholesale and risk management
transactions occurring on or after October 25, 2002. For non-derivative risk
management transactions entered into prior to October 25, 2002, we implemented 
this standard on January 1, 2003 and reported the effects of implementation as 
a cumulative effect of an accounting change.

After January 1, 2003, we use mark-to-market accounting for wholesale marketing
and risk management transactions that are derivatives unless the derivative is
designated for hedge accounting or the normal purchase and sale exemption.
Revenues and expenses are recognized from wholesale marketing and risk
management transactions that are not derivatives when the commodity is
delivered.

See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.

Accounting for Derivative Instruments
-------------------------------------

For derivative contracts that are not designated as hedges or normal purchase
and sale transactions we recognize unrealized gains and losses prior to
settlement based on changes in fair value during the period in our results of
operations. When we settle mark-to-market derivative contracts and realize gains
and losses, we reverse previously recorded unrealized gains and losses from
mark-to-market valuations.

We designate certain derivative instruments as hedges of forecasted transactions
or future cash flows (cash flow hedges) or as a hedge of a recognized asset,
liability or firm commitment (fair value hedge). We report changes in the fair
value of these instruments on our balance sheet. We do not recognize changes in
the fair value of the derivative instrument designated as a hedge in the current
results of operations until earnings are impacted by the hedged item. We also
recognize any changes in the fair value of the hedging instrument that are not
offset by changes in the fair value of the hedged item immediately in earnings.

We measure the fair values of derivative instruments and hedge instruments
accounted for using mark-to-market accounting based on exchange prices and
broker quotes. If a quoted market price is not available, we estimate the fair
value based on the best information available including valuation models that
estimate future energy prices based on existing market and broker quotes, supply
and demand market data, and other assumptions. We reduce fair values by
estimated valuation adjustments for items such as discounting, liquidity and
credit quality. There are inherent risks related to the underlying assumptions
in models used to fair value open long-term derivative 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 a contract
settles. Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices are not consistent
with our approach at estimating current market consensus for forward prices in
the current period. This is particularly true for long-term contracts.

We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.

Long-Lived Assets
-----------------

Long-lived assets are evaluated periodically for impairment whenever events or
changes in circumstances indicate that the carrying amount of any such assets
may not be recoverable. If the carrying amount is not recoverable, an impairment
is recorded to the extent that the fair value of the asset is less than its book
value.

Pension Benefits
----------------

We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants 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. See "Pension Plans" in Significant Factors section
of Management's Financial Discussion and Analysis.

New Accounting Pronouncements
-----------------------------

Effective July 1, 2003, we implemented FIN 46, "Consolidation of Variable
Interest Entities." As a result of the implementation, we consolidated two
entities, Sabine Mining Company ($77.8 million) and JMG ($469.6 million), which
were previously off-balance sheet. These entities were consolidated with SWEPCo
and OPCo, respectively. There is no change in net income due to the
consolidations. In addition, we deconsolidated Cadis Partners, LLC and the
trusts which hold mandatorily redeemable trust preferred securities which were
previously reported as Minority Interest in Finance Subsidiary ($533 million)
and Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities
of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries ($321 million), respectively. As a result of the deconsolidation
these amounts are now included in Long-term Debt. In December 2003, the FASB
issued FIN 46R which replaces FIN 46.  The FASB and other accounting 
constituencies continue to interpret the application of FIN 46R.  As a result,
we are continuing to review the application of this new interpretation and
expect to adopt FIN 46R by March 31, 2004.

See Notes 1 and 2 to the consolidated financial statements for a discussion of
significant accounting policies and additional impacts of new accounting
pronouncements.

Other Matters
-------------

FERC Proposed Standard Market Design
------------------------------------

In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and operation of
wholesale electricity markets across the country. Key elements of FERC's
proposal included 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 issued a "white paper" on the proposal in April 2003, in
response to the numerous comments that the FERC received on its proposal.
Management does not know if or when the FERC will finalize a rule for SMD. Until
any potential rule is finalized, management cannot predict its effect on cash
flows and results of operations.

FERC Market Power Mitigation
----------------------------

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. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.

Seasonality
-----------

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

Non-Core Investments
--------------------

Additional market deterioration associated with our non-core wholesale
investments (all operations outside our traditional domestic regulated utility
operations), including our U.K. operations, merchant generation facilities, and
certain gas storage and pipeline assets, could have an adverse impact on future
results of operations and cash flows. Further changes in external market
conditions could lead to additional write-offs and further divestitures of our
wholesale investments, including, but not limited to, the U.K. operations,
merchant generation facilities, and our gas storage and pipeline operations. See
Note 10 for additional information regarding assets and investments currently
recorded as held for sale.

Investments Limitations
-----------------------

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,
2003, our investment in EWGs and FUCOs was $1.7 billion, including guarantees of
debt, compared to our limit of $2.1 billion.

SEC Rule 58, under the general rules and regulations of the PUHCA, permits us to
invest up to 15% of consolidated capitalization (such amount was $3.4 billion at
December 31, 2003) in energy-related companies, including marketing and/or risk
management activities in electricity, gas and other energy commodities. As of
December 31, 2003 AEP has invested $2.8 billion in these energy-related
companies.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
-------------------------------------------------------------------------

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.

We have established policies and procedures which allow us to identify, assess,
and manage market risk exposures in our day-to-day operations. Our risk policies
have been reviewed with our Board of Directors and approved by our Risk
Executive Committee. Our Chief Risk Officer administers our risk policies and
procedures. The Risk Executive Committee establishes risk limits, approves risk
policies, and assigns responsibilities regarding the oversight and management of
risk and monitors risk levels. Members of this committee receive daily, weekly,
and monthly reports regarding compliance with policies, limits and procedures.
Our committee meets monthly and consists of the Chief Risk Officer, Chief Credit
Officer, V.P. Market Risk Oversight, and senior financial and operating
managers.

We actively participate in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around risk
management contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. The CCRO adopted disclosure
standards for risk management contracts to improve clarity, understanding and
consistency of information reported. Implementation of the disclosures is
voluntary. We support the work of the CCRO and have embraced the disclosure
standards. The following tables provide information on our risk management
activities.

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

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


<TABLE>
<CAPTION>

                                                  MTM Risk Management Contract Net Assets (Liabilities)
                                                             Year Ended December 31, 2003

                                                                                  Investments       Investments
                                                                     Utility           Gas              UK
                                                                    Operations     Operations       Operations       Consolidated
                                                                    ----------     ----------       ------------     ------------
                                                                                          (in millions)                 
        <C>                                                           <C>            <C>               <C>                 <C>  
        Beginning Balance December 31, 2002                           $360           $(155)            $ 45                $250 
        (Gain) Loss from Contracts Realized/Settled
         During  the Period (a)                                       (107)            175               (9)                 59 
        Fair Value of New Contracts When Entered
         Into During the Period (b)                                      -               -                4                   4 
        Net Option Premiums Paid/(Received) (c)                          -              23              (14)                  9 
        Change in Fair Value Due to Valuation 
         Methodology Changes                                             -               1                -                   1 
        Effect of EITF 98-10 Rescission (d)                            (19)              1              (14)                (32)
        Changes in Fair Value of Risk Management
         Contracts (e)                                                  43             (40)            (134)               (131)
        Changes in Fair Value of Risk Management Contracts
        Allocated to Regulated Jurisdictions (f)                         9               -                -                   9 
        UK Generation Hedges (g)                                         -               -             (124)               (124)
                                                                      -----           -----           ------               -----
        Total MTM Risk Management Contract  Net Assets
        (Liabilities), excluding Cash  Flow Hedges                    $286               $5           $(246)                 45 
                                                                      =====           =====           ======                  

        Net Cash Flow Hedge Contracts (h)                                                                                  (134)
        Net Risk Management Liabilities Held for Sale (i)                                                                   383
                                                                                                                           ----- 
        Ending Balance December 31, 2003                                                                                   $294 
                                                                                                                           =====
</TABLE>


        (a) "(Gain) Loss from Contracts Realized/Settled During the Period" 
            includes realized gains from risk management contracts and related 
            derivatives that settled during 2003 and entered into prior to 2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value at inception of long-term
            contracts entered into with customers during 2003. 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 associated with 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 entered into in 2003.
        (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and 
            Cumulative Effect."
        (e) "Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management portfolio due to market
            fluctuations during the current period. Market fluctuations are
            attributable to various factors such as supply/demand, weather,
            storage, etc.
        (f) "Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Operations. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.
        (g) "UK Generation Hedges" represent amounts previously classified as
            hedges of forecasted U.K. power sales relating to the fourth 
            quarter of 2004 and beyond. Given the expected disposition of our 
            U.K. generation in 2004, the forecasted sales are no longer 
            probable of occurring.  Therefore, these amounts have been 
            reclassified from hedge accounting to mark-to-market accounting.
        (h) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed in detail
            within the following pages. 
        (i) See Note 10 for discussion on Assets Held for Sale.



<TABLE>
<CAPTION>

                                            Detail on MTM Risk Management Contract Net Assets (Liabilities)
                                                             As of December 31, 2003

                                                                           Investments     Investments
                                                           Utility             Gas             UK        
                                                          Operations        Operations      Operations       Consolidated
                                                          ----------       -----------     ------------      ------------
                                                                                  (in millions)
        <C>                                                  <C>              <C>             <C>              <C>    
        Current Assets                                        $323             $417            $560             $1,300 
        Non Current Assets                                     279              215             274                768
                                                             ------           ------          ------           --------
        Total Assets                                          $602             $632            $834            $ 2,068
                                                             ------           ------          ------           --------

        Current Liabilities                                  $(216)           $(403)          $(646)           $(1,265)
        Non Current Liabilities                               (100)            (224)           (434)              (758)
                                                             ------           ------          ------           --------
        Total Liabilities                                    $(316)           $(627)        $(1,080)           $(2,023)
                                                             ------           ------          ------           --------

        Total Net Assets (Liabilities),
          excluding Cash Flow Hedges                          $286               $5           $(246)               $45
                                                             ======           ======          ======           ========
</TABLE>



<TABLE>
<CAPTION>


                                                    Reconciliation of MTM Risk Management Contracts to
                                                              Consolidated Balance Sheets
                                                                 As of December 31, 2003

                                                       Risk Management      Cash Flow          Assets Held
                                                          Contracts*          Hedges             for Sale          Consolidated
                                                       ---------------      ---------          -----------         ------------
                                                                               (in millions)
        <C>                                                <C>                 <C>                <C>                 <C>  
        Current Assets                                      $1,300               $26               $(560)               $766
        Non Current Assets                                     768                 -                (274)                494
                                                           --------            ------             -------             -------
        Total Assets                                        $2,068               $26               $(834)             $1,260
                                                           --------            ------             -------             -------

        Current Liabilities                                $(1,265)            $(148)               $782               $(631)
        Non Current Liabilities                               (758)              (12)                435                (335)
                                                           --------            ------             -------             -------
        Total Liabilities                                  $(2,023)            $(160)             $1,217               $(966)
                                                           --------            ------             -------             -------

        Total Net Assets (Liabilities)                         $45             $(134)               $383                $294
                                                           ========            ======             =======             =======


        * Excluding Cash Flow Hedges.

</TABLE>



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

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

  o     The source of fair value used in determining the carrying amount of 
        our total MTM asset or liability (external sources or modeled 
        internally). 
  o     The maturity, by year, of our net assets/liabilities, giving an 
        indication of when these MTM amounts will settle and generate cash.



<TABLE>
<CAPTION>


                                                     Maturity and Source of Fair Value of MTM
                                                 Risk Management Contract Net Assets (Liabilities)
                                                  Fair Value of Contracts as of December 31, 2003

                                                                                                         After
                                              2004        2005        2006        2007       2008       2008 (c)     Total (d)
                                             ------      ------      ------      ------     ------     ---------    -----------
                                                                              (in millions)
Utility Operations:
------------------
<C>                                           <C>        <C>          <C>          <C>        <C>         <C>          <C>
Prices Actively  Quoted - Exchange Traded
 Contracts                                     $44         $(4)        $(1)         $-         $-          $-            $39 
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                78          38          29          13          6           -            164 
Prices Based on Models and Other
 Valuation Methods (b)                         (15)          7          15          19         16          41             83
                                              -----      ------       -----        ----       ----        ----         ------
Total                                         $107         $41         $43         $32        $22         $41           $286
                                              =====      ======       =====        ====       ====        ====         ======

Investments - Gas Operations:
----------------------------
Prices Actively Quoted - Exchange
 Traded Contracts                              $49         $14         $(1)         $-         $-          $-            $62 
Prices Provided by Other External 
 Sources - OTC Broker Quotes (a)               (27)          -           -           -          -           -            (27)
Prices Based on Models and Other
 Valuation Methods (b)                          (8)         (7)         (6)         (1)        (3)         (5)           (30)
                                              -----      ------       -----        ----       ----        ----         ------
Total                                          $14          $7         $(7)        $(1)       $(3)        $(5)            $5
                                              =====      ======       =====        ====       ====        ====         ======

Investments - UK Operations:
---------------------------
Prices Actively Quoted - Exchange Traded
 Contracts                                      $-          $-          $-          $-         $-          $-             $- 
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)               (60)       (101)        (46)          -          -           -           (207)
Prices Based on Models and Other
 Valuation Methods (b)                         (26)         (9)         (2)         (2)         -           -            (39)
                                              -----      ------       -----        ----       ----        ----         ------
Total                                         $(86)      $(110)       $(48)        $(2)        $-          $-          $(246)
                                              =====      ======       =====        ====       ====        ====         ======

Consolidated:
------------
Prices Actively Quoted - Exchange Traded
 Contracts                                     $93         $10         $(2)         $-         $-          $-           $101 
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                (9)        (63)        (17)         13          6           -            (70)
Prices Based on Models and Other
 Valuation Methods (b)                         (49)         (9)          7          16         13          36             14
                                              -----      ------       -----        ----       ----        ----         ------
Total                                          $35        $(62)       $(12)        $29        $19         $36            $45
                                              =====      ======       =====        ====       ====        ====         ======

</TABLE>


 (a) Prices provided by other external sources - Reflects information obtained 
     from over-the-counter brokers, industry services, or multiple-party on-line
     platforms. 
 (b) Modeled - In the absence of pricing information from external sources, 
     modeled information is derived using valuation models developed by the
     reporting entity, reflecting when appropriate, option pricing theory, 
     discounted cash flow concepts, valuation adjustments, etc. and may 
     require projection of prices for underlying commodities beyond the period 
     that prices are available from third-party sources. In addition, where 
     external pricing information or market liquidity are limited, such 
     valuations are classified as modeled.
 (c) For Utility Operations, there is mark-to-market value in excess of 10
     percent of our total mark-to-market value in individual periods beyond 
     2008. $17 million of this mark-to-market value is in 2009 and $16 million 
     of this mark-to-market value is in 2010. 
 (d) Amounts exclude Cash Flow Hedges.

The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in the preceding table varies by market. The
following table reports an estimate of the maximum tenors (contract maturities)
of the liquid portion of each energy market.


<TABLE>
<CAPTION>

                                       Maximum Tenor of the Liquid Portion of Risk Management Contracts
                                                          As of December 31, 2003
                                                                                                                         
           Domestic          Transaction Class                       Market/Region                             Tenor
           --------          -----------------                       -------------                             -----
                                                                                                            (in months) 

        <C>                 <C>                                  <C>                                             <C>
        Natural Gas         Futures                              NYMEX Henry Hub                                 72
                            Physical Forwards                    Gulf Coast, Texas                               12
                            Swaps                                Gas East - Northeast, Mid-continent
                                                                   Gulf Coast, Texas                             15
                            Swaps                                Gas West - Rocky Mountains,
                                                                   West Coast                                    15
                            Exchange Option Volitility           NYMEX/Henry Hub                                 12

        Power               Futures                              Power East - PJM                                24
                            Physical Forwards                    Power East - Cinergy                            60
                            Physical Forwards                    Power East - PJM                                48
                            Physical Forwards                    Power East - NYPP                               24
                            Physical Forwards                    Power East - NEPOOL                             12
                            Physical Forwards                    Power East - ERCOT                              24
                            Physical Forwards                    Power East - TVA                                48
                            Physical Forwards                    Power East - Com Ed                             24
                            Physical Forwards                    Power East - Entergy                            48
                            Physical Forwards                    Power West - PV,  NP15, SP15,   
                                                                  MidC, Mead                                     60
                            Peak Power Volatility     
                             (Options)                           Cinergy                                         12
                            Peak Power Volatility     
                             (Options) PJM 12

        Crude Oil           Swaps                                West Texas Intermediate                         36

        Emissions           Credits                              SO2                                             24

        Coal                Physical Forwards                    PRB,NYMEX,CSX                                   24

        International
        -------------

        Power               Forwards and Options                 United Kingdom                                  24

        Coal                Forward Purchases and Sales          United Kingdom                                  15

                            Swaps                                Europe                                          36

        Freight             Swaps                                Europe                                          24

</TABLE>


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

We are exposed to market fluctuations in energy commodity prices impacting our
power operations. We monitor these risks on our future operations and may employ
various commodity instruments such as cash flow hedges to mitigate the impact of
these fluctuations on the future cash flows from assets. We do not hedge all
commodity price risk.

We employ fair value hedges and cash flow hedges 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 forward contracts
as cash flow hedges to lock-in prices on certain transactions which have been
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations of debt
denominated in foreign currencies. We do not hedge all foreign currency
exposure.

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place (However, given that under SFAS 133 only cash flow
hedges are recorded in Accumulated Other Comprehensive Income (AOCI), the table
does not provide an all-encompassing picture of our hedging activity). The table
further indicates what portions of these hedges are expected to be reclassified
into net income in the next 12 months. The table also includes a roll-forward of
the AOCI balance sheet account, providing insight into the drivers of the
changes (new hedges placed during the period, changes in value of existing
hedges and roll off of hedges).

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


<TABLE>
<CAPTION>

                             Cash Flow Hedges included in Accumulated Other Comprehensive Income (Loss)
                                        On the Balance Sheet as of December 31, 2003
                                                                                           Portion Expected to              
                                                           Accumulated Other               be Reclassified to 
                                                          Comprehensive Income             Earnings During the
                                                          (Loss) After Tax (a)              Next 12 Months (b)
                                                          --------------------             ------------------- 
                                                                              (in millions)
        <C>                                                        <C>                           <C>             
        Power and Gas                                              $(65)                         $(58)           
        Foreign Currency                                            (20)                          (20)           
        Interest Rate                                                (9)                           (8)           
                                                                   -----                         -----
        Total                                                      $(94)                         $(86)           
                                                                   =====                         =====
</TABLE>



<TABLE>
<CAPTION>

                                   Total Accumulated Other Comprehensive Income (Loss) Activity
                                                  Year Ended December 31, 2003

                                                         Power          Foreign
                                                        and Gas         Currency    Interest Rate    Consolidated
                                                        -------         --------    -------------    ------------   
                                                                              (in millions)
        <C>                                               <C>            <C>             <C>              <C>
        Beginning Balance, December 31, 2002               $(3)           $(1)           $(12)            $(16)
        Changes in Fair Value (c)                          (64)           (19)              4              (79)
        Reclassifications from AOCI to Net Income (d)        2              -              (1)               1 
                                                          -----          -----           -----            -----
        Ending Balance,
         December 31, 2003                                $(65)          $(20)            $(9)            $(94)
                                                          =====          =====           =====            =====
</TABLE>


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

Credit Risk
-----------

We limit credit risk by assessing creditworthiness of potential counterparties
before entering into transactions with them and continue to evaluate their
creditworthiness after transactions have been initiated. Only after an entity
has met our internal credit rating criteria will we extend unsecured credit. We
use Moody's Investor Service, Standard and Poor's and qualitative and
quantitative data to independently assess the financial health of counterparties
on an ongoing basis. Our independent analysis, in conjunction with the rating
agencies' information, is used to determine appropriate risk parameters. We also
require cash deposits, letters of credit and parental/affiliate guarantees as
security from counterparties depending upon credit quality in our normal course
of business.

We have risk management contracts with numerous counterparties. Since open risk
management contracts are valued based on changes in market prices of the related
commodities, our exposures change daily. We believe that credit exposure with
any one counterparty is not material to our financial condition at December 31,
2003. At December 31, 2003, our credit exposure net of credit collateral to sub
investment grade counterparties was approximately 16%, expressed in terms of net
MTM assets and net receivables. The increase in non-investment grade credit
quality was largely due to an increase in coal and freight exposures related to
our U.K. investments. As of December 31, 2003, the following table approximates
our counterparty credit quality and exposure based on netting across commodities
and instruments:


<TABLE>
<CAPTION>

                                                                                          Number of            Net Exposure of
Counterparty                        Exposure Before        Credit          Net          Counterparties          Counterparties
Credit Quality:                    Credit Collateral     Collateral      Exposure           > 10%                    >10%
--------------                     -----------------     ----------      --------       --------------         ---------------
                                                                                                              
                                                                      (in millions)          
<C>                                     <C>                  <C>         <C>                    <C>                     <C>    
Investment Grade                          $931                $29          $902                  1                      $135   
Split Rating                                47                  -            47                  1                        40   
Non-Investment Grade                       276                136           140                  2                        71   
No External Ratings:
  Internal Investment
    Grade                                  480                  5           475                  3                       207   
  Internal Non-Investment
    Grade                                  185                 48           137                  2                        51   
                                        -------              -----       -------                ---                     -----
Total                                   $1,919               $218        $1,701                  9                      $504   
                                        =======              =====       =======                ===                     =====
</TABLE>


Generation Plant Hedging Information
------------------------------------

This table provides information on operating measures regarding the proportion
of output of our generation facilities (based on economic availability
projections) economically hedged. This information is forward-looking and
provided on a prospective basis through December 31, 2006. Please note that this
table is a point-in-time estimate, subject to changes in market conditions and
our decisions on how to manage operations and risk. "Estimated Plant Output
Hedged," represents the portion of megawatt hours of future
generation/production for which we have sales commitments or estimated
requirement obligations to customers.

                         Generation Plant Hedging Information
                              Estimated Next Three Years
                               As of December 31, 2003

                                              2004       2005        2006
                                              ----       ----        ----
Estimated Plant Output Hedged                  90%        92%         92%


VaR Associated with Risk Management Contracts
---------------------------------------------

We use a risk measurement model, which calculates Value at Risk (VaR) to measure
our commodity price risk in the risk management portfolio. The VaR is based on
the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes a 95% confidence level and a one-day
holding period. Based on this VaR analysis, at December 31, 2003, a near term
typical change in commodity prices is not expected to have a material effect on
our results of operations, cash flows or financial condition.


The following table shows the end, high, average, and low market risk as
measured by VaR year-to-date:

                                    VaR Model

              December 31, 2003                  December 31, 2002    
         --------------------------           ------------------------
                (in millions)                      (in millions)
         End  High  Average  Low              End  High  Average  Low
         ---  ----  -------  ---              ---  ----  -------  ---

         $11   $19   $ 7     $4               $5    $24    $12    $4

The high VaR for 2003 occurred in late February 2003 during a period when
natural gas and power prices experienced high levels and extreme volatility.
Within a few days, the VaR returned to levels more representative of the average
VaR for the year.

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

<TABLE>
<CAPTION>
           
                                                                   CCRO VaR Metrics

                                                             Average for
                                                             Year-to-Date        High for               Low for
                                       December 31,  2003       2003         Year-to-Date  2003      Year-to-Date 2003
                                       ------------------    ------------    ------------------      -----------------
                                                                      (in millions)                          
<C>                                           <C>                 <C>                <C>                    <C>        
95% Confidence Level, Ten-Day 
  Holding Period                              $41                 $27                $71                    $16            

99% Confidence Level, One-Day
  Holding Period                              $17                 $11                $30                     $7            

</TABLE>


We utilize a VaR model to measure interest rate market risk exposure. The
interest rate VaR model is based on a Monte Carlo simulation with a 95%
confidence level and a one-year holding period. The volatilities and
correlations were based on three years of daily prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $1.013 billion at
December 31, 2003 and $527 million at December 31, 2002. We would not expect to
liquidate our entire debt portfolio in a one-year holding period, therefore a
near term change in interest rates should not materially affect our results of
operations or consolidated financial position.

We are 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 West
Virginia. To the extent the fuel supply of the generating units in these states
is not under fixed price long-term contracts we are subject to market price
risk. We continue to be protected against market price changes by active fuel
clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of
Texas. Fuel clauses are active again in Michigan and Texas, effective January 1,
2004 and March 1, 2004, respectively.

We employ risk management contracts including physical forward purchase and sale
contracts, exchange futures and options, over-the-counter options, swaps, and
other derivative contracts to offset price risk where appropriate. We engage in
risk management of electricity, gas and to a lesser degree other commodities,
principally coal and freight. As a result, we are subject to price risk. The
amount of risk taken is controlled by risk management operations and our Chief
Risk Officer and his staff. When risk management activities exceed certain
pre-determined limits, the positions are modified or hedged to reduce the risk
to be within the limits unless specifically approved by the Risk Executive
Committee.



<PAGE>

<TABLE>
<CAPTION>


                                     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                CONSOLIDATED STATEMENTS OF OPERATIONS
                                         For the Years Ended December 31, 2003, 2002 and 2001
                                                (in millions, except per-share amounts)

                                                                                2003              2002              2001
                                                                                ----              ----              ----
                           REVENUES
--------------------------------------------------------------
<C>                                                                           <C>                <C>               <C>      
Utility Operations                                                            $10,871            $10,446           $10,546  
Gas Operations                                                                  3,097              2,071             1,797  
Other                                                                             577                791               410
                                                                              --------           --------          --------
TOTAL                                                                          14,545             13,308            12,753
                                                                              --------           --------          --------
                           EXPENSES
--------------------------------------------------------------
Fuel for Electric Generation                                                    3,053              2,577             3,225  
Purchased Electricity for Resale                                                  707                532               296  
Purchased Gas for Resale                                                        2,850              1,946             1,443  
Maintenance and Other Operation                                                 3,673              4,065             3,666  
Asset Impairments and Other Related Charges                                       650                318                 -   
Depreciation and Amortization                                                   1,299              1,348             1,233  
Taxes Other Than Income Taxes                                                     681                718               667
                                                                              --------           --------          --------
TOTAL                                                                          12,913             11,504            10,530
                                                                              --------           --------          --------

OPERATING INCOME                                                                1,632              1,804             2,223
                                                                              --------           --------          --------

Other Income                                                                      387                461               371
                                                                              --------           --------          --------

                  INTEREST AND OTHER CHARGES
--------------------------------------------------------------
Investment Value Losses                                                            70                321                 -   
Other Expenses                                                                    227                323               225  
Interest                                                                          814                775               833  
Preferred Stock Dividend Requirements of Subsidiaries                               9                 11                10  
Minority Interest in Finance Subsidiary                                            19                 35                13
                                                                              --------           --------          --------
TOTAL                                                                           1,139              1,465             1,081
                                                                              --------           --------          --------

INCOME BEFORE INCOME TAXES                                                        880                800             1,513  
Income Taxes                                                                      358                315               553
                                                                              --------           --------          --------
INCOME BEFORE DISCONTINUED OPERATIONS, EXTRAORDINARY ITEMS AND
CUMULATIVE EFFECT                                                                 522                485               960  

DISCONTINUED OPERATIONS (Net of Tax)                                             (605)              (654)               41  
EXTRAORDINARY LOSS (Net of Tax)                                                     -                  -               (48) 

    CUMULATIVE EFFECT OF ACCOUNTING CHANGES (Net of Tax)
--------------------------------------------------------------

Goodwill and Other Intangible Assets                                                -               (350)               18  
Accounting for Risk Management Contracts                                          (49)                 -                 -
Asset Retirement Obligations                                                      242                  -                 -
                                                                              --------           --------          --------
NET INCOME (LOSS)                                                                $110              $(519)             $971
                                                                              --------           --------          --------

AVERAGE NUMBER OF SHARES OUTSTANDING                                              385                332               322
                                                                              --------           --------          --------

                 EARNINGS (LOSS) PER SHARE
--------------------------------------------------------------
Income Before Discontinued Operations, Extraordinary Items and
  Cumulative Effect of Accounting Changes                                       $1.35              $1.46             $2.98   
Discontinued Operations                                                         (1.57)             (1.97)             0.13   
Extraordinary Loss                                                                  -                  -             (0.16)  
Cumulative Effect of Accounting Changes                                          0.51              (1.06)             0.06
                                                                              --------           --------          --------
TOTAL EARNINGS PER SHARE (BASIC AND DILUTIVE)                                   $0.29             $(1.57)            $3.01
                                                                              --------           --------          --------

CASH DIVIDENDS PAID PER SHARE                                                   $1.65              $2.40             $2.40
                                                                              --------           --------          --------


See Notes to Consolidated Financial Statements.

</TABLE>


<PAGE>

<TABLE>
<CAPTION>

                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                    CONSOLIDATED BALANCE SHEETS
                                                              ASSETS
                                                    December 31, 2003 and 2002

                                                                                            2003                   2002         
                                                                                            ----                   ----  
                                                                                                    (in millions)

                            CURRENT  ASSETS
---------------------------------------------------------------------------
<C>                                                                                       <C>                    <C>   
Cash and Cash Equivalents                                                                  $1,182                 $1,199
Accounts Receivable:
  Customers                                                                                 1,155                  1,553
  Accrued Unbilled Revenues                                                                   596                    551
  Miscellaneous                                                                                83                     93
  Allowance for Uncollectible Accounts                                                       (124)                  (108)
                                                                                          --------               --------
    Total Receivables                                                                       1,710                  2,089
                                                                                          --------               --------
Fuel, Materials and Supplies                                                                  991                    938
Risk Management Assets                                                                        766                    850
Margin Deposits                                                                               119                    110
Other                                                                                         129                    132
                                                                                          --------               --------
TOTAL                                                                                       4,897                  5,318
                                                                                          --------               --------

                      PROPERTY, PLANT AND EQUIPMENT
---------------------------------------------------------------------------
Electric:
   Production                                                                              15,112                 13,678
   Transmission                                                                             6,130                  5,866
   Distribution                                                                             9,902                  9,573
Other (including gas, coal mining and nuclear fuel)                                         3,584                  3,656
Construction Work in Progress                                                               1,305                  1,354
                                                                                          --------               --------
TOTAL                                                                                      36,033                 34,127
Less: Accumulated Depreciation and Amortization                                            14,004                 13,539
                                                                                          --------               --------
TOTAL-NET                                                                                  22,029                 20,588
                                                                                          --------               --------

                        OTHER NON-CURRENT ASSETS
---------------------------------------------------------------------------
Regulatory Assets                                                                           3,548                  2,688 
Securitized Transition Assets                                                                 689                    735 
Spent Nuclear Fuel and Decommissioning Trusts                                                 982                    871
Investments in Power and Distribution Projects                                                212                    283 
Goodwill                                                                                       78                    241 
Long-term Risk Management Assets                                                              494                    758 
Other                                                                                         733                    792
                                                                                          --------               --------
TOTAL                                                                                       6,736                  6,368
                                                                                          --------               --------

Assets Held for Sale                                                                        3,082                  3,601 
Assets of Discontinued Operations                                                               -                     15

TOTAL ASSETS                                                                              $36,744                $35,890
                                                                                          ========               ========

            
See Notes to Consolidated Financial Statements.
</TABLE>




<PAGE>

<TABLE>
<CAPTION>



                                      AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                     CONSOLIDATED BALANCE SHEETS
                                                 LIABILITIES AND SHAREHOLDERS' EQUITY
                                                     December 31, 2003 and 2002

                                                                                            2003                 2002       
                                                                                            ----                 ---- 
                                                                                                  (in millions)                     

                            CURRENT LIABILITIES
---------------------------------------------------------------------------
<C>                                                                                       <C>                    <C>   
Accounts Payable                                                                           $1,337                 $1,892
Short-term Debt                                                                               326                  2,739
Long-term Debt Due Within One Year*                                                         1,779                  1,327
Risk Management Liabilities                                                                   631                    961
Accrued Taxes                                                                                 620                    556
Accrued Interest                                                                              207                    181
Customer Deposits                                                                             379                    186
Other                                                                                         703                    814
                                                                                          --------               --------
TOTAL                                                                                       5,982                  8,656
                                                                                          --------               --------

                          NON-CURRENT LIABILITIES
---------------------------------------------------------------------------
Long-term Debt*                                                                            12,322                  8,863
Long-term Risk Management Liabilities                                                         335                    435
Deferred Income Taxes                                                                       3,957                  3,916
Regulatory Liabilities and Deferred Investment Tax Credits                                  2,259                    939
Asset Retirement Obligations and Nuclear Decommissioning Trusts                               651                    638
Employee Benefits and Pension Obligations                                                     667                    987
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                   176                    185
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption                    76                      -      
Deferred Credits and Other                                                                    508                  1,691
                                                                                          --------               --------
TOTAL                                                                                      20,951                 17,654
                                                                                          --------               --------

Liabilities Held for Sale                                                                   1,876                  1,279
Liabilities of Discontinued Operations                                                          -                     12
 
TOTAL LIABILITIES                                                                          28,809                 27,601
                                                                                          --------               --------

Cumulative Preferred Stocks of Subsidiaries not Subject to Mandatory Redemption                61                      - 
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
 Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such                                                
 Subsidiaries                                                                                   -                    321
Minority Interest in Finance Subsidiary                                                         -                    759   
Cumulative Preferred Stocks of Subsidiaries                                                     -                    145  

Commitments and Contingencies

                        COMMON SHAREHOLDERS' EQUITY
---------------------------------------------------------------------------
Common Stock-Par Value $6.50:
                                         2003              2002
                                         ----              ----
Shares Authorized. . . . . . . . . . .600,000,000       600,000,000
Shares Issued. . . . . . . . . . . . .404,016,413       347,835,212
(8,999,992 shares were held in treasury at December 31, 2003 and 2002)                      2,626                  2,261
Paid-in Capital                                                                             4,184                  3,413
Retained Earnings                                                                           1,490                  1,999  
Accumulated Other Comprehensive Income (Loss)                                                (426)                  (609)
                                                                                          --------               --------
TOTAL                                                                                       7,874                  7,064
                                                                                          --------               --------

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                                                $36,744                $35,890
                                                                                          ========               ========

* See Accompanying Schedules

See Notes to Consolidated Financial Statements.
</TABLE>



<PAGE>

<TABLE>
<CAPTION>


                                     AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                    CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             For the Years Ended December 31, 2003, 2002 and 2001

                                                                                            2003            2002           2001
                                                                                            ----            ----           ----
                                                                                                        (in millions) 
                       OPERATING ACTIVITIES
---------------------------------------------------------------------------
<C>                                                                                        <C>             <C>           <C>  
Net Income (Loss)                                                                            $110           $(519)         $971 
Plus:  Discontinued Operations                                                                605             654           (41)
                                                                                           -------         -------       -------
Income from Continuing Operations                                                             715             135           930 
Adjustments for Noncash Items:
    Depreciation and Amortization                                                           1,299           1,375         1,267 
    Deferred Income Taxes                                                                     163              63           151 
    Deferred Investment Tax Credits                                                           (33)            (31)          (29)
    Pension and Postemployment Benefits Reserves                                              (74)             39          (234)
    Cumulative Effect of Accounting Changes                                                  (193)            350           (18)
    Asset and Investment Value Impairments and Other Related Charges                          720             639             -
    Extraordinary Loss                                                                          -               -            48
    Amortization of Deferred Property Taxes                                                    (2)            (16)           43 
    Amortization of Cook Plant Restart Costs                                                   40              40            40 
    Mark to Market of Risk Management Contracts                                              (122)            275          (294)
Changes in Certain Current Assets and Liabilities:
    Accounts Receivable, net                                                                  363            (238)        1,769
    Fuel, Materials and Supplies                                                              (71)           (102)          (82)
    Accounts Payable                                                                         (632)            (21)         (469)
    Taxes Accrued                                                                              87            (222)         (150)
Over/Under Fuel Recovery                                                                      138              13           340 
Change in Other Assets                                                                       (162)            (78)         (171)
Change in Other Liabilities                                                                    72            (154)         (323)
                                                                                           -------         -------       -------
Net Cash Flows From Operating Activities                                                    2,308           2,067         2,818
                                                                                           -------         -------       -------

                       INVESTING ACTIVITIES
---------------------------------------------------------------------------
Construction Expenditures                                                                  (1,358)         (1,685)       (1,646)
Business Acquisitions                                                                           -               -        (1,269)
Investment in Discontinued Operations, net                                                   (615)              -          (983)
Proceeds from Sale of Assets                                                                   82           1,263           648 
Other                                                                                           3              44           (42)
                                                                                     
                                                                                           -------         -------       -------
Net Cash Flows Used For Investing Activities                                               (1,888)           (378)       (3,292)
                                                                                           -------         -------       -------

                        FINANCING ACTIVITIES
---------------------------------------------------------------------------
Issuance of Common Stock                                                                    1,142             656            11 
Issuance of Long-term Debt                                                                  4,761           2,893         2,787 
Issuance of Minority Interest                                                                   -               -           744
Issuance of Equity Unit Senior Notes                                                            -             334             - 
Change in Short-term Debt, net                                                             (2,781)         (1,248)         (778)
Retirement of Long-term Debt                                                               (2,707)         (2,513)       (1,549)
Retirement of Preferred Stock                                                                  (9)            (10)           (5)
Retirement of Minority Interest                                                              (225)              -             - 
Dividends Paid on Common Stock                                                               (618)           (793)         (773)
                                                                                           -------         -------       -------
Net Cash Flows From (Used For) Financing Activities                                          (437)           (681)          437
                                                                                           -------         -------       -------

Effect of Exchange Rate Change on Cash                                                          -              (3)           (1)
                                                                                           -------         -------       -------

Net Increase (Decrease) in Cash and Cash Equivalents                                          (17)          1,005           (38)
Cash and Cash Equivalents at Beginning of Period                                            1,199             194           232
                                                                                           -------         -------       -------
Cash and Cash Equivalents at End of Period                                                 $1,182          $1,199          $194
                                                                                           =======         =======       =======

Net Increase (Decrease) in Cash and Cash Equivalents from Discontinued Operations            $(10)          $(116)          $29  
Cash and Cash Equivalents from Discontinued Operations - Beginning of Period                   23             139           110
                                                                                           -------         -------       -------
Cash and Cash Equivalents from Discontinued Operations - End of Period                        $13             $23          $139
                                                                                           =======         =======       =======

See Notes to Consolidated Financial Statements.
</TABLE>




<PAGE>

<TABLE>
<CAPTION>


                                         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                           CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND
                                                         COMPREHENSIVE INCOME (LOSS)
                                                               (in millions)
                                                                                                           Accumulated   
                                                                                                              Other
                                                                Common Stock       Paid-in     Retained   Comprehensive
                                                              Shares    Amount     Capital     Earnings   Income (Loss)  Total
                                                              ------    ------     -------     --------   -------------  -----
<C>                                                            <C>      <C>         <C>         <C>          <C>         <C>    
DECEMBER 31, 2000                                               331     $2,152      $2,915      $3,090       $(103)      $8,054 

Issuance of Common Stock                                                     1           9                                   10 
Common Stock Dividends                                                                            (773)                    (773)
Other                                                                                  (18)         8                       (10)
                                                                                                                         -------
TOTAL                                                                                                                     7,281
                                                                                                                         -------

           COMPREHENSIVE INCOME (LOSS)
------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
     Foreign Currency Translation Adjustments                                                                  (14)         (14)
     Unrealized Losses on Cash Flow Hedges                                                                      (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 
 
Issuance of Common Stock                                         17        108         568                                  676 
Common Stock Dividends                                                                            (793)                    (793)
Common Stock Expense                                                                   (30)                                 (30)
Other                                                                                  (31)         15                      (16)
                                                                                                                         -------
TOTAL                                                                                                                     8,066
                                                                                                                         -------

           COMPREHENSIVE INCOME (LOSS)
------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
     Foreign Currency Translation Adjustments                                                                  117          117 
     Unrealized Losses on Cash Flow Hedges                                                                     (13)         (13)
     Unrealized Losses on Securities Available for Sale                                                         (2)          (2)
     Minimum Pension Liability                                                                                (585)        (585)
NET LOSS                                                                                          (519)                    (519)
                                                                                                                         -------
TOTAL COMPREHENSIVE INCOME (LOSS)                                                                                        (1,002)
                                                               -----    -------     -------     -------      ------      -------
DECEMBER 31, 2002                                               348     $2,261      $3,413      $1,999       $(609)      $7,064 

Issuance of Common Stock                                         56        365         812                                1,177 
Common Stock Dividends                                                                            (618)                    (618)
Common Stock Expense                                                                   (35)                                 (35)
Other                                                                                   (6)         (1)                      (7)
                                                                                                                         -------
TOTAL                                                                                                                     7,581
                                                                                                                         -------

           COMPREHENSIVE INCOME (LOSS)
------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
      Foreign Currency Translation Adjustments                                                                 106          106 
      Unrealized Losses on Cash Flow Hedges                                                                    (78)         (78)
      Unrealized Gains on Securities Available for Sale                                                          1            1 
      Minimum Pension Liability                                                                                154          154 
NET INCOME                                                                                         110                      110
                                                                                                                         -------
TOTAL COMPREHENSIVE INCOME                                                                                                  293
                                                               -----    -------     -------     -------      ------      -------
DECEMBER 31, 2003                                               404     $2,626      $4,184      $1,490       $(426)      $7,874
                                                               =====    =======     =======     =======      ======      =======


See Notes to Consolidated Financial Statements.
</TABLE>



<PAGE>

<TABLE>
<CAPTION>


                                       AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                    SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
                                                          December 31, 2003 and 2002


                                                                            December 31, 2003           
                                            --------------------------------------------------------------------------------  
                                                  Call                 Shares                Shares                Amount
                                            Price Per Share(a)      Authorized(b)         Outstanding(d)       (in millions)
                                            ------------------      -------------         --------------       -------------
<C>                                            <C>                   <C>                      <C>                    <C>
Not Subject to Mandatory  Redemption:
  4.00% - 5.00%                                $102-$110             1,525,903                607,940                 $61      
                                                                                                                     ----

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                                 $100             1,950,000                278,100                  28      
  6.25% - 6.875% (c)                                $100             1,650,000                482,450                  48      
                                                                                                                     ----
Total Subject to Mandatory
 Redemption (c)                                                                                                        76      
                                                                                                                     ----

Total Preferred Stock                                                                                                $137 (e) 
                                                                                                                     ====
</TABLE>


<TABLE>
<CAPTION>

                                                                            December 31, 2002     
                                            -------------------------------------------------------------------------------- 
                                                  Call                 Shares                Shares                Amount
                                            Price Per Share(a)      Authorized(b)         Outstanding(d)       (in millions)
                                            ------------------      -------------         --------------       -------------
<C>                                            <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)                                 $100             1,950,000                333,100                  33      
  6.02% - 6.875% (c)                                $100             1,650,000                513,450                  51      
                                                                                                                     ----
Total Subject to Mandatory
 Redemption (c)                                                                                                        84      
                                                                                                                     ----

Total Preferred Stock                                                                                                $145      
                                                                                                                     ====
</TABLE>


 (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, 2003, the subsidiaries had 13,780,352  shares of 
        $100 par value preferred stock, 22,200,000 shares of $25 par value 
        preferred stock and 7,768,561 shares of no par value preferred stock 
        that were authorized but unissued.
 (c)    Shares outstanding and related amounts are stated net of applicable
        retirements through sinking funds (generally at par) and reacquisitions
        of shares in anticipation of future requirements. The subsidiaries
        reacquired enough shares in 1997 to meet all sinking fund requirements
        on certain series until 2008 and on certain series until 2009 when all
        remaining outstanding shares must be redeemed.
 (d)    The number of shares of preferred stock redeemed is 86,210 shares in 
        2003, 106,458 shares in 2002 and 50,000 shares in 2001.
 (e)    Due to the implementation of SFAS 150 in July 2003, Cumulative Preferred
        Stocks of Subsidiaries is no longer presented as one line item on the
        balance sheet. SFAS 150 has required us to present Cumulative Preferred
        Stocks of Subsidiaries Subject to Mandatory Redemption as a liability.
        Cumulative Preferred Stocks of Subsidiaries Not Subject to Mandatory
        Redemption will continue to be reported on the balance sheet in the
        "mezzanine" section.


<PAGE>

<TABLE>
<CAPTION>


                                         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                    SCHEDULE OF CONSOLIDATED LONG-TERM DEBT
                                                          December 31, 2003 and 2002

                                                     Weighted Average
Maturity                                               Interest Rate        Interest Rates at December 31,          December 31, 
--------                                             -----------------      ------------------------------       ----------------
                                                     December 31, 2003         2003               2002           2003        2002
                                                     -----------------         ----               ----           ----        ----
                                                                                                                   (in millions)
<C>                                                       <C>             <C>                 <C>             <C>          <C>
FIRST MORTGAGE BONDS (a)
  2003-2004                                               7.40%            6.125%-7.85%        6.00%-7.85%       $231        $648
  2005-2008                                               6.90%             6.20%-8.00%        6.20%-8.00%        463         463
  2022-2025                                               7.28%            6.875%-8.00%       6.875%-8.70%        246         773

INSTALLMENT PURCHASE CONTRACTS (b)(f)
2003-2009                                                 3.74%            2.15%-6.90%         3.75%-7.70%        395         396
2011-2030                                                 4.92%            1.10%-8.20%         1.35%-8.20%      1,631       1,284

NOTES PAYABLE (c)(f)
2003-2017                                                 5.20%            1.537%-15.45%      6.225%-9.60%      1,518         214

SENIOR UNSECURED NOTES
2003-2005                                                 5.10%             2.43%-7.45%        2.12%-7.45%      1,359       1,834
2006-2015                                                 5.49%             3.60%-6.91%        4.31%-6.91%      4,873       2,295
2032-2038                                                 6.41%            5.625%-7.375%       6.00%-7.375%     1,765         690

JUNIOR DEBENTURES
2025-2038                                                    -                   -             7.60%-8.72%          -         205

SECURITIZATION BONDS
2005-2016                                                 5.53%            3.54%-6.25%         3.54%-6.25%        746         797

NOTES PAYABLE TO TRUST (d)

2037-2043                                                 7.06%             5.25-8.00%              -             331           -

EQUITY UNIT SENIOR NOTES (e)
2007                                                      5.75%               5.75%               5.75%           345         345

OTHER LONG-TERM DEBT (g)                                                                                          247         247

Equity Unit Contract Adjustment Payments                                                                           19          31
Unamortized Discount (net)                                                                                        (68)        (32)
                                                                                                              --------     -------
Total Long-term Debt Outstanding                                                                               14,101      10,190 
Less Portion Due Within One Year                                                                                1,779       1,327
                                                                                                              --------     -------
Long-term Portion                                                                                             $12,322      $8,863
                                                                                                              ========     =======

</TABLE>


(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)   Notes Payable to Trust is a result of a deconsolidation of TCC, PSO and 
      SWEPCo's trusts effective July 1, 2003 due to the implementation of FIN
      46.  See Notes 2 and 17 for further information.
(e)   In May 2005, the interest rate on these Equity Unit Senior Notes can be 
      reset through a remarketing.
(f)   Installment Purchase Contracts and Notes Payable include $257 million and
      $185 million, respectively, due to the implementation of FIN 46 (see Note 
      2).  Notes Payable includes $496 million of a merchant power generation 
      facility which was consolidated as of December 31, 2003 (see Notes 10 and
      16). 
(g)   Other long-term debt consists of a liability along with accrued interest 
      for disposal of spent nuclear fuel (see Note 7) and a financing obligation
      under a sale and leaseback agreement.



<TABLE>
<CAPTION>

LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2003 IS PAYABLE AS FOLLOWS:
----------------------------------------------------------------------

                                             2004        2005        2006         2007        2008    Later Years         TOTAL
                                             ----        ----        ----         ----        ----    -----------         -----
                                                                             (in millions)
<C>                                        <C>         <C>         <C>          <C>           <C>         <C>           <C>     
Principal Amount                           $1,779      $1,273      $2,187       $1,124        $587        $7,200        $14,150 
Equity Unit Contract Adjustment Payments                                                                                     19 
Unamortized Discount                                                                                                        (68)
                                                                                                                        --------
                                                                                                                        $14,101
                                                                                                                        ========
</TABLE>



<PAGE>


             AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES
               INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
             ------------------------------------------------------


           1. Organization and Summary of Significant Accounting Policies

           2. New Accounting Pronouncements, Extraordinary Items and Cumulative
              Effect of Accounting Changes

           3. Goodwill and Other Intangible Assets

           4. Rate Matters

           5. Effects of Regulation

           6. Customer Choice and Industry Restructuring

           7. Commitments and Contingencies

           8. Guarantees

           9. Sustained Earnings Improvement Initiative

          10. Acquisitions, Dispositions, Discontinued Operations, Impairments,
              Assets Held for Sale and Assets Held and Used

          11. Benefit Plans

          12. Stock-Based Compensation

          13. Business Segments

          14. Derivatives, Hedging and Financial Instruments

          15. Income Taxes

          16. Leases

          17. Financing Activities

          18. Unaudited Quarterly Financial Information

          19. Subsequent Events (Unaudited)



<PAGE>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
         --------------------------------------------------------------


1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
---------------------------------------------------------------


ORGANIZATION
------------

Our principal business conducted by our eleven domestic electric utility
operating companies is the generation, transmission and distribution of electric
power. These companies are subject to regulation by the FERC under the Federal
Power Act and maintain accounts in accordance with FERC and other regulatory
guidelines. These companies are subject to further regulation with regard to
rates and other matters by state regulatory commissions.

We also engage in wholesale electricity, natural gas and other commodity
marketing and risk management activities in the United States and Europe. In
addition, our domestic operations include non-regulated independent power and
cogeneration facilities, coal mining and intra-state natural gas operations in
Louisiana and Texas.

International operations include the generation and supply of power in the
United Kingdom, and to a lesser extent in Mexico, Australia and China. These
operations are either wholly-owned or partially-owned by our various
subsidiaries.

We also conduct domestic barging operations, provide various energy related
services and furnish communications-related services domestically.

During 2003 we announced plans to significantly restructure and dispose of many
of our non-regulated operations. See Note 10 for a discussion of the impacts of
these plans on our organization.

Certain previously reported amounts have been reclassified to conform to current
classifications with no effect on net income or shareholders' equity.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------

Rate Regulation
---------------

We are 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 and Mexico are regulated by 
the authorities of those countries and are generally subject to price controls.

Principles of Consolidation
---------------------------

Our consolidated financial statements include AEP and its wholly-owned and
majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or
substantially controlled variable interest entities. Intercompany items are
eliminated in consolidation. Equity investments not substantially controlled
that are 50% or less owned are accounted for using the equity method of
accounting; equity earnings are included in Other Income. We also have
generating units that are jointly owned with unaffiliated companies. The
proportionate share of the operating costs associated with such facilities is
included in our Consolidated Statements of Operations and the investments are
reflected in our Consolidated Balance Sheets.

Accounting for the Effects of Cost-Based Regulation
---------------------------------------------------

As the owner of cost-based rate-regulated electric public utility companies, our
consolidated financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time periods than
enterprises that are not rate-regulated. 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. We discontinued the application of SFAS 71
for the generation portion of our business as follows: in Ohio by OPCo and CSPCo
in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas
by TCC, TNC, and SWEPCo in September 1999, in Arkansas by SWEPCo in September
1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo
reapplied SFAS 71 for West Virginia and SWEPCo reapplied SFAS 71 for Arkansas.

Use of Estimates
----------------

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

Property, Plant and Equipment
-----------------------------

Domestic electric utility property, plant and equipment are stated at original
purchase cost. Property, plant and equipment of the non-regulated operations and
other investments are stated at their fair market value at acquisition (or as
adjusted for any applicable impairments) plus the original cost of property
acquired or constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and associated
removal costs, net of salvage, are deducted from accumulated depreciation. For
non-regulated operations, retirements from the plant accounts and associated
salvage are deducted from accumulated depreciation and removal costs are charged
to expense. The costs of labor, materials and overhead incurred to operate and
maintain plant are included in operating expenses. Assets are tested for
impairment as required under SFAS 144 (see Note 10).

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

AFUDC represents the estimated cost of borrowed and equity funds used to finance
construction projects that is capitalized and recovered through depreciation
over the service life of domestic regulated electric utility plant. For
non-regulated operations, interest is capitalized during construction in
accordance with SFAS 34, "Capitalization of Interest Costs." Capitalized
interest is also recorded for domestic generating assets in Ohio, Texas and
Virginia, effective with the discontinuance of SFAS 71 regulatory accounting.
The amounts of AFUDC and interest capitalized were not material in 2003, 2002
and 2001.

Depreciation, Depletion and Amortization
----------------------------------------

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


<TABLE>
<CAPTION>

Functional Class of Property                                    Annual Composite Depreciation Rates Ranges
----------------------------                          ----------------------------------------------------------
                                                           2003                  2002                   2001        
                                                      --------------         -------------         -------------
<C>                                                    <C>                   <C>                   <C>  
Production:
  Steam-Nuclear                                        2.5% to  3.4%         2.5% to  3.4%         2.5% to  3.4% 
  Steam-Fossil-Fired                                   2.3% to  4.6%         2.6% to  4.5%         2.5% to  4.5% 
  Hydroelectric-Conventional
   and Pumped Storage                                  1.9% to  3.4%         1.9% to  3.4%         1.9% to  3.4% 
Transmission                                           1.7% to  2.8%         1.7% to  3.0%         1.7% to  3.1% 
Distribution                                           3.3% to  4.2%         3.3% to  4.2%         2.7% to  4.2% 
Other                                                  1.8% to 16.7%         1.8% to  9.9%         1.8% to 15.0%

</TABLE>


We provide for depreciation, depletion and amortization of coal-mining assets
over each asset's estimated useful life or the estimated life of each mine,
whichever is shorter, using the straight-line method for mining structures and
equipment. We use either the straight-line method or the units-of-production
method to amortize mine development costs and deplete coal rights based on
estimated recoverable tonnages. We include these costs in the cost of coal
charged to fuel expense. Average amortization rates for coal rights and mine
development costs were $0.25 per ton in 2003, $0.32 per ton in 2002 and $2.06
per ton in 2001. In 2002, certain coal-mining assets were impaired by $60
million leading to the decline in amortization rates in 2003. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia leading to the decline in
amortization rates in 2002.

Valuation of Non-Derivative Financial Instruments
-------------------------------------------------

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.

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. During 2003 a fair value hedging strategy was implemented for certain
non-trading gas and coal inventory. Changes in the fair value of hedged
inventory are recorded to the extent offsetting hedges are designated against
that inventory.

Accounts Receivable
-------------------

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

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

AEP Credit, Inc. factors accounts receivable for certain registrant
subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and
a portion of APCo. Since APCo does not have regulatory authority to sell
accounts receivable in all of its regulatory jurisdictions, only a portion of
APCo's accounts receivable are sold to AEP Credit. AEP Credit has a sale of
receivables agreement with banks and commercial paper conduits. Under the sale
of receivables agreement, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140,
allowing the receivables to be taken off of the company's balance sheet. See
Note 17 "Financing Activities" for further details.

Foreign Currency Translation
----------------------------

The financial statements of subsidiaries outside the U.S. which are included in
our 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." Although the effects of foreign currency
fluctuations are mitigated by the fact that expenses of foreign subsidiaries are
generally incurred in the same currencies in which sales are generated, the
reported results of operations of our foreign subsidiaries are affected by
changes in foreign currency exchange rates and, as compared to prior periods,
will be higher or lower depending upon a weakening or strengthening of the U.S.
dollar. Revenues and expenses are translated at monthly average foreign currency
exchange rates throughout the year. Assets and liabilities are translated into
U.S. dollars at year-end foreign currency exchange rates. Accordingly, our
consolidated common shareholders' equity will fluctuate depending on the
relative strengthening or weakening of the U.S. dollar versus relevant foreign
currencies. Currency translation gain and loss adjustments are recorded in
shareholders' equity as Accumulated Other Comprehensive Income (Loss). The
impact of the changes in exchange rates on cash, resulting from the translation
of items at different exchange rates, is shown on our Consolidated Statements of
Cash Flows in Effect of Exchange Rate Change on Cash. Actual currency
transaction gains and losses are recorded in income when they occur.

Deferred Fuel Costs
-------------------

The cost of fuel consumed is charged to expense when the fuel is burned. Where
applicable under governing state regulatory commission retail rate orders, fuel
cost over-recoveries (the excess of fuel revenues billed to ratepayers over fuel
costs incurred) are deferred as regulatory liabilities and under-recoveries (the
excess of fuel costs incurred over fuel revenues billed to ratepayers) are
deferred as regulatory assets. These deferrals are amortized when refunded or
billed to customers in later months with the regulator's review and approval.
The amounts of an over-recovery or under-recovery can also be affected by
actions of regulators. When these actions become probable we adjust our
deferrals to recognize these probable outcomes. The amount of under-recovered
fuel costs deferred under fuel clauses as a regulatory asset was $51 million at
December 31, 2003 and $148 million at December 31, 2002. The amount of
over-recovered fuel costs deferred under fuel clauses as a regulatory liability
was $132 million at December 31, 2003 and $90 million at December 31, 2002. See
Note 5 "Effects of Regulation" for further information.

In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas,
Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are
timely reflected in rates through the fuel cost adjustment clauses in place in
those states. 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 have also
impacted earnings. The Michigan fuel clause suspension ended December 31, 2003,
and the Indiana freeze is scheduled to end on March 1, 2004. Changes in fuel
costs also impact earnings for certain of our Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 4, "Rate Matters" and Note 6, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.

Revenue Recognition
-------------------

Regulatory Accounting
---------------------

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

When regulatory assets are probable of recovery through regulated rates, we
record them as assets on the balance sheet. We test for probability of recovery
whenever new events occur, for example, issuance of a regulatory commission
order or passage of new legislation. If it is determined that recovery of a
regulatory asset is no longer probable, we write off that regulatory asset as a
charge against earnings. A write-off of regulatory assets 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, with the
exception of certain physical forward gas purchase and sale contracts that are
derivatives and that are accounted for using mark-to-market accounting (Resale
Gas Contracts).

Energy Marketing and Risk Management Activities
-----------------------------------------------

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

In October 2002, EITF 02-3 precluded mark-to-market accounting for risk
management contracts that were not derivatives pursuant to SFAS 133. We
implemented this standard for all non-derivative wholesale and risk management
transactions occurring on or after October 25, 2002. For non-derivative risk
management transactions entered into prior to October 25, 2002, we implemented
this standard on January 1, 2003 and reported the effects of implementation as a
cumulative effect of an accounting change.

After January 1, 2003, we use mark-to-market accounting for wholesale marketing
and risk management transactions that are derivatives unless the derivative is
designated for hedge accounting or the normal purchase and sale exemption.
Revenues and expenses are recognized from wholesale marketing and risk
management transactions that are not derivatives when the commodity is
delivered.

See discussion of EITF 02-3 and Rescission of EITF 98-10 in Note 2.

Accounting for Derivative Instruments
-------------------------------------

We use the mark-to-market method of accounting for derivative contracts.
Unrealized gains and losses prior to settlement, resulting from revaluation of
these contracts to fair value during the period, are recognized currently. When
the derivative contracts are settled and gains and losses are realized, the
previously recorded unrealized gains and losses from mark-to-market valuations
are reversed.

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

The fair values of derivative instruments accounted for using mark-to-market
accounting or hedge accounting are based on exchange prices and broker quotes.
If a quoted market price is not available, the estimate of fair value is based
on the best information available including valuation models that estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
the appropriate valuation adjustments for items such as discounting, liquidity
and credit quality. Credit risk is the risk that the counterparty to the
contract will fail to perform or fail to pay amounts due. Liquidity risk
represents the risk that imperfections in the market will cause the price to be
less than or more than what the price should be based purely on supply and
demand. There are inherent risks related to the underlying assumptions in models
used to fair value open long-term risk management contracts. 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 a contract settles. Therefore,
there could be significant adverse or favorable effects on future results of
operations and cash flows if market prices are not consistent with our approach
at estimating current market consensus for forward prices in the current period.
This is particularly true for long-term contracts.

We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.

Construction Projects for Outside Parties
-----------------------------------------

Our 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,
we enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory hedges 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, 2003 or 2002.

Maintenance
-----------

Maintenance costs are expensed as incurred. If it becomes probable that we will
recover specifically incurred costs through future rates a regulatory asset is
established to match the expensing of maintenance costs with their recovery in
cost-based regulated revenues.

Other Income and Other Expenses
-------------------------------

Non-operational revenue including the nonregulated business activities of our
utilities, equity earnings of non-consolidated subsidiaries, gains on
dispositions of property, interest and dividends, AFUDC and miscellaneous
income, are reported in Other Income. Non-operational expenses including
nonregulated business activities of our utilities, losses on dispositions of
property, miscellaneous amortization, donations and various other non-operating
and miscellaneous expenses, are reported in Other Expenses.


<TABLE>
<CAPTION>

AEP Consolidated Other Income and Deductions:
---------------------------------------------           
                                             
                                                                       December 31,
                                                          2003             2002             2001
                                                         ------          -------           -----
                                                                      (in millions)                    
<C>                                                       <C>              <C>              <C> 
Other Income:
-------------
Equity Earnings (Loss)                                     $10             $(15)             $30 
Non-operational Revenue                                    129              201              184 
Interest                                                    42               26               48 
Gain on Sale of Frontera                                     -               -                73 
Gain on Sale of REPs (Mutual Energy Companies)              39              129                - 
Other                                                      167              120               36 
                                                          -----            -----            -----
Total Other Income                                        $387             $461             $371 
                                                          =====            =====            =====



Other Expenses:
---------------
Property Taxes                                             $20              $20              $15 
Non-operational Expenses                                   112              179               76 
Fiber Optic and Datapult Exit Costs                          -                -               49 
Provision for Loss - Airplane                                -                -               14 
Other                                                       95              124               71
                                                          -----            -----            -----
Total Other Expenses                                      $227             $323             $225 
                                                          =====            =====            =====

</TABLE>

                                                          
Income Taxes and Investment Tax Credits
---------------------------------------

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

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

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

Excise Taxes
------------

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

Debt and Preferred Stock
------------------------

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

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 reflected in rates, redemption premiums paid to reacquire preferred stock
of certain domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.

Goodwill and Intangible Assets
------------------------------

When we acquire businesses we record the fair value of any acquired goodwill and
other intangible assets. Purchased goodwill and intangible assets with
indefinite lives are not amortized. We test acquired goodwill and other
intangible assets with indefinite lives for impairment at least annually.
Intangible assets with finite lives are amortized over their respective
estimated lives to their estimated residual values.

The policies described above became effective with our adoption of a new
accounting standard for goodwill (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. Intangible assets with finite lives continue to be amortized over
their respective estimated lives ranging from 2 to 10 years.

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 have
established investment limitations and general risk management guidelines. 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 external to AEP, who must comply with the guidelines and
rules of the applicable regulatory authorities. The trust assets are invested in
order to optimize the after-tax earnings of the trust, giving consideration to
liquidity, risk, diversification, and other prudent investment objectives.

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

Comprehensive Income (Loss)
---------------------------

Comprehensive income (loss) is defined as the change in equity (net assets) of a
business enterprise during a period from transactions and other events and
circumstances from 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).

Components of Accumulated Other Comprehensive Income (Loss)
-----------------------------------------------------------

Accumulated Other Comprehensive Income (Loss) is included on the balance sheet
in the equity section. The following table provides the components that
constitute the balance sheet amount in Accumulated Other Comprehensive Income
(Loss):

<TABLE>
<CAPTION>

                                                                            December 31,
                                                                  --------------------------------
Components                                                         2003         2002         2001
----------                                                        -------      ------       ------
                                                                            (in millions)
<C>                                                               <C>           <C>          <C>   
Foreign Currency Translation Adjustments                           $110            $4        $(113)
Unrealized Losses on Securities Available for Sale                   (1)           (2)           -  
Unrealized Losses on Cash Flow Hedges                               (94)          (16)          (3)
Minimum Pension Liability                                          (441)         (595)         (10)
                                                                  ------        ------       ------
Total                                                             $(426)        $(609)       $(126)
                                                                  ======        ======       ======
</TABLE>


Stock Based Compensation Plans
------------------------------

At December 31, 2003, we have two stock-based employee compensation plans with
outstanding stock options, which are described more fully in Note 12. No stock
option expense is reflected in our earnings, as all options granted under these
plans had exercise prices equal to or above the market value of the underlying
common stock on the date of grant.

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

We do not currently intend to adopt the fair-value-based method of accounting
for stock options. The following table shows the effect on our Net Income (Loss)
and Earnings (Loss) per Share as if we had applied fair value measurement and
recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based
Compensation," to stock-based employee compensation awards:


<TABLE>
<CAPTION>

                                                                                  Year Ended December 31,
                                                                              -------------------------------
                                                                               2003        2002        2001  
                                                                              ------      ------      ------ 
                                                                           (in millions, except per share data)
          
           <C>                                                                <C>        <C>          <C>   
           Net Income (Loss), as reported                                      $110       $(519)       $971  
           Add:  Stock-based compensation expense included in
            reported net income, net of related tax effects                       2          (5)          3  
           Deduct:  Stock-based employee compensation expense
            determined under fair value based method for all                                     
           awards, net of related tax effects                                    (7)         (4)        (15) 
                                                                               -----      ------       -----
           Pro Forma Net Income (Loss)                                         $105       $(528)       $959  
                                                                               =====      ======       =====

           Earnings (Loss) per Share:
            Basic - as Reported                                               $0.29      $(1.57)      $3.01  
            Basic - Pro Forma (a)                                             $0.27      $(1.59)      $2.98  

            Diluted - as Reported                                             $0.29      $(1.57)      $3.01  
            Diluted - Pro Forma (a)                                           $0.27      $(1.59)      $2.97  

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


Earnings Per Share (EPS)
------------------------

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

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


<TABLE>
<CAPTION>

                                                                                      2003            2002            2001  
                                                                                     ------          ------          ------
                                                                                    (in millions - except per share amounts)
<C>                                                                                     <C>             <C>              <C>   
Weighted Average Shares:
Average Common Shares Outstanding                                                       385             332              322 
Assumed Conversion of Dilutive Stock Options (see Note 12)                                -               -                1
                                                                                        ---             ---              ---
Diluted Average Common Shares Outstanding                                               385             332              323
                                                                                        ===             ===              ===
</TABLE>


The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. Our basic and diluted EPS
are the same in 2003, 2002 and 2001 since the effect on weighted average common
shares outstanding is minimal.

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

Options to purchase 5.6 million, 8.8 million and 0.7 million shares of common 
stock were outstanding at December 31, 2003, 2002 and 2001, respectively, but 
were not included in the computation of diluted earnings per share because the 
options' exercise prices were greater than the year-end market price of the 
common shares and, therefore, the effect would be antidilutive.

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

Supplementary Information
-------------------------

<TABLE>
<CAPTION>

                                                                                         Year Ended December 31,
                                                                                      2003        2002         2001
                                                                                      ----        ----         ----
                                                                                              (in millions)
<C>                                                                                    <C>           <C>        <C>  
AEP Consolidated Purchased Power -
 Ohio Valley Electric Corporation
  (44.2% owned by AEP System)                                                          $147          $142       $127 

Cash was paid for:
  Interest (net of capitalized amounts)                                                $741          $792       $972 
  Income Taxes                                                                         $163          $336       $569 
Noncash Investing and Financing Activities:
 Acquisitions under Capital Leases                                                      $25            $6        $17 
 Assumption of Liabilities Related to Acquisitions                                       $-            $1       $171 
 Increase in assets and liabilities resulting from:
   Consolidation of VIEs due to the adoption of  FIN 46 (see Note 2)                   $547            $-         $- 
   Consolidation of merchant power generation facility (see Note 16)                   $496            $-         $- 
 Exchange of Communication Investment for Common Stock                                   $-            $-         $5 

</TABLE>


Power Projects
--------------

We own interests of 50% or less in domestic unregulated power plants with a
capacity of 1,043 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, we have interests of 50% or less in international power
plants totaling 1,113 MW (see Note 10, "Acquisitions, Dispositions, Discontinued
Operations, Impairments, Assets Held for Sale and Assets Held and Used").

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 our Consolidated Balance Sheets (see "Eastex" within the Dispositions section
of Note 10). At December 31, 2003, five domestic power projects and three
international power investments are accounted for under the equity method. The
five 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 $8 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits. In addition, AEP has
issued letters of credit with maximum future payments of $23 million for
domestic power projects and $69 million for international power investments.

Reclassifications
-----------------

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


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


NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------

SFAS 132 (revised 2003) "Employers' Disclosure about Pensions and Other 
Postretirement Benefits"
-----------------------------------------------------------------------

In December 2003 the FASB issued SFAS 132 (revised 2003), which requires
additional footnote disclosures about pensions and postretirement benefits, some
of which are effective beginning with the year-end 2003 financial statements.
Other additional disclosures will begin with our 2004 quarterly financial
statements or our 2004 year-end financial statements.

We will implement new quarterly disclosures when they become effective in the
first quarter of 2004, including (a) the amount of net periodic benefit cost for
each period for which an income statement is presented, showing separately each
component thereof, and (b) the amount of employer contributions paid and
expected to be paid during the current year, if significantly different from
amounts disclosed at the most recent year-end.

We will implement the new year-end disclosure when it becomes effective in the
fourth quarter of 2004, concerning information about foreign plans, if
appropriate. See Note 11 for these additional 2003 disclosures.

SFAS 142 "Goodwill and Other Intangible Assets"
-----------------------------------------------

SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, and that goodwill and intangible assets be tested
annually for impairment. The implementation of SFAS 142 resulted in a $350
million after tax net transitional loss in 2002 for the U.K. and Australian
operations and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change. See Note 3 for further information on
goodwill and other intangible assets.

SFAS 143 "Accounting for Asset Retirement Obligations"
------------------------------------------------------

We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability at fair
value for any legal obligations for asset retirements in the period incurred.
Upon establishment of a legal liability, SFAS 143 requires a corresponding asset
to be established which will be depreciated over its useful life. SFAS 143
requires that a cumulative effect of change in accounting principle be
recognized for the cumulative accretion and accumulated depreciation that would
have been recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in accounting
principle is favorably affected by the reversal of accumulated removal cost.
These costs had previously been recorded for generation and did not qualify as a
legal obligation although these costs were collected in depreciation rates by
certain formerly regulated subsidiaries.

We completed a review of our asset retirement obligations and concluded that we
have related legal liabilities for nuclear decommissioning costs for our Cook
Plant and our partial ownership in the South Texas Project, as well as
liabilities for the retirement of certain ash ponds, wind farms, the U.K.
Plants, and certain coal mining facilities. Since we presently recover our
nuclear decommissioning costs in our regulated cash flow and have existing
balances recorded for such nuclear retirement obligations, we recognized the
cumulative difference between the amount already provided through rates and the
amount as measured by applying SFAS 143 as a regulatory asset or liability.
Similarly, a regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In 2003, we
recorded an unfavorable cumulative effect of $45.4 million after tax for our
non-regulated operations ($38.0 million related to Ash Ponds in the Utility
Operations segment, $7.2 million related to U.K. Plants in the Investments - UK
Operations segment and $0.2 million for Wind Mills in the Investments - Other
segment).

Certain of our utility operating companies have collected removal costs from
ratepayers for certain assets that do not have associated legal asset retirement
obligations. To the extent that operating companies have now been deregulated we
reversed the balance of such removal costs, totaling $287.2 million, after tax,
which resulted in a net favorable cumulative effect in 2003. We have
reclassified approximately $1.2 billion of removal costs for our utility
operations from accumulated depreciation to Regulatory Liabilities and Deferred
Investment Tax Credits in 2003 and to Deferred Credits and Other in 2002. In
addition, $9 million is classified as held-for-sale related to the TCC
generation assets as of December 31, 2003 and 2002.

The net favorable cumulative effect of the change in accounting principle for
the year ended December 31, 2003 consists of the following:

                                              Pre-tax               After-tax
                                           Income (Loss)          Income (Loss)
                                           -------------          -------------
                                                      (in millions)       

  Ash Ponds                                    $(62.8)               $(38.0)
  U.K. Plants, Wind Mills and
   Coal Operations                              (11.3)                 (7.4)
  Reversal of Cost of Removal                   472.6                 287.2     
                                               -------               -------
  Total                                        $398.5                $241.8
                                               =======               =======

We have identified, but not recognized, asset retirement obligation liabilities
related to electric transmission and distribution and gas pipeline assets, as a
result of certain easements on property on which we have assets. Generally, such
easements are perpetual and require only the retirement and removal of our
assets upon the cessation of the property's use. The retirement obligation is
not estimable for such easements since we plan to use our facilities
indefinitely. The retirement obligation would only be recognized if and when we
abandon or cease the use of specific easements.

The following is a reconciliation of the beginning and ending aggregate carrying
amount of asset retirement obligations:


<TABLE>
<CAPTION>

                                                                                          U.K. Plants,
                                                                                           Wind Mills
                                                     Nuclear                Ash             and Coal
                                                 Decommissioning           Ponds           Operations           Total
                                                 ---------------           -----          ------------          -----
                                                                              (in millions)

        <C>                                          <C>                     <C>                <C>             <C>   
        Asset Retirement Obligation Liability
         at January 1, 2003                          $718.3                  $69.8              $37.2           $825.3  
        Accretion Expense                              52.6                    5.6                2.3             60.5  
        Liabilities Incurred                              -                      -                8.3              8.3  
        Foreign Currency
          Translation                                     -                      -                5.3              5.3
                                                     ------                  -----              -----           ------

        Asset Retirement Obligation
         Liability at December 31, 2003
         including Held for Sale                      770.9                   75.4               53.1            899.4  

        Less Asset Retirement Obligation
         Liability Held for Sale:
           South Texas Project                       (218.8)                     -                  -           (218.8) 
           U.K. Plants                                    -                      -              (28.8)           (28.8)
                                                     ------                  -----              -----           ------
        Asset Retirement Obligation
         Liability at December 31, 2003              $552.1                  $75.4              $24.3           $651.8
                                                     ======                  =====              =====           ======

</TABLE>


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

As of December 31, 2003 and 2002, the fair value of assets that are legally
restricted for purposes of settling the nuclear decommissioning liabilities
totaled $845 million and $716 million, respectively, of which $720 million and
$618 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and
Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of
assets that are legally restricted for purposes of settling the nuclear
decommissioning liabilities for the South Texas Project totaling $125 million
and $98 million as of December 31, 2003 and 2002, respectively, was classified
as Assets Held for Sale in our Consolidated Balance Sheets.

Pro forma net income and earnings per share are not presented for the years
ended December 31, 2002 and 2001 because the pro forma application of SFAS 143
would result in pro forma net income and earnings per share not materially
different from the actual amounts reported during those periods.

As of December 31, 2002 and 2001, the pro forma liability for asset retirement
obligations which has been calculated as if SFAS 143 had been adopted at the
beginning of each period was $825 million and $769 million, respectively.

SFAS 144 "Accounting for the Impairment or Disposal of Long-lived Assets"
-------------------------------------------------------------------------

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." We adopted SFAS
144 effective January 1, 2002. See Note 10 for discussion of impairments
recognized in 2003 and 2002.


SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB 
Statement No. 13, and Technical Corrections"
---------------------------------------------------------------------------

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). 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, we reclassified
Extraordinary Losses (Net of Tax) on TCC's reacquired debt of $2 million for
2001 to Other Expenses.

SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities"
---------------------------------------------------------------------------

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 time at which we recognize future costs related to
exit or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We adopted the provisions of SFAS 146
for exit or disposal activities initiated after December 31, 2002.


SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging 
Activities"
--------------------------------------------------------------------------

On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149
amends SFAS 133 to clarify the definition of a derivative and the requirements
for contracts to qualify for the normal purchase and sale exemption. SFAS 149
also amends certain other existing pronouncements. Effective July 1, 2003, we
implemented SFAS 149 and the effect was not material to our results of
operations, cash flows or financial condition.


SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of 
Both Liabilities and Equity"
------------------------------------------------------------------------------

We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the first phase of
the FASB's project to eliminate from the balance sheet the "mezzanine"
presentation of items with characteristics of both liabilities and equity,
including: (1) mandatorily redeemable shares, (2) instruments other than shares
that could require the issuer to buy back some of its shares in exchange for
cash or other assets and (3) certain obligations that can be settled with
shares. Measurement of these liabilities generally is to be at fair value, with
the payment or accrual of "dividends" and other amounts to holders reported as
interest cost.

Beginning with our third quarter 2003 financial statements, we present
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a
Non-Current Liability. Beginning July 1, 2003, we classify dividends on these
mandatorily redeemable preferred shares as interest expense. In accordance with
SFAS 150, dividends from prior periods remain classified as preferred stock
dividends (a component of Preferred Stock Dividend Requirements of
Subsidiaries).


FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees, 
Including Indirect Guarantees of Indebtedness of Others"
--------------------------------------------------------------------------

In November 2002, the FASB issued FIN 45 which clarifies the accounting to
recognize liabilities related to issuing a guarantee, as well as additional
disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the
effect was not material to our results of operations, cash flows or financial
condition. See Note 8 for further disclosures.


FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities" and
FIN 46 "Consolidation of Variable Interest Entities"
-------------------------------------------------------------------------------

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

On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis). At December
31, 2002 $759 million was reported as a Minority Interest in Finance Subsidiary.
At December 31, 2003 $527 million is reported as a note payable to Caddis, a
component of Long-Term Debt. See Note 17 "Financing Activities" for further
disclosures.

On July 1, 2003, we also deconsolidated the trusts which hold mandatorily
redeemable trust preferred securities. Therefore, of the $321 million net amount
reported as "Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred
Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of
Such Subsidiaries" at December 31, 2002, $331 million is reported as Notes
Payable to Trust (included in Long-term Debt) and $10 million is reported in
Other Non-Current Assets at December 31, 2003.

Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company (Sabine), a
contract mining operation providing mining services to SWEPCo. Upon
consolidation, SWEPCo recorded the assets and liabilities of Sabine ($77.8
million). Also, after consolidation, SWEPCo currently records all expenses
(depreciation, interest and other operation expense) of Sabine and eliminates
Sabine's revenues against SWEPCo's fuel expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate, and
there is no change in net income due to the consolidation of Sabine.

Effective July 1, 2003, OPCo consolidated JMG. Upon consolidation, OPCo recorded
the assets and liabilities of JMG ($469.6 million). OPCo now records the
depreciation, interest and other operating expenses of JMG and eliminates JMG's
revenues against OPCo's operating lease expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate JMG,
and there is no change in net income due to the consolidation of JMG. See Note
16 "Leases" for further disclosures.

In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R) 
which replaces FIN 46.  The FASB and other accounting constituencies continue to
interpret the application of FIN 46R.  As a result, we are continuing to review
the application of this new interpretation and expect to adopt FIN 46R by
March 31, 2004.

EITF 02-3 and Rescission of EITF 98-10
--------------------------------------

In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and related
interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded
for risk management contracts that are not derivatives pursuant to SFAS 133. The
consensus to rescind EITF 98-10 also eliminated the recognition of physical
inventories at fair value other than as provided by GAAP. We have implemented
this standard for all physical inventory and non-derivative risk management
transactions occurring on or after October 25, 2002. For physical inventory and
non-derivative risk management transactions entered into prior to October 25,
2002, we implemented this standard on January 1, 2003 and reported the effects
of implementation as a cumulative effect of an accounting change. We recorded a
$49 million loss, net of income tax, as a cumulative effect of accounting
change.

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 risk management
purposes. Previous guidance in EITF 98-10 permitted contracts that were not
settled financially to be reported either gross or net in the income statement.
Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward risk management contracts as revenues; we also recorded and
reported purchases under forward risk management contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward risk management
revenues and purchases on a net basis. The reclassification of such risk
management activities 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 our financial condition, results of operations or cash flows.


EITF 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That 
Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" as
Defined in Issue No. 02-3"
------------------------------------------------------------------------------

In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus
states that realized gains and losses on derivative contracts not "held for
trading purposes" should be reported either on a net or gross basis based on the
relevant facts and circumstances. Reclassification of prior year amounts is not
required. The adoption of EITF 03-11 did not have a material impact on our
results of operations, financial position or cash flows.


FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related 
to the Medicare Prescription Drug Improvement and Modernization Act of 2003
-----------------------------------------------------------------------------

On January 12, 2004, the FASB Staff issued FSP 106-1, which allows a one-time
election to defer accounting for any effects of the prescription drug subsidy
under the Medicare Prescription Drug Improvement and Modernization Act of 2003
(the Act), enacted on December 8, 2003. There are significant uncertainties as
to whether our plan will be eligible for a subsidy under future federal
regulations that have not yet been drafted. The method of accounting for any
such subsidy and, therefore, the subsidy's possible reduction to our accumulated
postretirement benefit obligation and periodic postretirement benefit costs has
not been resolved by the FASB or other professional accounting standard setting
authority. Accordingly, we elected to defer any potential effects of the Act
until authoritative guidance on the accounting for the federal subsidy is
issued. Our measurements of the accumulated postretirement benefit obligation
and periodic postretirement benefit cost included in these financial statements
do not reflect any potential effects of the Act. We cannot determine what
impact, if any, new authoritative guidance on the accounting for the federal
subsidy may have on our results of operations or financial condition.

Future Accounting Changes
-------------------------

The FASB's standard-setting process is ongoing. Until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting of
our operations that may result from any such future changes.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES
---------------------------------------

Accounting for Risk Management Contracts
----------------------------------------

EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. We recorded a
$49 million after tax charge against net income as Accounting for Risk
Management Contracts in our Consolidated Statements of Operations in Cumulative
Effect of Accounting Changes in the first quarter of 2003 ($12 million in
Utility Operations, $22 million in Investments - Gas Operations and $15 million
in Investments - UK Operations segments). This amount will be realized when the
positions settle.

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.

The effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market after tax effect of $18 million (net of tax of
$2 million). It was reported as a cumulative effect of an accounting change on
our Consolidated Statements of Operations (included in Investments-Other 
segment).

Asset Retirement Obligations (SFAS 143)
---------------------------------------

In the first quarter of 2003, we recorded $242 million in after-tax income as a
cumulative effect of accounting change for Asset Retirement Obligations.

Goodwill and Other Intangible Assets
------------------------------------

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 in 2002 resulted in a $350 million net transitional
loss for our U.K. and Australian operations (included in the Investments - Other
segment) and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change (see Note 3, "Goodwill and Other
Intangible Assets" for further details).

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


<TABLE>
<CAPTION>

                                                                                        Year Ended  December 31,       
                                                                              ----------------------------------------- 
Description                                                                   2003               2002              2001
-----------                                                                   ----               ----              ----
                                                                                             (in millions)
<C>                                                                           <C>                  <C>              <C>
Accounting for Risk Management Contracts (EITF 02-3)                          $(49)                $-               $- 
Asset Retirement Obligations (SFAS 143)                                        242                  -                - 
Goodwill and Other Intangible Assets                                             -               (350)               - 
Accounting for Risk Management Contracts (DIG Guidance)                          -                  -               18
                                                                              -----             ------             ----
Total                                                                         $193              $(350)             $18
                                                                              =====             ======             ====
</TABLE>


EXTRAORDINARY ITEMS
-------------------

In 2001, we recorded an extraordinary item for the discontinuance of regulatory
accounting under SFAS 71 for the generation portion of our business in the Ohio
state jurisdiction. OPCo and CSPCo recognized an extraordinary loss of $48
million (net of tax of $20 million) for unrecoverable Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits. 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.


3.  GOODWILL AND OTHER INTANGIBLE ASSETS
----------------------------------------


GOODWILL
--------

The changes in our carrying amount of goodwill for the years ended December 31,
2003 and 2002 by operating segment are:


<TABLE>
<CAPTION>
                                                                                Investments                            
                                                                   ---------------------------------------                      
                                                       Utility         Gas              UK                           AEP
                                                     Operations    Operations        Operations      Other      Consolidated 
                                                     ----------    ------------      ----------      -----      ------------
                                                                                   (in millions)
   <C>                                                  <C>           <C>              <C>           <C>            <C>         
   Balance at January 1, 2002                                                                                               
     (including Assets Held for Sale)                   $37.1         $340.1               $-        $14.9          $392.1  
   Goodwill acquired                                        -              -              2.3            -             2.3  
   Changes to Goodwill due to
     Purchase price adjustments                             -          (33.8)           172.5         42.4           181.1  
   Impairment losses                                        -              -           (170.0)       (15.9)         (185.9) 
   Foreign currency exchange rate changes                   -              -              6.4            -             6.4
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2002
     (including Assets Held for Sale)                    37.1          306.3             11.2         41.4           396.0  
   Less: Assets Held for Sale, Net (a)                      -         (143.8)           (11.2)           -          (155.0) 
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2002
     (excluding Assets Held for Sale)                   $37.1         $162.5               $-        $41.4          $241.0  
                                                        =====         ======           =======       ======         =======

   Balance at January 1, 2003
     (including Assets Held for Sale)                   $37.1         $306.3            $11.2        $41.4          $396.0  
   Impairment losses                                        -         (291.4)           (12.2)           -          (303.6) 
   Foreign currency exchange rate changes                   -              -              1.0            -             1.0
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2003
     (including Assets Held for Sale)                    37.1           14.9                -         41.4            93.4  
   Less: Assets Held for Sale, Net (a)                      -          (14.9)               -            -           (14.9) 
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2003
    (excluding Assets Held for Sale)                    $37.1             $-               $-        $41.4           $78.5  
                                                        =====         =======          =======       ======         ======

</TABLE>


    (a) On our Consolidated Balance Sheets, amounts related to entities
        classified as held for sale are excluded from Goodwill and are reported
        within Assets Held for Sale (see Note 10). The following entities
        classified as held for sale had goodwill or goodwill impairments during
        the years ended December 31, 2003 or 2002:

  o     Jefferson Island (Investments - Gas Operations segment) - $14.4
        million and $143.3 million balances in goodwill at December 1, 2003 
        and 2002, respectively. During 2003, we recognized a goodwill 
        impairment loss of $128.9 million.
  o     LIG Chemical (Investments - Gas Operations segment) - $0.5 million 
        balance in goodwill at December 31, 2003 and 2002.
  o     U.K. Coal Trading (Investments - UK Operations segment) - $11.2
        million balance in goodwill at December 31, 2002. In 2003, we 
        recognized a goodwill impairment loss of $12.2 million related to the 
        impairment study (impairment in 2003 was greater than December 31, 
        2002 balance due to changes in foreign currency translation rates).
  o     U.K.  Generation  (Investments  - UK  Operations  segment) - No 
        goodwill  balances at December  31, 2003 or 2002.  In 2002, we 
        recognized a goodwill impairment loss of $166.0 million related to the
        impairment study.
  o     AEP Coal  (Investments - Other  segment) - No goodwill balances at 
        December 31, 2003 or 2002. In 2002, we recognized a $3.6 million 
        impairment loss related to the impairment study.

Accumulated amortization of goodwill was approximately $1 million and $9 million
at December 31, 2003 and 2002, respectively. The decrease of $8 million between
years is related to the impairment of goodwill on Houston Pipe Line Company and
AEP Energy Services.

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

During 2002, changes to goodwill were due to purchase price adjustments of $6.7
million primarily related to our acquisition of Houston Pipe Line Company, MEMCO
and Nordic Trading (see Note 10).

In the first quarter of 2002, we recognized a goodwill impairment loss of $12.3
million for all goodwill related to Gas Power Systems (see Note 10).

In the fourth quarter of 2002, we prepared our annual goodwill impairment tests.
The fair values of the operations were estimated using cash flow projections. As
a result of the tests, we recognized a goodwill impairment loss of $4.0 million
related to Nordic Trading (see Note 10).

The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as Cumulative Effect of Accounting Changes in 2002, is
excluded from the above schedule.

The following tables show the transitional disclosures to adjust our 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,
-----------------                                      ----------------------------------
                                                       2003            2002          2001
                                                       ----            ----          ----
                                                                  (in millions)            
<C>                                                    <C>            <C>          <C>     
Reported Net Income (Loss)                             $110           $(519)         $971    
Add back: Goodwill amortization                           -               -            39(a)
Add back: Amortization for intangibles with 
 indefinite lives                                         -               -             8(b)
                                                       -----          ------       -------
Adjusted Net Income (Loss)                             $110           $(519)       $1,018    
                                                       =====          ======       =======
</TABLE>



<TABLE>
<CAPTION>


Earnings (Loss) Per Share (Basic and Dilutive)              Year Ended December 31,
----------------------------------------------         ----------------------------------
                                                       2003            2002          2001
                                                       ----            ----          ----
<C>                                                    <C>           <C>            <C>      
Reported Earnings (Loss) per Share                     $0.29         $(1.57)        $3.01    
Add back: Goodwill amortization                            -              -          0.12(c)
Add back: Amortization for intangibles with
 indefinite lives                                          -              -          0.02(b)
                                                       -----         -------        ------
Adjusted Earnings (Loss) per Share                     $0.29         $(1.57)        $3.15    
                                                       =====         =======        ======
</TABLE>



(a) This amount includes $34 million in 2001 related to SEEBOARD and CitiPower
    amortization expense included in Discontinued Operations on our Consolidated
    Statements of Operations. 
(b) The amounts shown for 2001 relate to CitiPower amortization expense 
    included in Discontinued Operations on our Consolidated Statements of 
    Operations.
(c) This amount includes $0.10 in 2001 related to SEEBOARD and CitiPower
    amortization expense included in Discontinued Operations on our Consolidated
    Statements of Operations.

OTHER INTANGIBLE ASSETS
-----------------------

Acquired intangible assets subject to amortization are $34 million at December
31, 2003 and $37 million at December 31, 2002, net of accumulated amortization.
The gross carrying amount, accumulated amortization and amortization life by
major asset class are:


<TABLE>
<CAPTION>

                                                                 December 31, 2003                   December 31, 2002
                                                             ---------------------------          ----------------------
                                                              Gross                             Gross
                                         Amortization        Carrying       Accumulated        Carrying         Accumulated
                                             Life             Amount        Amortization        Amount          Amortization
                                         ------------        --------       ------------       --------         ------------
                                          (in years)               (in millions)                       (in millions)
<C>                                            <C>            <C>              <C>              <C>                <C>   
Software and customer list (a)                  2                $-               $-             $0.5              $0.2  
Software acquired (b)                           3               0.5              0.3              0.5                 -  
Patent                                          5               0.1                -              0.1                 -  
Easements                                      10               2.2              0.3                -                 -  
Trade name and administration of                 
contracts                                       7               2.4              0.9              2.4               0.6  
Purchased technology                           10              10.9              2.2             10.3               1.0  
Advanced royalties                             10              29.4              7.7             29.4               4.7  
                                                              -----            -----            -----              ----
Total                                                         $45.5            $11.4            $43.2              $6.5  
                                                              =====            =====            =====              ====
</TABLE>



(a) This asset was disposed of in the second quarter of 2003.
(b) This asset relates to U.K. Generation Plants and is included in Assets Held
    for Sale on our Consolidated Balance Sheets.

Amortization of intangible assets was $5 million and $4 million for the twelve
months ended December 31, 2003 and 2002, respectively. Our estimated aggregate
amortization expense is $5 million for each year 2004 through 2007, $4 million
for 2008 through 2010 and $3 million in 2011.


4.  RATE MATTERS
----------------

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

Fuel in SPP Area of Texas
-------------------------

In 2001, the PUCT delayed the start of customer choice in the SPP area of Texas.
In May 2003, the PUCT ordered that competition would not begin in the SPP areas
before January 1, 2007. TNC filed with the PUCT in 2002 to determine the most
appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the
PUCT issued an order adopting the methodology proposed in TNC's filing, with
adjustments, for reconciling fuel costs in the SPP area. The adjustments removed
$3.71 per MWH from reconcilable fuel expense. This adjustment will reduce
revenues received by Mutual Energy SWEPCo who now serves TNC's SPP customers by
approximately $400,000 annually. In October 2003, Mutual Energy SWEPCo agreed
with the PUCT staff and the Office of Public Utility Counsel (OPC) to file a
fuel reconciliation proceeding for the period January 2002 through December 2003
by March 31, 2004 and the PUCT ordered that the filing be made.

TNC Fuel Reconciliations
------------------------

In June 2002, TNC filed with the PUCT to reconcile fuel costs, requesting 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
deferred 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 for
under-recovered fuel costs. TNC's SPP customers will continue to be subject to
fuel reconciliations until competition begins in the SPP area as described
above. The under-recovery balance at December 31, 2001 for TNC's service within
SPP was $0.7 million including interest.

In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a reserve of $13 million based on the
recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain
matters and remanded TNC's final fuel reconciliation to the ALJ to consider two
issues. The issues are the sharing of off-system sales margins from AEP's
trading activities with customers for five years per the PUCT's interpretation
of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel
factor revenues and associated costs in the determination of the under-recovery.
The PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the final fuel
reconciliation proceeding. This would result in the sharing of margins for an
additional three and one half years after the end of the Texas ERCOT fuel
factor.

On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel
r
econciliation proceeding on January 15, 2004 accepting the PFD. TNC is waiting
for a written order, after which it will request a rehearing of the PUCT's
ruling. While management believes that the Texas merger settlement only provided
for sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was recorded in
December 2003. Based on the decisions of the PUCT, TNC's final under-recovery
including interest at December 31, 2003 was $6.2 million.

In February 2002, TNC received a final order from the PUCT in a previous fuel
reconciliation covering the period July 1997 to June 2000 and reflected the
order in its financial statements. This final order was appealed to the Travis
County District Court. In May 2003, the District Court upheld the PUCT's final
order. That order is currently on appeal to the Third Court of Appeals.

TCC Fuel Reconciliation
-----------------------

In December 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery balance in the
2004 true-up proceeding. This reconciliation covers the period of July 1998
through December 2001. 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.

Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC
established a reserve for potential adverse rulings of $81 million during 2003.
In July 2003, the ALJ requested that additional information be provided in the
TCC fuel reconciliation related to the impact of the TNC orders, referenced
above, on TCC. On February 3, 2004, the ALJ issued a PFD recommending that the
PUCT disallow $140 million in eligible fuel costs including some new items not
considered in the TNC case, and other items considered but not disallowed in the
TNC ruling. At this time, management is unable to predict the outcome of this
proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of
the established reserve 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 6 "Customer Choice and
Industry Restructuring."

SWEPCo Texas Fuel Reconciliation
--------------------------------

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This
reconciliation covers the period of January 2000 through December 2002. At
December 31, 2002, SWEPCo's filing included a $2 million deferred over-recovery
balance including interest. During the reconciliation period, SWEPCo incurred
$435 million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of more than
$30 million. In December 2003, SWEPCo agreed to a settlement in principle with
all parties in the fuel reconciliation. The settlement provides for a
disallowance in fuel costs of $8 million which was recorded in December 2003. In
addition, the settlement provides for the deferral as a regulatory asset of
costs of a new lignite mining agreement in excess of a specified benchmark for
lignite at SWEPCo's Dolet Hills Plant. The settlement provides for recovery of
the deferred costs over a period ending in April 2011 as cost savings are
realized under the new mining agreement. The settlement also will allow future
recovery of litigation costs associated with the termination of a previous 
lignite mining agreement if future costs savings are adequate. The settlement
will be filed with the PUCT for approval.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal
--------------------------------------------

Several parties including the Office of Public Utility Counsel (OPC) and cities
served by both TCC and TNC appealed the PUCT's December 2001 orders establishing
initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June
25, 2003, the District Court ruled in both appeals. The Court ruled in the
Mutual Energy WTU case that the PUCT lacked sufficient evidence to include
unaccounted for energy in the fuel factor, and that the PUCT improperly shifted
the burden of proof and the record lacked substantial evidence on the effect of
loss of load due to retail competition on generation requirements. The Court
upheld the initial PTB orders on all other issues. In the Mutual Energy CPL
proceeding, the Court ruled that the PUCT improperly shifted the burden of proof
and the record lacked substantial evidence on the effect of loss of load due to
retail competition on generation requirements. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million for Mutual
Energy WTU. At this time, management is unable to estimate the potential
financial impact related to the loss of load issue. The District Court decision
was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy
WTU and other parties. Management believes, based on the advice of counsel, that
the PUCT's original decision will ultimately be upheld. If the District Court's
decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors
charged to retail customers in 2002 and 2003 resulting in an adverse effect on
future results of operations and cash flows.

Unbundled Cost of Service (UCOS) Appeal
---------------------------------------

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

TCC Rate Case
-------------

On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's requested
$67 million rate increase. The recommendations range from a decrease in existing
rates of approximately $100 million to an increase in TCC's current rates of
approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004,
recommending reductions to TCC's request of approximately $51 million. TCC's
rebuttal testimony was filed on February 26, 2004. Hearings are scheduled for
March 2004 with a PUCT decision expected in May 2004. Management is unable to
predict the ultimate effect of this proceeding on TCC's rates or its impact on
TCC's results of operations, cash flows and financial condition.

Louisiana Fuel Audit
--------------------

The LPSC is performing an audit of SWEPCo's historical fuel costs. In addition,
five SWEPCo customers filed a suit in the Caddo Parish District Court in January
2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has
over charged them for fuel costs since 1975. The LPSC consolidated the customer
complaint and audit. In January 2004, a procedural schedule was issued requiring
LPSC Staff and intervenor testimony to be filed in June 2004 and scheduling
hearings for October 2004. Management believes that SWEPCo's fuel costs were
proper and those costs incurred prior to 1999 have been approved by the LPSC.
Management is unable to predict the outcome of these proceedings. If the actions
of the LPSC or the Court result in a material disallowance of recovery of
SWEPCo's fuel costs from customers, it could have an adverse impact on results
of operations and cash flows.

Louisiana Compliance Filing
---------------------------

In October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of 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. In 2004 the
LPSC required SWEPCo to file updated financial information with a test year
ending December 31, 2003 before April 16, 2004. If, after review of the updated
information, 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 Wholesale Fuel Complaints
------------------------------

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 since 1997.

Negotiations to settle the complaint and update the contracts resulted in new
contracts. The FERC approved an offer of settlement regarding the fuel complaint
and new contracts at market prices in December 2003. Since TNC had recorded a
provision for refund in 2002, the effect of the settlement was a $4 million
favorable adjustment recorded in December 2003. 

Environmental Surcharge Filing
------------------------------

In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million) to
recover the cost of emissions control equipment being installed at the Big Sandy
Plant. See NOx Reductions in Note 7.

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

PSO Rate Review
---------------

In February 2003, the Director of the OCC filed an application requiring PSO to
file all documents necessary for a general rate review. In October 2003, PSO
filed financial information and supporting testimony in response to the OCC's
requirements. PSO's response indicates that its annual revenues are $36 million
less than costs. As a result, PSO is seeking OCC approval to increase its base
rates by that amount, which is a 3.6% increase over PSO's existing revenues.
Hearings are scheduled for October 2004. Management is unable to predict the
ultimate effect of this review on PSO's rates or its impact on PSO's results of
operations, cash flows and financial condition.

PSO Fuel and Purchased Power
----------------------------

PSO had a $44 million under-recovery of fuel costs resulting from a 2002
reallocation among AEP West companies of purchased power costs for periods prior
to January 1, 2002. In July 2003, PSO filed with the OCC seeking recovery of the
$44 million over an 18-month time period. In August 2003, the OCC Staff filed
testimony recommending PSO be granted recovery of $42.4 million over three
years. In September 2003, the OCC expanded the case to include a full review of
PSO's 2001 fuel and purchased power practices. PSO filed its testimony in
February 2004 and hearings will occur in June 2004. If the OCC determines as a
result of the review that a portion of PSO's fuel and purchased power costs
should not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.

Virginia Fuel Factor Filing
---------------------------

APCo filed with the Virginia SCC to reduce its fuel factor effective August 1,
2003. The requested fuel rate reduction was approved by the Virginia SCC and is
effective for 17 months (August 1, 2003 to December 31, 2004) and is estimated
to reduce revenues by $36 million during that period. This fuel factor
adjustment will reduce cash flows without impacting results of operations as any
over-recovery or under-recovery of fuel costs would be deferred as a regulatory
liability or a regulatory asset.

FERC Long-term Contracts
------------------------

In 2002, the FERC set for hearing complaints filed by certain wholesale
customers located in Nevada and Washington that sought to break long-term
contracts which the customers alleged were "high-priced." At issue were
long-term contracts entered into during the California energy price spike in
2000 and 2001. The complaints alleged that AEP sold power at unjust and
unreasonable prices.

In February 2003, AEP and one of the customers agreed to terminate their
contract. The customer withdrew its FERC complaint and paid $59 million to AEP.
As a result of the contract termination, AEP reversed $69 million of unrealized
mark-to-market gains previously recorded, resulting in a $10 million pre-tax
loss.

In December 2002, a FERC ALJ ruled in favor of AEP and dismissed a complaint
filed by two Nevada utilities. In 2000 and 2001, we agreed to sell power to the
utilities for future delivery. In 2001, the utilities filed complaints asserting
that the prices for power supplied under those contracts should be lowered
because the market for power was allegedly dysfunctional at the time such
contracts were executed. The ALJ rejected the utilities' complaint, held that
the markets for future delivery were not dysfunctional, and that the utilities
had failed to demonstrate that the public interest required that changes be made
to the contracts. In June 2003, the FERC issued an order affirming the ALJ's
decision. The utilities requested a rehearing which the FERC denied. The
utilities' appeal of the FERC order is pending before the U.S. Court of Appeals
for the Ninth Circuit. Management is unable to predict the outcome of this
proceeding and its impact on future results of operations and cash flows.

RTO Formation/Integration Costs
-------------------------------

With FERC approval, AEP East companies have been deferring costs incurred under
FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). In
July 2003, the FERC issued an order approving our continued deferral of both our
Alliance formation costs and our PJM integration costs including the deferral of
a carrying charge. The AEP East companies have deferred approximately $28
million of RTO formation and integration costs and related carrying charges
through December 31, 2003. As a result of the subsequent delay in the
integration of AEP's East transmission system into PJM, FERC declined to rule,
in its July order, on our request to transfer the deferrals to regulatory
assets, and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration with PJM.
In August 2003, the Virginia SCC filed a request for rehearing of the July
order, arguing that FERC's action was an infringement on state jurisdiction, and
that FERC should not have treated Alliance RTO startup costs in the same manner
as PJM integration costs. On October 22, 2003, FERC denied the rehearing
request.

In its July 2003 order, FERC indicated that it would review the deferred costs
at the time they are transferred to a regulatory asset account and scheduled for
amortization and recovery in the open access transmission tariff (OATT) to be
charged by PJM. Management believes that the FERC will grant permission for the
deferred RTO costs to be amortized and included in the OATT. Whether the
amortized costs will be fully recoverable depends upon the state regulatory
commissions' treatment of AEP East companies' portion of the OATT at the time
they join PJM. Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. APCo's Virginia retail
base rates are capped with an opportunity for a one-time increase in
non-generation rates after January 1, 2004. We intend to file an application
with FERC seeking permission to delay the amortization of the deferred RTO
formation/integration costs until they are recoverable from all users of the
transmission system including retail customers. Management is unable to predict
the timing of when AEP will join PJM and if upon joining PJM whether FERC will
grant a delay of recovery until the rate caps and freezes end. If the AEP East
companies do not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently estimated at
$24 million for the entire PJM integration project). Management intends to seek
recovery of the deferred RTO formation/integration costs and project
implementation cost reimbursements, if incurred. If the FERC ultimately decides
not to approve a delay or the state commissions deny recovery, future results of
operations and cash flows could be adversely affected.

In the first quarter of 2003, the state of Virginia enacted legislation
preventing APCo from joining an RTO prior to July 1, 2004 and thereafter only
with the approval of the Virginia SCC, but required such transfers by January 1,
2005. In January 2004, APCo filed with the Virginia SCC a cost/benefit study
covering the time period through 2014 as required by the Virginia SCC. The study
results show a net benefit of approximately $98 million for APCo over the
11-year study period from AEP's participation in PJM.

In July 2003, the KPSC denied KPCo's request to join PJM based in part on a lack
of evidence that it would benefit Kentucky retail customers. In August 2003,
KPCo sought and was granted a rehearing to submit additional evidence. In
December 2003, AEP filed with the KPSC a cost/benefit study showing a net
benefit of approximately $13 million for KPCo over the five-year study period
from AEP's participation in PJM. A hearing has been scheduled in April 2004.

In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to certain
conditions included in the order. The IURC's order stated that AEP shall request
and the IURC shall complete a review of Alliance formation costs before any
deferral of the costs for future recovery.

In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set for public hearing before an
ALJ several issues. Those issues include whether the laws, rules, or regulations
of Virginia and Kentucky are preventing AEP from joining an RTO and whether the
exceptions under PURPA apply. The FERC directed the ALJ to issue his initial
decision by March 15, 2004.

FERC Order on Regional Through and Out Rates
--------------------------------------------

In July 2003, the FERC issued an order directing PJM and the Midwest ISO to make
compliance filings for their respective Open Access Transmission Tariffs to
eliminate, by November 1, 2003, the transaction-based charges for through and
out (T&O) transmission service on transactions where the energy is delivered
within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). In
October 2003, the FERC postponed the November 1, 2003 deadline to eliminate T&O
rates. The elimination of the T&O rates will reduce the transmission service
revenues collected by the RTOs and thereby reduce the revenues received by
transmission owners under the RTOs' revenue distribution protocols. The order
provided that affected transmission owners could file to offset the elimination
of these revenues by increasing rates or utilizing a transitional rate mechanism
to recover lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of some of the former Alliance RTO companies,
including AEP, may be unjust, unreasonable, and unduly discriminatory or
preferential for energy delivered in the RTO Footprint. FERC initiated an
investigation and hearing in regard to these rates. We made a filing with the
FERC to support the justness and reasonableness of our rates. We also made a
joint filing with unaffiliated utilities proposing a regional revenue
replacement mechanism for the lost revenues, in the event that FERC eliminated
all T&O rates for delivery points within the RTO Footprint. In orders issued in
November 2003, the FERC dismissed the joint filing, but adopted a new regional
rate design substantially in the form proposed in the joint filing. The orders
directed each transmission provider to file compliance rates to eliminate T&O
rates prospectively within the region and simultaneously implement new seams
elimination cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC did not indicate
the recovery method for the revenues after the two-year period. As required by
the FERC, we filed compliance tariff changes in January 2004 to eliminate the
T&O charges within the RTO Footprint. The SECA rate issues that remain
unresolved have been set before an ALJ for settlement procedures, and the
effective date of the T&O rate elimination and SECA rates were delayed until May
1, 2004. The November orders have been appealed by a number of parties. The AEP
East companies received approximately $150 million of T&O rate revenues from
transactions delivering energy to customers in the RTO Footprint for the twelve
months ended June 30, 2003. At this time, management is unable to predict
whether the new SECA rates will fully compensate the AEP East companies for
their lost T&O rate revenues and, consequently, their impact on our future
results of operations, cash flows and financial condition.

Indiana Fuel Order
------------------

On July 17, 2003, I&M filed a fuel adjustment clause application requesting
authorization to implement the fixed fuel adjustment charge (fixed pursuant to a
prior settlement of the Cook Nuclear Plant Outage) for electric service for the
billing months of October 2003 through February 2004, and for approval of a new
fuel cost adjustment credit for electric service to be applicable during the
March 2004 billing month.

On August 27, 2003, the IURC issued an order approving the requested fixed fuel
adjustment charge for October 2003 through February 2004. The order further
stated that certain parties must negotiate the appropriate action on fuel to
commence on March 1, 2004. Such negotiations are ongoing. The IURC deferred
ruling on the March 2004 factor until after January 1, 2004.

Michigan 2004 Fuel Recovery Plan
--------------------------------

The MPSC's December 16, 1999 order approved a Settlement Agreement regarding the
extended outage of the Cook Plant and fixed I&M Power Supply Cost Recovery
(PSCR) factors for the St. Joseph and Three Rivers rate areas through December
2003. In accordance with the settlement, PSCR Plan cases were not required to be
filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with
the MPSC on September 30, 2003 seeking new fuel and power supply recovery
factors to be effective in 2004. The case has been scheduled for hearing. As
allowed by Michigan law, the proposed factors were effective on January 1, 2004,
subject to review and possible adjustment based on the results of the hearing.


5.  EFFECTS OF REGULATION
-------------------------


Regulatory Assets and Liabilities
---------------------------------

Regulatory assets and liabilities are comprised of the following items:

<TABLE>
<CAPTION>

                                                                                                                       
                                                                                        
                                                                            December 31,                          Future  
                                                                  ------------------------------                 Recovery/
                                                                   2003                    2002                Refund  Period
                                                                   ----                    ----                --------------
                                                                            (in millions)         

<C>                                                                   <C>                <C>              <C>    
  Regulatory Assets:

    Income Tax-related Regulatory Assets, Net                           $728               $639           Various Periods  (a)
    Transition Regulatory Assets                                         529                743             Up to 5 Years  (a)
    Regulatory Assets Designated for Securitization                    1,253                331                            (b)
    Texas Wholesale Capacity Auction True-Up                             480                262                            (c)
    Unamortized Loss on Reacquired Debt                                  116                 83             Up to 40 Years (d)
    Cook Nuclear Plant Restart Costs                                       -                 40                            N/A
    Cook Nuclear Plant Refueling Outage Levelization                      57                 30                            (e)
    Deferred Fuel Costs                                                   24                121                     1 Year (a)
    CSW Merger Costs                                                      23                 32              Up to 5 Years (a)
    Deferred Fuel Costs (TNC)                                             27                 27                            (c)
    DOE Decontamination and Decommissioning Assessment                    21                 26              Up to 5 Years (a)
    Other                                                                290                354           Various Periods  (f)
                                                                      -------            -------
  Total Regulatory Assets                                             $3,548             $2,688 
                                                                      =======            =======

  Regulatory Liabilities:
    Asset Removal Costs                                               $1,233                 $-                            (h)
    Deferred Investment Tax Credits                                      422                455             Up to 26 Years (a)
    Excess ARO for Nuclear Decommissioning Liability                     216                  -                            (g)
    Deferred Over-Recovered Fuel Costs (TCC)                              69                 69                            (c)
    Deferred Over-Recovered Fuel Costs                                    63                 21                            (a)
    Texas Retail Clawback                                                 57                 66                            (c)
    Other                                                                199                328            Various Periods (f)
                                                                      -------            -------
  Total Regulatory Liabilities                                        $2,259               $939 
                                                                      =======            =======
</TABLE>



  (a) Amount does not earn a return.
  (b) Will be included in TCC's PUCT 2004 true-up proceeding and is designated
      for possible securitization during 2005. 
  (c) Amount will be included in TCC's and TNC's 2004 true-up proceedings for 
      future recovery/payment over a time period to be determined in a future
      PUCT proceeding.
  (d) Amount effectively earns a return.
  (e) Amortized over the period beginning with the commencement of an outage and
      ending with the beginning of the next outage and does not earn a return.
  (f) These regulatory assets and liabilities include items both earning and not
      earning a return.
  (g) Amounts are accrued monthly and will be paid when the nuclear plant is
      decommissioned. This also earns a return. 
  (h) The liability for removal costs will be discharged as removal costs are
      incurred over the life of the plant.

Texas Restructuring Related Regulatory Assets and Liabilities
-------------------------------------------------------------

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

Nuclear Plant Restart
---------------------

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

The amount of deferrals amortized to other O&M expenses were $40 million in
2003, 2002 and 2001. Also pursuant to the settlement agreements, accrued
fuel-related revenues of approximately $37 million in 2003 and $38 million in
2002 and 2001 were amortized as a reduction of revenues.

The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements adversely affected
results of operations through December 31, 2003 when the amortization period
ended.

Merger with CSW
---------------

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

Summary of key provisions of Merger Rate Agreements:

         State/Company                   Ratemaking Provisions
         -------------                   --------------------- 
         Texas - SWEPCo, TCC, TNC        $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.No base rate increase before 
                                         June 15, 2003

         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 7, "Commitments and Contingencies" for information on a court decision
concerning the merger.


6.  CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
----------------------------------------------


Prior to 2003, retail customer choice began in four of the eleven state retail
jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic
electric utility companies operate. The following paragraphs discuss significant
events related to customer choice and industry restructuring.

OHIO RESTRUCTURING
------------------

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 the applicable law by failing to participate in an
RTO.

The complainants seek, among other relief, an order from the PUCO:
  o     suspending  collection  of transition  charges by CSPCo and OPCo until
        transfer of control of their  transmission  assets has occurred
  o     requiring the pricing of standard offer electric generation effective
        January 1, 2006 at the market price used by CSPCo and OPCo in their 1999
        transition plan filings to estimate transition costs and
  o     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 FERC, state legislative and regulatory developments, 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, CSPCo and OPCo filed an application with the
PUCO for approval of the transfer of functional control over certain of their
transmission facilities to PJM. In February 2003, the PUCO consolidated the June
2002 complaint with our December application. CSPCo's and OPCo's motion to
dismiss the complaint has been denied by the PUCO and the PUCO affirmed that
ruling in rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC and
elsewhere." Management is currently unable to predict the timing of the AEP East
companies' (including CSPCo and OPCo) participation in PJM, the outcome of these
proceedings before the PUCO or their impact on results of operations and cash
flows.

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. In January 2004, the
PUCO staff issued a report recommending that the PUCO seek more authority from
the Ohio Legislature on this issue. The PUCO has taken no further action in this
proceeding. Management is unable to predict the outcome of the PUCO's
investigation or its impact on results of operations, cash flows and business
practices, if any.

On March 20, 2003, the PUCO commenced a statutorily required investigation
concerning the desirability, feasibility and timing of declaring retail
ancillary, metering or billing and collection service, supplied to customers
within the certified territories of electric utilities, a competitive retail
electric service. The PUCO sent out a list of questions and set June 6, 2003 and
July 7, 2003 as the dates for initial responses and replies, respectively. CSPCo
and OPCo filed comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this proceeding or
its impact on results of operations or cash flows.

The Ohio Act provides for a Market Development Period (MDP) during which retail
customers can choose their electric power suppliers or receive Default Service
at frozen generation rates from the incumbent utility. The MDP began on January
1, 2001 and is scheduled to terminate no later than December 31, 2005. The PUCO
may terminate the MDP for one or more customer classes before that date if it
determines either that effective competition exists in the incumbent utility's
certified territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail customers
will receive distribution and transmission service from the incumbent utility
whose distribution rates will be approved by the PUCO and whose transmission
rates will be approved by the FERC. Retail customers will continue to have the
right to choose their electric power suppliers or receive Default Service, which
must be offered by the incumbent utility at market rates. On December 17, 2003,
the PUCO adopted a set of rules concerning the method by which it will determine
market rates for Default Service following the MDP. The rule provides for a
Market Based Standard Service Offer which would be a variable rate based on a
transparent forward market, daily market, and/or hourly market prices. The rule
also requires a fixed-rate Competitive Bidding Process for residential and small
nonresidential customers and permits a fixed-rate Competitive Bidding Process
for large general service customers and other customer classes. Customers who do
not switch to a competitive generation provider can choose between the Market
Based Standard Service Offer or the Competitive Bidding Process. Customers who
make no choice will be served pursuant to the Competitive Bidding Process.

On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the
PUCO addressing rates following the end of the MDP, which ends December 31,
2005. If approved by the PUCO, rates would be established pursuant to the plan
for the period from January 1, 2006 through December 31, 2008 instead of the
rates discussed in the previous paragraph. The plan is intended to provide rate
stability and certainty for customers, facilitate the development of a
competitive retail market in Ohio, provide recovery of environmental and other
costs during the plan period and improve the environmental performance of AEP's
generation resources that serve Ohio customers. The plan includes annual, fixed
increases in the generation component of all customers' bills (3% annually for
CSPCo and 7% annually for OPCo), and the opportunity for additional
generation-related increases upon PUCO review and approval. For residential
customers, however, if the temporary 5% generation rate discount provided by the
Ohio Act were eliminated on June 30, 2004, the fixed increases would be 1.6% for
CSPCo and 5.7% for OPCo. The generation-related increases under the plan would
be subject to caps. The plan would maintain distribution rates through the end
of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such
rates could be adjusted for specified reasons through a PUCO filing.
Transmission charges can be adjusted to reflect applicable charges approved by
the FERC related to open access transmission, net congestion, and ancillary
services. The plan also provides for continued recovery of transition regulatory
assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and
carrying costs on required environmental expenditures. A procedural schedule has
not been established for this filing. Management cannot predict whether the plan
will be approved as submitted, modified by the PUCO, or its impacts on results
of operation and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. The
February 2004 filing provides for the continued deferral of customer choice
implementation costs during the rate stabilization plan period. At December 31,
2003, we have incurred $66 million and deferred $26 million of such costs.
Recovery of these regulatory assets will be subject to PUCO review in future
Ohio filings for new distribution rates. If the rate stabilization plan is
approved, it would defer recovery of these amounts until after the end of the
rate stabilization period. Management believes that the customer choice
implementation costs were prudently incurred and the deferred amounts should be
recoverable in future rates. If the PUCO determines that any of the deferred
costs are unrecoverable, it would have an adverse impact on future results of
operations and cash flows.

TEXAS RESTRUCTURING
-------------------

Texas Legislation enacted in 1999 provided the framework and timetable to allow
retail electricity competition for all customers. On January 1, 2002, customer
choice of electricity supplier began in the ERCOT area of Texas. Customer choice
has been delayed in the SPP area of Texas until at least January 1, 2007.

The Texas 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 each utility to structurally unbundle into a retail electric
        provider, a power generation company and a transmission and distribution
        (T&D) utility;
  o     provides for an earnings test for each of the years 1999 through 2001 
        and;
  o     provides for a 2004 true-up proceeding. See 2004 true-up proceeding 
        discussion below.

The Texas Legislation required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations to comply with the Texas Legislation requirements. AEP formed
new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1,
2002 (the start date of retail competition). In December 2002, AEP sold the
affiliated REPs to an unaffiliated company.

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 amount not approved for securitization will be
included in regulatory assets/stranded costs in TCC's 2004 true-up proceeding.

TEXAS 2004 TRUE-UP PROCEEDING
-----------------------------

A 2004 true-up proceeding will determine the amount and recovery of:
  o     net stranded generating plant costs and generation-related regulatory
        assets (stranded costs),
  o     a true-up of actual market prices determined through legislatively-
        mandated capacity auctions to the power costs used in the PUCT's ECOM 
        model for 2002 and 2003 (wholesale capacity auction true-up),
  o     final approved deferred fuel balance,
  o     unrefunded accumulated excess earnings,
  o     excess of price-to-beat revenues over market prices subject to certain 
        conditions and limitations (retail clawback) and
  o     other restructuring true-up items

The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TNC's filing in May 2004 and TCC's filing in September
2004 or 60 days after the completion of the sale of TCC's generation assets, if
later.

Stranded Costs and Generation-Related Regulatory Assets
-------------------------------------------------------

Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generating assets for determining stranded
costs. TCC is the only AEP subsidiary that has stranded costs under the Texas
Legislation. We have elected to use the sale of assets method to determine the
market value of all of our generation assets for stranded cost purposes. When
completed, the sale of our generation assets will substantially complete the
required separation of generation assets from transmission and distribution
assets. For purposes of the 2004 true-up proceeding, the amount of stranded
costs under this market valuation methodology will be the amount by which the
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 TCC's 2004 true-up proceeding.

In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval
of a sales process for all of its generating facilities. In March 2003, the PUCT
dismissed TCC's divestiture filing, determining that it was more appropriate to
address allowable valuation methods for the nuclear asset in a rulemaking
proceeding. The PUCT approved a rule, in May 2003, which allows the market value
obtained by selling nuclear assets to be used in determining stranded costs.
Although the PUCT declined to review TCC's proposed sale of assets process, the
PUCT has hired a consultant to advise TCC during the sale of the generation
assets. TCC's sale of its generating assets will be subject to a review in the
2004 true-up proceeding.

In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generating capacity in Texas. In order to sell these assets, we anticipate
retiring TCC's first mortgage bonds by making open market purchases or defeasing
the bonds. Bids were received for all of TCC's generating plants. In January 
2004, TCC agreed to sell its 7.8% ownership interest in the Oklaunion Power 
Station to an unaffiliated third party for $43 million. The sale of TCC's 
remaining generation is pending. Additional regulatory approvals will be 
required to complete the sale of the generation assets, including NRC approval 
of the transfer of our interest in STP.

In the 2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of TCC's
generating assets, including regulatory assets and liabilities that were not
securitized and reduced by mitigation including unrefunded excess earnings,
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 TCC's 2004 true-up
proceeding.

After the 2004 true-up proceeding, TCC may seek to issue securitization revenue
bonds for its stranded costs and recover the costs of the securitization bonds
through transmission and distribution rates. Based upon the Oklaunion sale and
the bid information for the remaining generation, we recorded an impairment of
generating assets of $938 million in December 2003 as a regulatory asset (see
Note 10). The recovery of the regulatory asset will be subject to review and
approval by the PUCT as a stranded cost in the 2004 true-up proceeding.

Wholesale Capacity Auction True-up
----------------------------------

Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and
after, 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. Actual market power prices received in the
state mandated auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding.

TCC recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction true-up for
the years 2002 and 2003. In TCC's UCOS proceeding, the PUCT estimated that TCC
had negative stranded costs. In its true-up rule, the PUCT determined that the
wholesale capacity auction true-up proceeds should be offset against negative
stranded costs. However, in March 2003, the Texas Court of Appeals ruled that
under the restructuring legislation, other 2004 true-up items, including the
wholesale capacity auction true-up regulatory asset, could be recovered
regardless of the level of stranded costs.


In the fourth quarter of 2003, the PUCT approved a true-up filing package
containing calculation instructions similar to the methodology employed by TCC
to calculate the amount recorded for recovery under its wholesale capacity
auction true-up. The PUCT will review the $480 million wholesale capacity
regulatory asset for recovery as part of the 2004 true-up proceeding.

Fuel Balance Recoveries
-----------------------

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case that established TNC's unrecovered fuel balance, including interest for the
ERCOT service territory, at $6.2 million. This balance will be included in TNC's
2004 true-up proceeding. TNC is waiting for a written order from the PUCT, after
which it will request a rehearing.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery of fuel balance for inclusion in the 2004 true-up
proceeding. In February 2004, an ALJ issued recommendations finding a $205
million over-recovery in this fuel proceeding. Management is unable to predict
the amount of TCC's fuel over-recovery which will be included in its 2004
true-up proceeding.

See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 "Rate Matters"
for further discussion.

Unrefunded Excess Earnings
--------------------------

The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined for the three
year period were $3 million for SWEPCo, $47 million for TCC and $19 million for
TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related
deferred income taxes and appealed the PUCT's final 2000 excess earnings to the
Travis County District Court which upheld the PUCT ruling. The District Court's
ruling was appealed to the Third Court of Appeals. In August 2003, the Third
Court of Appeals reversed the PUCT order and the District Court's judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied and the
PUCT chose not to appeal the ruling any further. Appeal of the same issue from
the PUCT's 2001 order is pending before the District Court. Since an expense and
regulatory liability had been accrued in prior years in compliance with the PUCT
orders, the companies reversed a portion of their regulatory liability for the
years 2000 and 2001 consistent with the Appeals Court's decision and credited
amortization expense during the third quarter of 2003. Pre-tax amounts reversed
by company were $5 million for TCC, $3 million for TNC and $1 million for
SWEPCo.

In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. Since excess
earnings amounts were expensed in 1999, 2000 and 2001, the order 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 and that it was
inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up
proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis
County District Court. That court affirmed the PUCT's decision and further
ordered that the refunds be provided to customers. TCC has appealed the decision
to the Court of Appeals.

Retail Clawback
---------------

The Texas Legislation provides for the affiliated PTB REP serving residential
and small commercial customers to refund to its T&D utility the excess of the
PTB revenues over market prices (subject to certain conditions and a limitation
of $150 per customer). This is the retail clawback. If, prior to January 1,
2004, 40% of the load for the residential or small commercial classes is served
by competitive REPs, the retail clawback is not applicable for that class of
customer. During 2003, TCC and TNC filed to notify the PUCT that competitive
REPs serve over 40% of the load in the small commercial class. The PUCT approved
TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory
liability of approximately $9 million for the small commercial retail clawback
on its REP's books. When the PUCT certified that the REP's in TCC and TNC
service territories had reached the 40% threshold, the regulatory liability was
no longer required for the small commercial class and was reversed in December
2003. At December 31, 2003, the remaining retail clawback regulatory liability
was $57 million.

When the 2004 true-up proceeding is completed, TCC intends to file to recover
PUCT-approved stranded costs and other true-up amounts that are in excess of
current securitized amounts, plus appropriate carrying charges and other true-up
amounts, through non-bypassable competition transition charge in the regulated
T&D rates. TCC may also seek to securitize certain of the approved stranded
plant costs and regulatory assets that were not previously recovered through the
non-bypassable transition charge. The annual costs of securitization are
recovered through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.

In the event we are unable, after the 2004 true-up proceeding, to recover all or
a portion of our stranded plant costs, generation-related regulatory assets,
unrecovered fuel balances, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.

MICHIGAN RESTRUCTURING
----------------------

Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Effective with that date the rates on I&M's Michigan customers' bills for retail
electric service were unbundled to allow customers the opportunity to evaluate
the cost of generation service for comparison with other offers. I&M's total
rates in Michigan remain unchanged and reflect cost of service. At December 31,
2003, 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, 2003 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.

ARKANSAS RESTRUCTURING
----------------------

In February 2003, Arkansas repealed customer choice legislation originally
enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71
regulatory accounting, which had been discontinued in 1999. The reapplication of
SFAS 71 had an insignificant effect on results of operations and financial
condition. As a result of reapplying SFAS 71, derivative contract gains/losses
for transactions within AEP's traditional marketing area allocated to Arkansas
will not affect income until settled. That is, such positions will be recorded
on the balance sheet as either a regulatory asset or liability until realized.

WEST VIRGINIA RESTRUCTURING
---------------------------

APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first
quarter of 2003 after new developments during the quarter prompted an analysis
of the probability of restructuring becoming effective.

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

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

In the 2003 legislative session, the WV Legislature failed to enact the required
tax legislation. Also, legislation enacted in March 2003 clarified the
jurisdiction of the WVPSC over electric generation facilities in WV. In March
2003, APCo's outside counsel advised us that restructuring in WV was no longer
probable and confirmed facts relating to the WVPSC's jurisdiction and rate
authority over APCo's WV generation. APCo has concluded that deregulation of the
WV generation business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.

Reapplying SFAS 71 in WV had an insignificant effect on results of operations
and financial condition. As a result, derivative contract gains/losses related
to transactions within AEP's traditional marketing area allocated to WV will not
affect income until settled. That is, such positions will be recorded on the
balance sheet as either a regulatory asset or liability until realized.
Positions outside AEP's traditional marketing area will continue to be
marked-to-market.


7.  COMMITMENTS AND CONTINGENCIES
---------------------------------


ENVIRONMENTAL
-------------

Federal EPA Complaint and Notice of Violation
---------------------------------------------

The Federal EPA and a number of states have alleged APCo, CSPCo, I&M, OPCo and
other unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the NSRs of the CAA. The Federal EPA filed its complaints
against our subsidiaries in U.S. District Court for the Southern District of
Ohio. The court also consolidated a separate lawsuit, initiated by certain
special interest groups, with the Federal EPA case. The alleged modifications
relate to costs that were incurred at our generating units 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.

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

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

On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA has requested
reconsideration of this decision, or in the alternative, certification of an
interlocutory appeal to the Fourth Circuit Court of Appeals.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged Clean Air Act violations. The
11th Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the Clean Air Act are unconstitutional.

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

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

We are unable to estimate the loss or range of loss related to the contingent
liability for civil penalties under the CAA proceedings. We are also unable to
predict the timing of resolution of these matters due to the number of alleged
violations and the significant number of issues yet to be determined by the
Court. If we do not prevail, any capital and operating costs of additional
pollution control equipment that may be required, as well as any penalties
imposed, would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered through
regulated rates and market prices for electricity.

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 future results of operations and cash flows.

NUCLEAR
-------

Nuclear Plants
--------------

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

Nuclear Incident Liability
--------------------------

The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $10.6 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $300
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $101 million on each licensed reactor in the U.S. payable in
annual installments of $10 million. As a result, I&M could be assessed $202
million per nuclear incident payable in annual installments of $20 million. TCC
could be assessed $50 million per nuclear incident payable in annual
installments of $5 million as its share of a STPNOC assessment. The number of
incidents for which payments could be required is not limited. Under an
industry-wide program insuring workers at nuclear facilities, I&M and TCC are
also obligated for assessments of up to $6 million and $2 million, respectively,
for potential claims. These obligations will remain in effect until December 31,
2007.

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

The current Price-Anderson Act expired in August 2002. Its contingent financial
obligations still apply to reactors licensed by the NRC as of its expiration
date. It is anticipated that the Price-Anderson Act will be renewed in 2004 with
increases in required third party financial protection for nuclear incidents.

SNF Disposal
------------

Federal law provides for government responsibility for permanent SNF disposal
and assesses 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 $226 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, 2003, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and exceed the liability amount. TCC is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal
---------------------------------------------------------

Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. In November 2003, I&M filed to extend the operating licenses of the
two Cook Plant units for up to an additional 20 years. The review of the license
extension application is expected to take at least two years. After expiration
of the licenses, Cook Plant is expected to be decommissioned using the prompt
decontamination and dismantlement (DECON) method. The estimated cost of
decommissioning and low level radioactive waste accumulation disposal costs for
Cook Plant ranges from $821 million to $1,080 million in 2003 nondiscounted
dollars. The wide range is caused by variables in assumptions including the
estimated length of time SNF may need to be stored at the plant site subsequent
to ceasing operations. This, in turn, depends on future developments in the
federal government's SNF disposal program. Continued delays in the federal fuel
disposal program can result in increased decommissioning costs. I&M is
recovering estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $27 million in 2003, 2002 and 2001.

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 2003, 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 decrease the amount needed to be recovered from ratepayers.
Decommissioning costs including interest, unrealized gains and losses and
expenses of the trust funds are recorded in Other Operation expense for Cook
Plant. For STP, nuclear decommissioning costs are recorded in Other Operation
expense, interest income of the trusts are recorded in Nonoperating Income and
interest expense of the trust funds are included in Interest Charges.

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

OPERATIONAL
-----------

Construction and Commitments
----------------------------

The AEP System has substantial construction commitments to support its
operations. Aggregate construction expenditures for 2004-2006 for consolidated
domestic and foreign operations are estimated to be $5.8 billion including
amounts for proposed environmental rules.

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

The AEP System has 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.

Potential Uninsured Losses
--------------------------

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

Power Generation Facility
-------------------------

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).

Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.

On September 5, 2003, TEM and AEP separately filed declaratory judgment actions
in the United States District Court for the Southern District of New York. We
allege that TEM has breached the PPA, and we are seeking a determination of our
rights under the PPA. TEM alleges that the PPA never became enforceable or
alternatively, that the PPA has already been terminated as the result of AEP
breaches. If the PPA is deemed terminated or found to be unenforceable by the
court, we could be adversely affected to the extent we are unable to find other
purchasers of the power with similar contractual terms to the extent we do not
fully recover claimed termination value damages from TEM. The corporate parent
of TEM has provided a limited guaranty.

On November 18, 2003, the above litigation was suspended pending final
resolution in arbitration of all issues pertaining to the protocols relating to
the dispatching, operation, and maintenance of the Facility and the sale and
delivery of electric power products. In the arbitration proceedings, TEM
basically argued that in the absence of mutually agreed upon protocols there was
no commercially reasonable means to obtain or deliver the electric power
products and therefore the PPA is not enforceable. TEM further argued that the
creation of the protocols is not subject to arbitration. The arbitrator ruled in
favor of TEM on February 11, 2004 and concluded that the "creation of protocols"
was not subject to arbitration, but did not rule upon the merits of TEM's claim
that the PPA is not enforceable.

If commercial operation is not achieved for purposes of the PPA by April 30,
2004, TEM may claim that it can terminate the PPA and is owed liquidating
damages of approximately $17.5 million. TEM may also claim that we are not
entitled to receive any termination value for the PPA.

See further discussion in Notes 10 and 16.

Merger Litigation
-----------------

In 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
----------------

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, certain subsidiaries of 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 from Enron 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
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.

We also entered into an agreement with BAM Lease Company which grants HPL the
exclusive right to use approximately 65 billion cubic feet of cushion gas
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust (owned by Enron and Bank of America (BOA)) purports to have a lien on
55 billion cubic feet of this cushion gas. These banks claim to have certain
rights to the cushion gas in certain events of default. In connection with our
acquisition of HPL, the banks and Enron entered into an agreement granting HPL's
exclusive use of 65 billion cubic feet of cushion gas. Enron and the banks
released HPL from all prior and future liabilities and obligations in connection
with the financing arrangement. After the Enron bankruptcy, HPL was informed by
the banks of a purported default by Enron under the terms of the financing
arrangement. In July 2002, the banks filed a lawsuit against HPL in the state
court of Texas seeking a declaratory judgment that they have a valid and
enforceable security interest in gas purportedly in the Bammel storage facility
which would permit them to cause the withdrawal of up to 55 billion cubic feet
of gas from the storage facility. In September 2002, HPL filed a general denial
and certain counterclaims against the banks including that Enron was a necessary
and indispensable party to the Texas state court proceeding initiated by BOA.
HPL also filed a motion to dismiss, which was denied. In December 2003, the
Texas state court granted partial summary judgment in favor of the banks. HPL
appealed this decision. We have considered the possible outcomes of these 
issues in our impairment analysis of HPL; however, actual results could differ 
from those estimates.  Management is unable to predict the outcome of this 
lawsuit or its impact on results of operations, cash flows and financial
condition.

In October 2003, AEP Energy Services Gas Holding Company filed a lawsuit against
BOA in the United States District Court for the Southern District of Texas. On
January 8, 2004, this lawsuit was amended and seeks damages for BOA's breach of
contract, negligent misrepresentation and fraud in connection with transactions
surrounding our acquisition of HPL from Enron including entering into the Bammel
storage facility lease arrangement with Enron and the cushion gas arrangements
with BOA and Enron. BOA led a lending syndicate involving the 1997 gas
monetization that Enron and its subsidiaries undertook and the leasing of the
Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA
made misrepresentations and engaged in fraud to induce and promote the stock
sale of HPL, that BOA directly benefited from the sale of HPL and that AEP
undertook the stock purchase and entered into the Bammel storage facility lease
arrangement with Enron and the cushion gas arrangement with Enron and BOA based
on misrepresentations that BOA made about Enron's financial condition that BOA
knew or should have known were false including that the 1997 gas monetization
did not contravene or constitute a default of any federal, state, or local
statute, rule, regulation, code or any law.

In September 2003, Enron filed a complaint in the Bankruptcy Court against AEPES
challenging AEP's offsetting of receivables and payables and related collateral
across various Enron entities and seeking payment of approximately $125 million
plus interest in connection with gas related trading transactions. We will
assert our right to offset trading payables owed to various Enron entities
against trading receivables due to several AEP subsidiaries. Management is
unable to predict the outcome of this lawsuit or its impact on our results of
operations, cash flows or financial condition.

In December 2003, Enron filed a complaint in the Bankruptcy Court against AEPSC
seeking approximately $93 million plus interest in connection with a transaction
for the sale and purchase of physical power among Enron, AEP and Allegheny
Energy Supply, LLC during November 2001. Enron's claim seeks to unwind the
effects of the transaction. AEP believes it has several defenses to the claims
in the action being brought by Enron. Management is unable to predict the
outcome of this lawsuit or its impact on our results of operations, cash flows
or financial condition.

During 2002 and 2001, we expensed a total of $53 million ($34 million net of
tax) for our estimated loss from the Enron bankruptcy. The amount expensed was
based on an analysis of contracts where AEP and Enron entities are
counterparties, the offsetting of receivables and payables, the application of
deposits from Enron entities and management's analysis of the HPL related
purchase contingencies and indemnifications. As noted above, Enron has
challenged our offsetting of receivables and payables and the Bammel storage
facility lease agreement and cushion gas agreement. Management is unable to
predict the final resolution of these disputes, however the impact on results of
operations, cash flows and financial condition could be material.

Shareholder Lawsuits
--------------------

In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging
securities law violations and seeking class action certification were filed in
federal District Court, Columbus, Ohio against AEP, certain AEP executives, and
in some of the lawsuits, members of the AEP Board of Directors and certain
investment banking firms. The lawsuits claim that we failed to disclose that
alleged "round trip" trades resulted in an overstatement of revenues, that we
failed to disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to disclose
that we did not have in place sufficient management controls to prevent "round
trip" trades or false reporting of energy prices. The plaintiffs seek recovery
of an unstated amount of compensatory damages, attorney fees and costs. The
Court has appointed a lead plaintiff who has filed a Consolidated Amended
Complaint. We have filed a Motion to Dismiss the Consolidated Amended Complaint.
The Motion has been briefed by the parties. Also, in the first quarter of 2003,
a lawsuit making essentially the same allegations and demands was filed in state
Common Pleas Court, Columbus, Ohio against AEP, certain executives, members of
the Board of Directors and our independent auditor. We removed this case to
federal District Court in Columbus and the Court has denied plaintiff's motion
to remand the case to state court. We have moved to consolidate this case with
the other pending cases. We intend to continue to vigorously defend against
these actions.

In the fourth quarter of 2002, two shareholder derivative actions were filed in
state court in Columbus, Ohio against AEP and its Board of Directors alleging a
breach of fiduciary duty for failure to establish and maintain adequate internal
controls over our gas trading operations. These cases have been stayed pending
the outcome of our Motion to Dismiss the Consolidated Amended Complaint in the
federal securities lawsuits. If these cases do proceed, we intend to vigorously
defend against them. Also, in the fourth quarter of 2002 and the first quarter
of 2003, three putative class action lawsuits were filed against AEP, certain
executives and AEP's Employee Retirement Income Security Act (ERISA) Plan
Administrator alleging violations of ERISA in the selection of AEP stock as an
investment alternative and in the allocation of assets to AEP stock. The ERISA
actions are pending in federal District Court, Columbus, Ohio. In these actions,
the plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. We have filed a Motion to Dismiss these actions. The
parties have fully briefed this Motion. We intend to continue to vigorously
defend against these claims.

California Lawsuits
-------------------

In November 2002, the Lieutenant Governor of California filed a lawsuit in Los
Angeles County, California Superior Court against forty energy companies,
including AEP, and two publishing companies alleging violations of California
law through alleged fraudulent reporting of false natural gas price and volume
information with an intent to affect the market price of natural gas and
electricity. This case is in the initial pleading stage and all defendants have
filed motions to dismiss. AEP has been dismissed from the case. The plaintiff
had stated an intention to amend the complaint to add an AEP subsidiary as a
defendant. The plaintiff amended the complaint but did not name any AEP company
as a defendant. In November 2003, Texas-Ohio Energy, Inc. filed a lawsuit in the
United States District Court for the Eastern District of California alleging
that AEP and a large number of other energy companies conspired to manipulate
natural gas prices in California in violation of federal and state antitrust and
unfair competition laws. Certain of the other defendants in this case have filed
a Notice of Potential Tag-Along Action with the Judicial Panel on Multi-District
Litigation seeking to have this case transferred to the United States District
Court for the District of Nevada where there are a number of other cases now
pending that assert claims regarding the alleged manipulation of energy markets
in California. None of the AEP companies is a party to these other pending
cases. Once venue for the Texas-Ohio Energy, Inc. case is determined, we plan to
move to dismiss the complaint and otherwise vigorously defend against these
claims. In February 2004, two individuals on behalf of themselves and two
businesses they own and another individual filed an action in state court in San
Diego County, California against a large number of energy companies including
AEPES. This action alleges violations of state antitrust and unfair competition
laws based on alleged manipulation of gas price indices. This case is in the
initial pleading states. We plan to vigorously defend against these claims.

Cornerstone Lawsuit
-------------------

In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Thereafter, two similar actions were filed in the same court against a number of
companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. On December
5, 2003, the Court issued its initial Pretrial Order consolidating all related
cases, appointing co-lead counsel and providing for the filing of an amended
consolidated complaint. In January 2004, plaintiffs filed an amended
consolidated complaint. We plan to move to dismiss the complaint and otherwise
vigorously defend against these claims.

Texas Commercial Energy, LLP Lawsuit
------------------------------------

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

Bank of Montreal Claim
----------------------

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had
acted contrary to the appropriate trading contract and industry practice in
terminating the contract and calculating termination and liquidation amounts and
that BOM had acknowledged just prior to the termination and liquidation that it
owed us approximately $68 million. We are claiming that BOM owes us at least $45
million. 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.

Arbitration of Williams Claim
-----------------------------

In October 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding resulted 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 we owed approximately $130
million in connection with the termination and liquidation of all trading deals.
Williams and AEP settled the dispute and we paid $90 million to Williams in June
2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter did not have a
material impact on results of operations or financial condition.

Arbitration of PG&E Energy Trading, LLC Claim
---------------------------------------------

In January 2003, PG&E Energy Trading, LLC (PGET) claimed approximately $22
million was owed by AEP in connection with the termination and liquidation of
all trading deals. In February 2003, PGET initiated arbitration proceedings. In
July 2003, AEP and PGET agreed to a settlement and we paid approximately $11
million to PGET. The settlement amount approximated the amount payable that, in
the ordinary course of business, we recorded as part of our trading activity
using MTM accounting. As a result, the settlement payment did not have a
material impact on results of operations, cash flows or financial condition.

Energy Market Investigation
---------------------------

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

In March 2003, we received a subpoena from the SEC as part of the SEC's ongoing
investigation of energy trading activities. In August 2002, we had received an
informal data request from the SEC asking that we voluntarily provide
information. The subpoena sought additional information and is part of the SEC's
formal investigation. We responded to the subpoena and will continue to
cooperate with the SEC.

On September 30, 2003, the CFTC filed a complaint against AEP and AEPES in
federal district court in Columbus, Ohio. The CFTC alleges that AEP and AEPES
provided false or misleading information about market conditions and prices of
natural gas in an attempt to manipulate the price of natural gas in violation of
the Commodity Exchange Act. The CFTC seeks civil penalties, restitution and
disgorgement of benefits. The case is in the initial pleading stage with our
response to the complaint currently due on May 18, 2004. Although management is
unable to predict the outcome of this case, it is not expected to have a
material effect on results of operations due to a provision recorded in December
2003.

In January 2004, the CFTC issued a request for documents and other information
in connection with a CFTC investigation of activities affecting the price of
natural gas in the fall of 2003. We are responding to that request.

Management cannot predict what, if any further action, any of these governmental
agencies may take with respect to these matters.

FERC Proposed Standard Market Design
------------------------------------

In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and operation of
wholesale electricity markets across the country. Key elements of FERC's
proposal included 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 issued a "white paper" on the proposal in April 2003, in
response to the numerous comments that the FERC received on its proposal.
Management does not know if or when the FERC will finalize a rule for SMD. Until
any potential rule is finalized, management cannot predict its effect on cash
flows and results of operations.

FERC Market Power Mitigation
----------------------------

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. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.


8.  GUARANTEES
---------------


There are no liabilities recorded for guarantees entered into prior to December
31, 2002 in accordance with FIN 45. There are certain immaterial liabilities
recorded for guarantees entered into subsequent to December 31, 2002. There is
no collateral held in relation to any guarantees and there is no recourse to
third parties in the event any guarantees are drawn unless specified below.

LETTERS OF CREDIT
-----------------

We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. All of these LOCs were issued by us in the
ordinary course of business. At December 31, 2003, the maximum future payments
for all the LOCs are approximately $227 million with maturities ranging from
January 2004 to January 2011. Included in these amounts is TCC's LOC of
approximately $43 million with a maturity date of November 3, 2005. As the
parent of all these subsidiaries, we hold all assets of the subsidiaries as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.

We have guaranteed 50% of the principal and interest payments as well as 100% of
a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which we are a 50%
owner. In the event Fort Lupton does not make the required debt payments, we
have a maximum future payment exposure of approximately $7 million, which
expires May 2008.

In the event Fort Lupton is unable to perform under its PPA agreement, we have a
maximum future payment exposure of approximately $15 million, which expires June
2019.

We have guaranteed 50% of a security deposit for gas transmission as well as 50%
of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of
which we are a 50% owner. In the event Orange fails to make payments in
accordance with agreements for gas transmission, we have a maximum future
payment exposure of approximately $1 million, which expires June 2023. In the
event Orange is unable to perform under its PPA agreement, we have a maximum
future payment exposure of approximately $1 million, which expires June 2016.

GUARANTEES OF THIRD-PARTY OBLIGATIONS
-------------------------------------

CSW Energy and CSW International
--------------------------------

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 a financing. In the event that Sweeny does not make the required
debt payments, CSW Energy and CSW International have a maximum future payment
exposure of approximately $4 million, which expires June 2020.

AEP Utilities
-------------

AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power
Partners, an IPP of which CSW Energy owns 50%. In the event that Polk Power does
not make the required debt payments, AEP Utilities has a maximum future payment
exposure of approximately $5 million, which expires July 2010.

SWEPCo
------

In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to
assume the capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements,

SWEPCo's total future maximum payment exposure is approximately $58 million with
maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At December 31, 2003, the cost to reclaim the mine in 2035 is
estimated to be approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46
(see Note 2). Upon consolidation, SWEPCo recorded the assets and liabilities of
Sabine ($78 million). Also, after consolidation, SWEPCo currently records all
expenses (depreciation, interest and other operation expense) of Sabine and
eliminates Sabine's revenues against SWEPCo's fuel expenses. There is no
cumulative effect of an accounting change recorded as a result of the
requirement to consolidate, and there is no change in net income due to the
consolidation of Sabine.

INDEMNIFICATIONS AND OTHER GUARANTEES
-------------------------------------

We entered into several types of contracts, which would require
indemnifications. Typically these contracts include, but are not limited to,
sale agreements, lease agreements, purchase agreements and financing agreements.
Generally these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect to sale
agreements, our exposure generally does not exceed the sale price. We cannot
estimate the maximum potential exposure for any of these indemnifications
entered into prior to December 31, 2002 due to the uncertainty of future events.
In 2003 we entered into several sale agreements discussed in Note 10. These sale
agreements include indemnifications with a maximum exposure of approximately $57
million. There are no material liabilities recorded for any indemnifications
entered into during 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.

We lease certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed to receive up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, we have committed to pay the difference between the fair market value and
the unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At December 31, 2003, the maximum potential loss for these
lease agreements was approximately $28 million assuming the fair market value of
the equipment is zero at the end of the lease term.

See Note 16 "Leases" for disclosure of lease residual value guarantees.


9.  SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
-----------------------------------------------


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

Termination benefits expense relating to 1,120 terminated employees totaling 
$75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this 
amount, we paid $9.5 million to these terminated employees in the fourth 
quarter of 2002. No additional termination benefits expense related to the SEI 
initiative was recorded in 2003, and the remaining SEI related payments were 
made in 2003. The termination benefits expense is classified as Maintenance 
and Other Operation expense on our Consolidated Statements of Operations. We
determined that the termination of the employees under our SEI initiative did
not constitute a plan curtailment of any of our retirement benefit plans.


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


ACQUISITIONS
------------

2002
----

Acquisition of Nordic Trading (Investments - UK Operations segment)
-------------------------------------------------------------------

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

Acquisition of USTI (Investments - Other segment)
-------------------------------------------------

In January 2002, we acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both our affiliates and
external customers. Results of operations are included in our Consolidated
Statements of Operations from the date of acquisition.

2001
----

Houston Pipe Line Company (Investments - Gas Operations segment)
----------------------------------------------------------------

On June 1, 2001, through a wholly-owned subsidiary, we 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 prepaid lease of a gas storage
facility and certain gas marketing contracts. The purchase method of accounting
was used to record the acquisition. During 2003 we recorded impairment and other
losses for HPL and related gas operations of $315 million ($228 million net of
tax).

U.K. Generation Plants (Investments - UK  Operations segment)
-------------------------------------------------------------

In December 2001, we acquired 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000 MW station on the River Mersey in northwest
England, and Ferrybridge, a four-unit, 2,000 MW station on the River Aire in
northeast England and related coal stocks. These assets were acquired for a cash
payment of $942.3 million and the assumption of certain liabilities. During 2003
these assets became held-for-sale and we reported the operations as
discontinued. See U.K. Generation Plants in the "Discontinued Operations"
section of this note for further information.

Other Acquisitions (Various segments)
-------------------------------------

We also purchased the following assets or acquired the following businesses from
July 2001 through December 2001:

  o     Dolet Hills mining operations were purchased by SWEPCo, an AEP 
        subsidiary, and SWEPCo also 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 was
        acquired, including certain liabilities. The acquisition includes
        property, coal reserves, mining operations and royalty interests in
        Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. We continue to
        operate the mines and facilities. See AEP Coal in the "Assets Held for
        Sale" section of this note for further information on our decision to
        dispose of this investment.
  o     MEMCO Barge Line was acquired adding 1,200 hopper barges and 30 towboats
        to AEP's existing barging fleet. MEMCO added major barging operations on
        the Mississippi and Ohio rivers to AEP's barging operations on the Ohio
        and Kanawha rivers.
  o     A 20% equity interest in Caiua, a Brazilian electric operating company
        which is a subsidiary of Vale was acquired by converting a total of $66
        million on an existing loan and accrued interest on that loan into Caiua
        equity. See Grupo Rede Investment in the "Dispositions" section of this
        note for further information.
  o     Indian Mesa Wind Project (referred to as "Desert Sky") consisting of 160
        MW of wind generation located near Fort Stockton,  Texasm was purchased.
  o     Enron's London-based international coal trading group was acquired by
        purchasing existing contracts and hiring key staff.

Management recorded the assets acquired and liabilities assumed at their
estimated fair values based on currently available information and on current
assumptions as to future operations.

DISPOSITIONS
------------

2003
----

C3 Communications (Investments - Other segment)
-----------------------------------------------

In February 2003, C3 Communications sold the majority of its assets for a sales
price of $7.25 million. We provided for an $82 million pre-tax ($53 million
after-tax) asset impairment in December 2002 and the effect of the sale on 2003
results of operations was not significant. The impairment is classified in Asset
Impairments and Other Related Changes in our Consolidated Statements of
Operations. See "Assets Held for Sale" section of this note for information on
assets and liabilities held for sale at December 31, 2002 related to our
"telecommunications" businesses.

Mutual Energy Companies (Utility Operations segment)
----------------------------------------------------

On December 23, 2002 we sold the general partner interests and the limited
partner interests in Mutual Energy CPL 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. The buyer 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. We recorded a net gain
totaling $83.7 million after-tax ($129 million pre-tax) in Other Income during
2002. We provided the buyer with a power supply contract for the two REPs and
back-office services related to these customers for a two-year period. In
addition, we retained the right to share in earnings from the two REPs above a
threshold amount through 2006 in the event the Texas retail market develops
increased earnings opportunities. No revenue was recorded in 2003 related to
these sharing agreements. Under the Texas Legislation, REPs are subject to a
clawback liability if customer change does not attain thresholds required by the
legislation. We are responsible for a portion of such liability, if any, for the
period we operated the REPs in the Texas competitive retail market (January 1,
2002 through December 23, 2002). In addition, we retained responsibility for
regulatory obligations arising out of operations before closing. Our
wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an
up-front payment of approximately $30 million from the buyer associated with the
back-office service agreement, and MESC deferred its right to receive payment of
an additional amount of approximately $9 million to secure certain contingent
obligations. These prepaid service revenues were deferred on the books of MESC
as of December 31, 2002 and are being amortized over the two-year term of the
back office service agreement.

In February 2003, we completed the sale of MESC for $30.4 million dollars and
realized a pre-tax gain of approximately $39 million, which included the
recognition of the remaining balance of the original $30 million prepayment ($27
million), as no further service obligations existed for MESC.

Water Heater Assets (Utility Operations segment)
------------------------------------------------

We sold our water heater rental program for $38 million and recorded a pre-tax
loss of $3.9 million in the first quarter of 2003 based upon final terms of the
sale agreement. We had provided for a $7.1 million pre-tax charge in the fourth
quarter 2002 based on an estimated sales price ($3.2 million asset impairment
charge and $3.9 million lease prepayment penalty). The impairment loss is
included in Investment Value Losses in our Consolidated Statements of
Operations. We operated a program to lease electric water heaters to residential
and commercial customers until a decision was reached in the fourth quarter of
2002 to discontinue the program and offer the assets for sale. See the "Assets
Held for Sale" section of this Note for assets and liabilities held for sale as
of December 31, 2002.

AEP Gas Power Systems (Investments - Other segment)
---------------------------------------------------

In 2001, we acquired a 75% interest in a startup company, seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. In
January 2003, AEP Gas Power Systems, LLC sold its assets. We recognized a
goodwill impairment loss of $12.3 million pre-tax in the first quarter of 2002
due to technological and operational problems (also see Note 3). The impairment
loss was recorded in Investment Value Losses on our Consolidated Statements of
Operations. The fair values of the remaining assets and liabilities as of
December 31, 2002 were excluded from held for sale on our Consolidated Balance
Sheets as the impact was not significant. The effect of the asset sale on the
first quarter 2003 results of operations was not significant.

Newgulf Facility (Investments - Other segment)
----------------------------------------------

In 1995, we purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002, we began negotiations
with a likely buyer of the facility. We estimated a pre-tax loss on sale of
$11.8 million based on the indicative bid. This loss was recorded as Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations during the fourth quarter 2002. Newgulf's Property, Plant and
Equipment, net of accumulated depreciation, was classified on our Consolidated
Balance Sheets as held for sale at December 31, 2002. During the second quarter
of 2003 we completed the sale of Newgulf and the impact on earnings in 2003 was
not significant.

Nordic Trading (Investments - UK Operations segment)
----------------------------------------------------

In October 2002 we announced that our ongoing energy trading operations would be
centered around our generation assets. As a result, we took steps to exit our
coal, gas and electricity trading activities in Europe, except for those
activities predominantly related to our U.K. generation operations. The Nordic
Trading business acquired earlier in 2002 was made available for sale to
potential buyers later in 2002. The estimated pre-tax loss on disposal recorded
in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations. Management's determination of a zero fair value was
based on discussions with a potential buyer. The assets and liabilities of
Nordic Trading have been classified on our Consolidated Balance Sheets as held
for sale at December 31, 2002. The transfer of the Nordic Trading business,
including the trading portfolio, to new owners was completed during the second
quarter of 2003 and the impact on earnings during the second quarter of 2003 was
not significant.

Eastex (Investments - Other segment)
------------------------------------

In 1998, we began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, we requested that the FERC allow us to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002, we solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. The estimated pre-tax loss on sale of $218.7 million pre-tax
($142 million after-tax), which was based on the estimated fair value of the
facility and indicative bids by interested buyers, was recorded in Discontinued
Operations in our Consolidated Statements of Operations during the fourth
quarter 2002.

We completed the sale of Eastex during the third quarter of 2003 and the effect
of the sale on third quarter 2003 results of operations was not significant. The
results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 for all years presented. The assets and
liabilities of Eastex were reclassified on the Consolidated Balance Sheets from
Assets Held for Sale and Liabilities Held for Sale to Discontinued Operations at
December 31, 2002. See "Discontinued Operations" section of this note for
additional information.

Grupo Rede Investment (Investments - Other segment)
---------------------------------------------------

In December 2002, we recorded an other than temporary impairment totaling $141.0
million ($217.0 million net of federal income tax benefit of $76.0 million) of
our 44% equity investment in Vale and our 20% equity interest in Caiua, both
Brazilian electric operating companies (referred to as Grupo Rede). This amount
is included in Investment Value Losses on our Consolidated Statements of
Operations.

In December 2003 we transferred our share and investment in Vale to Grupo Rede
for $1 million. The effect of the transfer on fourth quarter results of
operations was not significant.

Excess Equipment (Investments - Other segment)
----------------------------------------------

In November 2002, as a result of a cancelled development project, we obtained
title to a surplus gas turbine generator. We had been unsuccessful in finding
potential buyers of the unit due to an over-supply of generation equipment
available for sale during 2002. An estimated pre-tax loss on disposal of $23.9
million was recorded in December 2002, based on market prices of similar
equipment. The loss is included in Asset Impairments and Other Related Charges
on our Consolidated Statements of Operations. The Other asset of $12 million in
2002 was classified on our Consolidated Balance Sheets as held for sale at
December 31, 2002.

We completed the sale of the surplus gas turbine generator in November 2003. The
proceeds from the sale were $8.7 million. A pre-tax loss of $1.8 million was
recorded in the fourth quarter of 2003.

Ft. Davis Wind Farm (Investments - Other segment)
-------------------------------------------------

In the 1990's, we developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 our engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility is expected to be completed during 2004. An estimated pre-tax
loss on abandonment of $4.7 million was recorded in December 2002. The loss was
recorded in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations.

2002
----

SEEBOARD (Investments - Other segment)
--------------------------------------

On June 18, 2002, through a wholly-owned subsidiary, we entered into an
agreement, subject to European Union (EU) approval, to sell our consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
We received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. The
results of operations of SEEBOARD have been classified as Discontinued
Operations for all years presented. A net loss of $22 million pre-tax ($14
million after-tax) was classified as Discontinued Operations in the second
quarter of 2002. The remaining $323 million of the net loss has been classified
as a transitional goodwill impairment loss from the adoption of SFAS 142 (see
Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change
retroactive to January 1, 2002. A $59 million pre-tax ($38 million after-tax)
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. See "Discontinued Operations" section for the
total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD.

CitiPower (Investments - Other segment)
---------------------------------------

On July 19, 2002, through a wholly owned subsidiary, we entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. We completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. We recorded a pre-tax charge
totaling $192 million ($125 million after-tax) as of June 30, 2002. The charge
included a pre-tax impairment loss of $151 million ($98 million after-tax) on
the remaining carrying value of an intangible asset related to a distribution
license for CitiPower. The remaining $41 million pre-tax ($27 million after-tax)
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 $37 million pre-tax ($24 million
after-tax) to $229 million pre-tax ($149 million after-tax; $122 million plus
$27 million of cumulative effect) in the second half of 2002 based on actual
closing amounts and exchange rates. See the "Discontinued Operations" section of
this note for the total revenues and pretax profit (loss) of the discontinued
operations of CitiPower.

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 ($73 million pre-tax).

In July 2001, through a wholly-owned subsidiary, we sold our 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, we 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 had a nominal impact on our results of operations and
cash flows.

In December 2001, we completed the sale of our 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. Subsequently
during 2002, due to decreasing market value of the shares received from the
sale, we reduced the value of them to zero.

DISCONTINUED OPERATIONS
-----------------------

Management periodically assesses the overall AEP business model and makes
decisions regarding our continued support and funding of our various businesses
and operations. When it is determined that we will seek to exit a particular
business or activity and we have met the accounting requirements for
reclassification, we will reclassify the operations of those businesses or
operations as discontinued operations. The assets and liabilities of these
discontinued operations are classified as Assets and Liabilities Held for Sale
until the time that they are sold. At the time they are sold they are
reclassified to Assets and Liabilities of Discontinued Operations on the
Consolidated Balance Sheets for all periods presented. Assets and liabilities
that are held for sale, but do not qualify as a discontinued operations are
reflected as Assets and Liabilities Held for Sale both while they are held for
sale and after they have been sold, for all periods presented.

Certain of our operations were determined to be discontinued operations and have
been classified as such in 2003, 2002 and 2001.  Results of operations of these
businesses have been reclassified as shown in the following table:

<TABLE>
<CAPTION>


                                                                              Pushan                      U.K.
                                           SEE-                                Power                   Generation
                                          BOARD    CitiPower      Eastex       Plant        LIG           Plants        Total
                                          -----    ---------      ------     ---------      ---      ---------------    -----

     <C>                                  <C>           <C>       <C>           <C>         <C>             <C>         <C>  
     2003 Revenue                            $-           $-       $58          $60         $653            $125         $896 
     2003 Pretax Profit (Loss)                -          (20)      (23)           4         (122)           (713)        (874)
     2003 Earnings(Loss) After Tax           16          (13)      (14)           4          (91)           (507)        (605)


     2002 Revenue                           694          204        73           57          507             251        1,786 
     2002 Pretax Profit (Loss)              180         (190)     (239)         (13)          14            (579)        (827)
     2002 Earnings (Loss) After Tax          96         (123)     (156)          (7)           8            (472)        (654)

     2001 Revenue                         1,451          350         -           57          525              26        2,409 
     2001 Pretax Profit (Loss)              104           (4)        1            8           (6)            (48)          55 
     2001 Earnings (Loss) After Tax          88           (6)        -            4           (4)            (41)          41 
</TABLE>


Assets and liabilities of discontinued operations have been reclassified 
as follows:

                                                                      Eastex
                                                                      ------
                                                                   (in millions)
           As of December 31, 2002
           Current Assets                                                $15  
                                                                         ----
           Total Assets of Discontinued Operations                       $15  
                                                                         ====

           Current Liabilities                                            $8  
           Deferred Credits and Other                                      4  
                                                                         ----
           Total Liabilities of Discontinued Operations                  $12  
                                                                         ====

Pushan Power Plant (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner and a purchase and sale agreement was signed in the fourth quarter of
2003. We expect to close on this transaction by mid 2004. An estimated pre-tax
loss on disposal of $20 million pre-tax ($13 million after-tax) was recorded in
December 2002, based on an indicative price expression. The estimated pre-tax
loss on disposal is classified in Discontinued Operations in our Consolidated
Statements of Operations.

Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan have been classified on our
Consolidated Balance Sheets as held for sale. We have classified the assets and
liabilities as held for sale for longer than 12 months, which is longer than
originally expected, due to several unusual circumstances including the SARS
outbreak and governmental delays.

Louisiana Intrastate Gas (LIG ) (Investments - Gas Operations segment)
----------------------------------------------------------------------

After announcing during 2003 that we would be divesting our non-core assets we
began actively marketing LIG with the help of an investment advisor. After
receiving and analyzing initial bids during the fourth quarter 2003 we recorded
a $133.9 million pre-tax ($99 million after-tax) impairment loss; of this loss,
$128.9 million pre-tax relates to the impairment of goodwill and $5 million
pre-tax relates to other charges. In February 2004, we signed a definitive
agreement to sell the pipeline portion of LIG. We anticipate the sale will be
completed during the second quarter of 2004 and that the impact on results of
operations in 2004 will not be significant. The assets and liabilities of LIG
are classified as held for sale on our Consolidated Balance Sheets and the
results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations.

U.K. Generation Plants (Investments - UK Operations segment)
------------------------------------------------------------

In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 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 our own projections made during the
fourth quarter of 2002 indicated that this situation may extend many years into
the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This
impairment loss is included in 2002 Discontinued Operations on our Consolidated
Statements of Operations.

Management has retained an investment advisor to assist in determining the best
methodology to exit the U.K. business. An information memorandum was distributed
for the sale of our U.K. Generation and based on current information we recorded
a $577 million pre-tax charge ($375 after-tax), including asset impairments of
$420.7 million during the fourth quarter of 2003 to write down the value of the
assets to their estimated realizable value. Additional charges of $156.7 million
pre-tax were also recorded in December 2003 including $122.2 million related to
the net loss on certain cash flow hedges previously recorded in Accumulated
Other Comprehensive Income that has been reclassified into earnings as a result
of management's determination that the hedged event is no longer probable of
occurring and $34.5 million related to a first quarter 2004 sale of certain
power contracts. The assets and liabilities of U.K. Generation have been
classified as held for sale on our Consolidated Balance Sheets and the results
of operations are included in Discontinued Operations on our Consolidated
Statements of Operations. We anticipate the sale of the U.K. Generation plants
during 2004.

ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES
--------------------------------------------------------------------

In 2003, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.4 billion [consisting of approximately $650 million
related to Asset Impairments ($610 million) and Other Related Charges ($40
million), $70 million related to Investment Value Losses, $711 million related
to Discontinued Operations ($550 million of impairments and $161 million of
other charges) and $6 million related to charges recorded for Excess Real Estate
in Maintenance and Other Operation in the Consolidated Statements of Operations]
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, our decision to exit non-core businesses and
other factors.

In 2002, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.7 billion (consisting of approximately $318 million
related to Asset Impairments, $321 million related to Investment Value Losses,
$938 million related to Discontinued Operations and $88 million related to
charges recorded in other lines within the Consolidated Statements of
Operations) that reflected downturns in energy trading markets, projected
long-term decreases in electricity prices, and other factors. These impairments
exclude the transitional goodwill impairment loss from adoption of SFAS 142 (see
Notes 2 and 3).

The categories of impairments include:

<TABLE>
<CAPTION>
                                                              2003                    2002                          2001
                                                              ----                    ----                          ----
                                                                                  (in millions)
Asset Impairments and Other Related Charges (Pre-tax)   
-----------------------------------------------------

<C>                                                            <C>                     <C>                           <C>
AEP Coal                                                        $67                     $60                          $- 
HPL and Other                                                   315                       -                           - 
Power Generation Facility                                       258                       -                           - 
Blackhawk Coal Company                                           10                       -                           - 
Ft. Davis Wind Farm                                               -                       5                           - 
Texas Plants                                                      -                      38                           - 
Newgulf Facility                                                  -                      12                           - 
Excess Equipment                                                  -                      24                           - 
Nordic Trading                                                    -                       5                           - 
Excess Real Estate                                                -                      16                           - 
Telecommunications - AEPC/C3                                      -                     158                           -
                                                               -----                   -----                         ---
Total                                                          $650                    $318                          $-
                                                               =====                   =====                         ===


Investment Value Losses (Pre-tax)
---------------------------------
Independent Power Producers                                     $70                      $-                          $- 
Water Heater Assets                                               -                       3                           - 
South Coast Power Investment                                      -                      63                           - 
Telecommunications - AFN                                          -                      14                           - 
AEP Gas Power Systems                                             -                      12                           - 
Grupo Rede Investment - Vale                                      -                     217                           - 
Technology Investments                                            -                      12                           -
                                                               -----                   -----                         ---
Total                                                           $70                    $321                          $-
                                                               =====                   =====                         ===
</TABLE>



<TABLE>
<CAPTION>


"Impairments and Other Related Charges" and
"Operations" Included in Discontinued Operations (After-tax)
------------------------------------------------------------

Impairments and Other Related Charges:

  <C>                                                         <C>                     <C>                            <C>
  U.K. Generation Plants                                      $(375)                  $(414)                         $- 
  Louisiana Intrastate Gas                                      (99)                     -                            - 
  CitiPower                                                       -                    (122)                          - 
  Eastex                                                          -                    (142)                          - 
  SEEBOARD                                                        -                      24                           - 
  Pushan                                                          -                     (13)                          -
                                                              ------                  ------                         ---
Total*                                                         (474)                   (667)                          -
                                                              ------                  ------                         ---

Operations:

  U.K. Generation Plants                                       (132)                    (58)                        (41)
  Louisiana Intrastate Gas                                        8                       8                          (4)
  CitiPower                                                     (13)                     (1)                         (6)
  Eastex                                                        (14)                    (14)                          - 
  SEEBOARD                                                       16                      72                          88 
  Pushan                                                          4                       6                           4
                                                              ------                  ------                        ----
Total                                                          (131)                     13                          41
                                                              ------                  ------                        ----

Total Discontinued Operations                                 $(605)                  $(654)                        $41
                                                              ======                  ======                        ====
</TABLE>



* See the "Dispositions" and "Discontinued Operations" sections of this note for
  the pre-tax impairment figures.


ASSETS HELD FOR SALE
--------------------

Telecommunications (Investments - Other segment)
------------------------------------------------

We developed businesses to provide telecommunication services to businesses and
other telecommunication companies through broadband fiber optic networks. The
businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN, LLC (AFN), a joint venture. Due to the difficult
economic conditions in these businesses and the overall telecommunications
industry, the AEP Board approved in December 2002 a plan to cease operations of
these businesses. We took steps to market the assets of the businesses to
potential interested buyers in the fourth quarter of 2002.

We completed the sale of substantially all the assets of C3 in the first quarter
of 2003 as discussed in the "Dispositions" section of this note. AFN closed on
the sale of substantially all of its assets in January 2004 with no significant
additional effect on results of operations in 2004. The sale of remaining
telecommunication assets is proceeding.

An estimated pre-tax impairment loss of $158.5 million ($76.3 million related to
AEPC and $82.2 million related to C3) was recorded in December 2002 and is
classified in Asset Impairments and Other Related Charges in our Consolidated
Statements of Operations. An estimated pre-tax loss in value of the investment
in AFN of $13.8 million was recorded in December 2002 and is classified in
Investment Value Losses in our Consolidated Statements of Operations. The
estimated losses were based on indicative bids by potential buyers. Property,
Plant and Equipment, net of accumulated depreciation, of the telecommunication
businesses have been classified on our Consolidated Balance Sheets as held for
sale in 2002.

AEP Coal (Investments - Other segment)
--------------------------------------

In October 2001, we acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and renamed "AEP Coal." During 2002 the coal operations suffered from a
decline in prices and adverse mining factors resulting in significantly reduced
mine productivity and revenue. Based on an extensive review of economically
accessible reserves and other factors, future mine productivity and production
is expected to continue below historical levels. In December 2002, a
probability-weighted discounted cash flow analysis of fair value of the mines
was performed which indicated a 2002 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 and Other Related Charges on
our Consolidated Statements of Operations.

In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In the fourth quarter
of 2003, after considering the current bids and all other options, we recorded a
$66.6 million pre-tax ($43.6 million after-tax) charge comprised of a $29.4
million asset impairment, a $25.2 million charge related to accelerated
remediation cost accruals and $12 million charge (accrued at December 31, 2003)
related to a royalty agreement. These impairment losses were included in Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations. The assets and liabilities of AEP Coal that are held for sale have
been included in Assets and Liabilities Held for Sale in our Consolidated
Balance Sheets at December 31, 2003 and 2002.

Texas Plants (Utility Operations segment)
-----------------------------------------

In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired
power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted
reliability studies, which determined that seven plants (4 TCC plants and 3 TNC
plants) would be required to ensure reliability of the electricity grid. As a
result of those studies, ERCOT and AEP mutually agreed to enter into reliability
must run (RMR) agreements, which expired in December 2002, and were subsequently
renewed through December 2003. However, certain contractual provisions provided
ERCOT with a 90-day termination clause, if the contracted facility was no longer
needed to ensure reliability of the electricity grid. With ERCOT's approval, AEP
proceeded with its planned deactivation of the remaining nine plants. In August
2003, pursuant to contractual terms, ERCOT provided notification to AEP of its
intent to cancel a RMR agreement at one of the TNC plants. Upon termination of
the agreement, AEP proceeded with its planned deactivation of the plant. In
December 2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants
(4 TCC plants and 2 TNC plants) through December 2004, subject to ERCOT's 90 day
termination clause and the divestiture of the TCC facilities.

As a result of the decision to deactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments and Other Related Charges expense during the third quarter 2002 on
our Consolidated Statements of Operations. The decision to deactivate 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 our Consolidated Balance Sheets.

During the fourth quarter of 2002, evaluations continued as to whether assets
remaining at the deactivated plants, including materials, supplies and fuel oil
inventories, could be utilized elsewhere within the AEP System. As a result of
such evaluations, TNC recorded an additional asset impairment charge to Asset
Impairments and Other Related Charges expense of $3.9 million (pre-tax) in the
fourth quarter of 2002. In addition, TNC recorded related fuel inventory and
materials and supplies write-downs of $2.6 million ($1.2 million in Fuel for
Electric Generation and $1.4 million in Maintenance and Other Operation).
Similarly, TCC recorded an additional asset impairment write-down of $6.7
million (pre-tax), which was deferred and recorded in Regulatory Assets in the
fourth quarter of 2002. TCC also recorded related inventory write-downs of $14.9
million which was deferred and recorded in Regulatory Assets in the fourth
quarter 2002.

The total Texas plant asset impairment of $38.1 million pre-tax in 2002 (all
related to TNC) is included in Asset Impairments and Other Related Charges in
our Consolidated Statements of Operations.

In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either deactivated or designated as RMR status.
During the fourth quarter of 2003, after receiving bids from interested buyers,
we recorded a $938 million impairment loss and changed the classification of the
plant assets from plant in service to Assets Held for Sale. In accordance with
Texas legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires charge,
subject to the final outcome of the 2004 Texas true-up proceeding. See Texas
Restructuring section of Note 6, "Customer Choice and Industry Restructuring,"
for further discussion of the divestiture plan, anticipated timeline and true-up
proceeding.

The assets and liabilities of the entities held for sale at December 31, 2003
and 2002 are as follows:

<TABLE>
<CAPTION>

                                            Pushan          U.K.
                                             Power       Generation        AEP            Texas
                                             Plant         Plants          Coal           Plants           LIG           Total
                                           -------       ----------        ----           ------           ----          -----  
December 31, 2003  
------------------                                                       (in millions)
Assets:
<C>                                           <C>        <C>               <C>          <C>              <C>              <C>   
 Current Assets                                $24       $1,245             $6             $57            $50             $1,382
 Property, Plant and Equipment, Net            142           99             13             797            171              1,222
 Regulatory Assets                               -            -              -              49              -                 49
 Spent Nuclear Fuel and 
  Decommissioning Trusts                         -            -              -             125              -                125
 Goodwill                                        -            -              -               -             15                 15
 Long-term Risk Management Assets                -          274              -               -              -                274
 Other                                           -            6              -               -              9                 15
                                              -----      -------           ----         -------          -----            -------
 Total Assets  Held for Sale                  $166       $1,624            $19          $1,028           $245             $3,082
                                              =====      =======           ====         =======          =====            =======

Liabilities:
 Current Liabilities                           $26         $988             $-              $-            $61             $1,075
 Long-term Debt                                 20            -              -               -              -                 20
 Long-term Risk Management
  Liabilities                                    -          435              -               -              -                435
 Regulatory Liabilities and Deferred
  Investment Tax Credits                        -            -              -               9              -                  9 
 Asset Retirement Obligations and
  Nuclear Decommissioning Trusts                 -           29              -             219              -                248
 Employee Benefits and Pension
  Obligations                                    -           12              -               -              -                 12
 Deferred Credits and Other                     57            -             14               -              6                 77
                                              -----      -------           ----         -------          -----            -------
 Total Liabilities Held for Sale              $103       $1,464            $14            $228            $67             $1,876
                                              =====      =======           ====         =======          =====            =======
</TABLE>



<TABLE>
<CAPTION>


                         Pushan       U.K.                                Tele-                                  Water 
                         Power    Generation     AEP      Texas           Commun-   Nordic   Newgulf      Excess   Heater
                         Plant       Plants     Coal     Plants    LIG    ications  Trading  Facility  Equipment   Program   Total
                         -----    ----------    ----     ------    ---    --------  -------  --------  ---------   -------   -----
December 31,  2002                                                (in millions)   
------------------                                                                                      
Assets:

<C>                       <C>       <C>         <C>     <C>        <C>        <C>     <C>       <C>        <C>      <C>   <C>  
Current Assets             $19        $571        4       $ 70      $62       $-      $35       $-          $-       $1     $762 
Property, Plant and        
 Equipment, Net            132         445       38      1,647      169        6        -        6           -       38    2,481  
Spent Nuclear Fuel
 and Decommissioning         
 Trusts                      -           -        -         98        -        -        -        -           -        -       98
Goodwill                     -          11        -          -      144        -        -        -           -        -      155 
Long-term Risk
  Management Assets          -          61        -          -        -        -        5        -           -        -       66 
Other                        -          22        -          -        -        -        5        -          12        -       39
                          -----     -------     ----    -------    -----      ---     ----      ---        ----     ----  -------
Total Assets
  Held for Sale           $151      $1,110      $42     $1,815     $375       $6      $45       $6         $12      $39   $3,601
                          =====     =======     ====    =======    =====      ===     ====      ===        ====     ====  =======  

Liabilities:
Current Liabilities        $28        $992       $-         $-      $53       $-      $48       $-         $ -      $ -   $1,121 
Long-term Debt              25           -        -          -        -        -        -        -           -        -       25 
Deferred Income Taxes        -           -        -          -        -        -        -        -           -        -        -
Long-term Risk
  Management
  Liabilities                -          39        -          -        7        -        3        -           -        -       49 
Deferred Credits and
  Other                     26          24       15          9       10        -        -        -           -        -       84
                          -----     -------     ----    -------    -----      ---     ----      ---        ----     ----  -------
Total Liabilities
   Held for Sale           $79      $1,055      $15         $9      $70       $-      $51       $-          $-      $ -   $1,279  
                          =====     =======     ====    =======    =====      ===     ====      ===        ====     ====  =======  
</TABLE>



ASSETS HELD AND USED
--------------------

In 2003 and 2002, we recorded the following impairments related to assets
(including Goodwill) held and used to Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations as discussed below:

Excess Real Estate (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, TX obtained through our merger with CSW. Sale of the
facility was projected by the second quarter 2003 and an estimated pre-tax loss
on disposal of $15.7 million was recorded in 2002, based on the option sale
price. The estimated loss is included in Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations. The Property asset of $18
million in 2002 and $36 million in 2001 was previously classified on our
Consolidated Balance Sheets as held for sale.

The sale of this office building was not completed by the end of 2003 and as a
result the building no longer qualifies for held for sale status. In accordance
with SFAS 144 the building will be moved to held and used status for all periods
presented as of December 31, 2003. In December 2003 we recorded an additional
pre-tax impairment of $6 million based on bids received to date. The impairment
is recorded in Maintenance and Other Operation on our Consolidated Statements of
Operations. The building will continue to be actively marketed.

HPL and Other (Investments - Gas Operations segment)
----------------------------------------------------

HPL owns, or leases, and operates natural gas gathering, transportation and
storage operations in Texas. In 2003, management announced that we were in the
process of divesting our non-core assets, which includes the assets within our
Investments-Gas Operations segment. During the fourth quarter of 2003, based on
a probability-weighted after-tax cash flow analysis of the fair value of HPL, we
recorded an impairment of $300 million pre-tax ($218 million after-tax), with
$150 million pre-tax related to goodwill, reflecting management's decision not
to operate HPL as a major trading hub and market indicators supported by the LIG
bid process. The cash flow analysis used management's estimate of the
alternative likely outcomes of the uncertainties surrounding the continued use
of the Bammel facility and other matters (see Note 7) and an after-tax risk free
discount rate of 3.3% over the remaining life of the assets.

We also recorded a $15 million pre-tax charge ($10 million after-tax) in the
fourth quarter 2003 included in Asset Impairments and Other Related Charges on
our Consolidated Statements of Operations. This charge related to the effect of
the write-off of certain HPL and LIG assets and the impairment of goodwill
related to our former optimization strategy of LIG assets by AEP Energy
Services.

Blackhawk Coal Company (Utility Operations segment)
---------------------------------------------------

Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M and was
formerly engaged in coal mining operations until they ceased due to gas
explosions in the mine. During the fourth quarter of 2003, it was determined
that the carrying value of the investment was impaired based on an updated
valuation reflecting management's decision not to pursue development of
potential gas reserves. As a result, a $10.4 million pre-tax charge was recorded
to reduce the value of the coal and gas reserves to their estimated realizable
value. This charge was recorded in Asset Impairments and Other Related Charges
in our Consolidated Statements of Operations.

Power Generation Facility (Investments - Other segment)
-------------------------------------------------------

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).

At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation. In
the fourth quarter of 2003, we chose to not seek funding from Juniper for 
budgeted and approved pipeline construction costs related to the Facility. 
In order to continue reporting the Facility as an off-balance sheet financing,
we were required to seek funding of our construction costs from Juniper. As a
result, we recorded $496 million of construction work in progress (CWIP) and the
related financing liability for the debt and equity as of December 31, 2003. At
December 31, 2003, the lease of the Facility is reported as an owned asset under
a lease financing transaction. Since the debt obligations of the Facility are
recorded on our financial statements, the obligations under the lease agreement
are excluded from the above table of future minimum lease payments.

The current litigation between TEM and ourselves, combined with a substantial
oversupply of generation capacity in the markets where we would otherwise sell
the power freed up by TEM contract termination, triggered us to review the
project for possible impairment of its reported values. We determined that the
value of the Facility was impaired and recorded a $258 million pre-tax
impairment ($168 million after-tax) in December 2003 on the CWIP.

See further discussion in Notes 7 and 16.

INVESTMENT VALUE AND OTHER LOSSES
---------------------------------

In 2003 and 2002, we recorded the following declines in fair value on
investments:

Independent Power Producers (Investments - Other segment)
---------------------------------------------------------

During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method. Based on indicative bids, it was determined that an other than temporary
impairment existed on two of the equity investments. The impairment was the
result of the measurement of fair value that was triggered by our recent
decision to sell the assets. A $70.0 million pre-tax ($45.5 million net of tax)
loss was recorded in September 2003 as a result of an other than temporary
impairment of the equity interest. This loss of investment value is included in
Investment Value Losses on our Consolidated Statements of Operations. We have
received bids on the IPP investments and anticipate a final sale during the
first half of 2004.

South Coast Power Investment (Investments - Other segment)
----------------------------------------------------------

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 Plants above in "Discontinued Operations." 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 Losses on our
Consolidated Statements of Operations in 2002.

Technology Investments (Investments - Other segment)
----------------------------------------------------

We 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 Losses on our Consolidated Statements of
Operations.


11.  BENEFIT PLANS
------------------


In the U.S. we sponsor two qualified pension plans and two nonqualified pension
plans. A substantial majority of our employees in the U.S. are covered by either
one qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit plans are sponsored by us to provide medical and death
benefits for retired employees in the U.S.

We also have a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. The Genco pension plan had $7 million of
accumulated benefit obligations in excess of plan assets at December 31, 2002.
The plan was in an overfunded position at December 31, 2003.

The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending at
the plan's measurement date of December 31, 2003, and a statement of the funded
status as of December 31 for both years:

<TABLE>
<CAPTION>
                                                                                                        U.S.
                                                                     U.S.                        Other Post Retirement
                                                                Pension Plans                        Benefit Plans  
                                                                -------------                    ---------------------    

                                                              2003            2002              2003            2002               
                                                              ----            ----              ----            ----           
Change in Benefit Obligation:                                                     (in millions)
<C>                                                         <C>            <C>                <C>              <C>    
Obligation at January 1                                     $3,583         $3,292             $1,877           $1,645 
Service Cost                                                    80             72                 42               34 
Interest Cost                                                  233            241                130              114 
Participant Contributions                                        -              -                 14               13 
Plan Amendments                                                  -             (2)                 -                - 
Actuarial (Gain) Loss                                           91            258                192              152 
Benefit Payments                                              (299)          (278)               (92)             (81)
                                                            -------        -------           --------         --------
Obligation at December 31                                   $3,688         $3,583             $2,163           $1,877
                                                            =======        =======           ========         ========

Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1                      $2,795         $3,438               $723             $711 
Actual Return on Plan Assets                                   619           (371)               122              (57)
Company Contributions (a)                                       65              6                183              137 
Participant Contributions                                        -              -                 14               13 
Benefit Payments (a)                                          (299)          (278)               (92)             (81)
                                                            -------        -------           --------         --------
Fair Value of Plan Assets at December, 31                   $3,180         $2,795               $950             $723
                                                            =======        =======           ========         ========

Funded Status:
Funded Status at December 31                                 $(508)         $(788)           $(1,213)         $(1,154)
Unrecognized Net Transition (Asset) Obligation                   2             (7)               206              233 
Unrecognized Prior Service Cost                                (12)           (13)                 6                6 
Unrecognized Actuarial (Gain) Loss                             797          1,020                977              896
                                                            -------        -------           --------         --------
Net Asset (Liability) Recognized                              $279           $212               $(24)            $(19)
                                                            =======        =======           ========         ========
</TABLE>



(a) Our contributions and benefit payments include only those amounts
    contributed directly to or paid directly from plan assets. 

Accumulated Benefit Obligation:                           2003            2002
                                                          ----            ---- 
                                                              (in millions)
U.S. Qualified Pension Plans                             $3,549          $3,456
U.S. Nonqualified Pension Plans                              76              71


<TABLE>
<CAPTION>

                                                                                                        U.S.
                                                                    U.S.                        Other Post Retirement
                                                                Pension Plans                       Benefit Plans   
                                                            -------------------                  ------------------    
                                                            2003           2002                  2003          2002
                                                            ----           ----                  ----          ---- 
                                                                                 (in millions)
<C>                                                         <C>             <C>                 <C>             <C>  
Prepaid Benefit Costs                                       $325            $255                  $-              $-   
Accrued Benefit Liability                                    (46)            (44)                (24)            (19) 
Additional Minimum Liability                                (723)           (944)                N/A             N/A 
Unrecognized Prior Service Costs                              39              45                 N/A             N/A 
Accumulated Other Comprehensive Income                       684             900                 N/A             N/A
                                                           ------           -----               -----            ----
Net Asset (Liability) Recognized                            $279            $212                $(24)           $(19)
                                                           ======           =====               =====           =====

Increase (Decrease) in Minimum Liability
  Included in Other Comprehensive Income (Pre-tax)         $(216)           $894                 N/A             N/A
                                                           ======           =====               =====           =====
</TABLE>



        N/A = Not Applicable

The asset allocations for our U.S. pension plans at the end of 2003 and 2002,
and the target allocation for 2004, by asset category, are as follows:

<TABLE>
<CAPTION>

                                              Target Allocation           Percentage of Plan Assets at Yearend
                                              -----------------           ------------------------------------
       Asset Category                                2004                     2003                    2002
       --------------                                ----                     ----                    ----
                                                                           (in percentage)

       <C>                                            <C>                      <C>                    <C>
       Equity                                          70                       71                     67 
       Fixed Income                                    28                       27                     32 
       Cash and Cash Equivalents                        2                        2                      1
                                                      ----                     ----                   ----
       Total                                          100                      100                    100
                                                      ====                     ====                   ====
</TABLE>




The asset allocations for our U.S. other postretirement benefit plans at the 
end of 2003 and 2002, and target allocation for 2004, by asset category, are as
follows:

<TABLE>
<CAPTION>

                                              Target Allocation           Percentage of Plan Assets at Yearend
                                              -----------------           ------------------------------------   
       Asset Category                                2004                      2003                  2002
       --------------                                ----                      ----                  ----   
                                                                          (in percentage)

       <C>                                            <C>                      <C>                   <C>
       Equity                                          70                       61                    41 
       Fixed Income                                    28                       36                    38 
       Cash and Cash Equivalents                        2                        3                    21
                                                      ----                     ----                  ----
       Total                                          100                      100                   100
                                                      ====                     ====                  ====
</TABLE>




Our investment strategy for our employee benefit trust funds is to use a
diversified mixture of equity and fixed income securities to preserve the
capital of the funds and to maximize the investment earnings in excess of
inflation within acceptable levels of risk.

The value of our qualified plans' assets increased from $2.795 billion at
December 31, 2002 to $3.180 billion at December 31, 2003. The qualified plans
paid $292 million in benefits to plan participants during 2003 (nonqualified
plans paid $7 million in benefits). The status of our plans remains in an
underfunded position (plan assets are less than projected benefit obligations)
of $508 million at December 31, 2003. Due to the pension plans currently being
underfunded, we recorded income in Other Comprehensive Income (OCI) of $154
million, and a reduction in the Deferred Income Tax Asset of $76 million, offset
by a reduction to Minimum Pension Liability of $234 million and a reduction in
adjustments for unrecognized costs of $4 million. The charge to OCI does not
affect earnings or cash flow. Also, due to the current underfunded status of our
qualified plans, we expect to make cash contributions to our U.S. pension plans
of approximately $41 million in 2004.

At December 31, 2003 and 2002, the projected benefit obligation, accumulated
benefit obligation, and fair value of U.S. plan assets of the U.S. pension plans
with an accumulated benefit obligation in excess of plan assets, were as
follows:

                                                         U.S. Plans  
                                                         ----------     
End of Year                                           2003        2002   
-----------                                         --------    -------- 
                                                       (in millions)
Projected Benefit Obligation                         $3,688      $3,583  
Accumulated Benefit Obligation                        3,625       3,527  
Fair Value of Plan Assets                             3,180       2,795  
Accumulated Benefit Obligation
 Exceeds the Fair Value of Plan Assets                  445         732  

We base our determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded.

The weighted-average assumptions as of December 31, used in the measurement of
our benefit obligations are shown in the following tables:

<TABLE>
<CAPTION>
                                                                                  
                                                                                    U.S.
                                               U.S.                         Other Postretirement 
                                          Pension Plans                         Benefit Plans
                                          -------------                     -------------------- 
                                                                            
                                         2003        2002                   2003          2002 
                                         ----        ----                   ----          ----     
                                                          (in percentages)       

        <C>                              <C>         <C>                    <C>            <C> 
        Discount Rate                    6.25        6.75                   6.25           6.75
        Rate of Compensation Increase     3.7         3.7                    N/A            N/A
</TABLE>


2
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 2003, we determined that a decrease in
our discount rate from 6.75% at December 31, 2002 to 6.25% at December 31, 2003
was appropriate.

The rate of compensation increase assumed varies with the age of the employee,
ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.

Information about the expected cash flows for the U.S. pension (qualified and
non-qualified) and other postretirement benefit plans is as follows:

<TABLE>
<CAPTION>
                                                                                                U.S.
                                                                                        Other Postretirement
                                                               U.S. Pension Plans          Benefit Plans
                                                               ------------------       --------------------
                                                                              (in millions)
       <C>                                                       <C>                           <C>   
       Employer Contributions
       2003                                                      $65                           $183            
       2004 (expected)                                            41                            180      
</TABLE>

      


The table below reflects the total benefits expected to be paid from the plan or
from our assets, including both our share of the benefit cost and the
participants' share of the cost, which is funded by participant contributions to
the plan. Future benefit payments are dependent on the number of employees
retiring, whether the retiring employees elect to receive pension benefits as
annuities or as lump sum distributions, future integration of the benefit plans
with changes to Medicare and other legislation, future levels of interest rates,
and variances in actuarial results. The estimated payments for pension benefits
and other postretirement benefits are as follows:

<TABLE>
<CAPTION>

                                                                                                  U.S.
                                                                    U.S.                  Other Postretirement
                                                              Pension Benefits                Benefit Plans
                                                              ----------------            --------------------
                                                                              (in millions)
       <C>                                                          <C>                          <C>                         
       2004                                                          $293                        $106
       2005                                                           300                         114
       2006                                                           310                         123
       2007                                                           325                         132
       2008                                                           335                         140
       Years 2009 to 2013, in Total                                 1,840                         836
</TABLE>



The contribution to the pension fund is based on the minimum amount required by
the U.S. Department of Labor or the amount of the pension expense for accounting
purposes, whichever is greater. The contribution to the other postretirement
benefit plans' trusts is generally based on the amount of the other
postretirement benefit plans' expense for accounting purposes and is provided
for in agreements with state regulatory authorities.

The following table provides the components of our net periodic benefit cost
(credit) for the plans for fiscal years 2003, 2002 and 2001:

<TABLE>
<CAPTION>

                                                             U.S.                                    U.S.
                                                        Pension Plans                 Other Postretirement Benefit Plans
                                                        -------------                 -----------------------------------
                                                 2003        2002        2001            2003        2002         2001
                                                 ----        ----        ----            ----        ----         ----
                                                                             (in millions)      
       <C>                                       <C>         <C>         <C>             <C>         <C>          <C> 
       Service Cost                               $80         $72         $69             $42         $34          $30 
       Interest Cost                              233         241         232             130         114          114 
       Expected Return on Plan Assets            (318)       (337)       (338)            (64)        (62)         (61)
       Amortization of Transition
        (Asset) Obligation                         (8)         (9)         (8)             28          29           30 
       Amortization of Prior-service Cost          (1)         (1)          -               -           -            - 
       Amortization of Net Actuarial
        (Gain) Loss                                11         (10)        (24)             52          27           18
                                                 -----       -----       -----           -----       -----        -----
       Net Periodic Benefit Cost (Credit)          (3)        (44)        (69)            188         142          131 
       Curtailment Loss                             -           -           -               -           -            1
                                                 -----       -----       -----           -----       -----        -----
       Net Periodic Benefit Cost (Credit)
        After Curtailments                        $(3)       $(44)       $(69)           $188        $142         $132
                                                 =====       =====       =====           =====       =====        =====
</TABLE>



The weighted-average assumptions as of January 1, used in the measurement of our
benefit costs are shown in the following tables:

<TABLE>
<CAPTION>
                                                             U.S.                                    U.S.
                                                        Pension Plans                 Other Postretirement Benefit Plans 
                                                        -------------                 ---------------------------------- 

                                                    2003        2002        2001          2003        2002         2001
                                                    ----        ----        ----          ----        ----         ---- 
                                                                             (in percentage)
       <C>                                          <C>         <C>         <C>           <C>         <C>          <C>    
       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   
</TABLE>



The expected return on plan assets for 2003 was determined by evaluating
historical returns, the current investment climate, rate of inflation, and
current prospects for economic growth. After evaluating the current yield on
fixed income securities as well as other recent investment market indicators,
the expected return on plan assets was reduced to 8.75% for 2004. The expected
return on other postretirement benefit plan assets (a portion of which is
subject to capital gains taxes as well as Unrelated Business Income Taxes) was
reduced to 8.35%.

The assumptions used for other postretirement benefit plan measurement purposes
are shown below:

          Health Care Trend Rates:       2003             2002
                                        ------           ------
                                            (in percentage)
          Initial                         10.0            10.0 
          Ultimate                         5.0             5.0 
          Year Ultimate Reached           2008            2008 

Assumed health care cost trend rates have a significant effect on the amounts
reported for the other postretirement benefit health care plans. A 1% change in
assumed health care cost trend rates would have the following effects:

<TABLE>
<CAPTION>

                                                                      1% Increase        1% Decrease
                                                                      -----------        -----------
                                                                             (in millions)
          <C>                                                              <C>               <C>      
          Effect on Total Service and Interest Cost
           Components of Net Periodic Postretirement
           Health Care Benefit Cost                                        $26               $(21)   

          Effect on the Health Care Component of the
           Accumulated Postretirement Benefit Obligation                   315               (257)   
</TABLE>


We have not yet determined the impact of the Medicare Prescription Drug
Improvement and Modernization Act of 2003 on our other postretirement benefit
plans' accumulated benefit obligation and periodic benefit cost. See FASB Staff
Position No. 106-1 in Note 2 for additional information on the potential impact
on our results of operations, cash flows and financial condition.
 
AEP Savings Plans
-----------------

We sponsor various defined contribution retirement savings plans eligible to
substantially all non-United Mine Workers of America (UMWA) U.S. employees.
These plans include features under Section 401(k) of the Internal Revenue Code
and provide for company matching contributions. On January 1, 2003, the two
major AEP Savings Plans merged into a single plan. Beginning in 2001, and
continuing under the single merged plan, our contributions to the plans
increased from 50% to 75% of the first 6% of eligible employee compensation. The
cost for contributions to these plans totaled $57.0 million in 2003, $60.1
million in 2002 and $55.6 million in 2001.

Other UMWA Benefits
-------------------

We provide UMWA pension, health and welfare benefits for certain unionized
mining employees, retirees, and their survivors who meet eligibility
requirements. UMWA trustees make final interpretive determinations with regard
to all benefits. The pension benefits are administered by UMWA trustees and
contributions are made to their trust funds.

The health and welfare benefits are administered by us and benefits are paid
from our general assets. Contributions are expensed as paid as part of the cost
of active mining operations and were not material in 2003, 2002 and 2001.


12.  STOCK-BASED COMPENSATION
------------------------------


The American Electric Power System 2000 Long-Term Incentive Plan (the Plan)
authorizes the use of 15,700,000 shares of AEP common stock for various types of
stock-based compensation awards, including stock option awards, to key
employees. The Plan was adopted in 2000 by the Board of Directors and
shareholders.

Stock-based compensation awards granted by AEP include restricted stock units,
restricted shares, performance share units and stock options. Restricted stock
units vest, subject to the participant's continued employment, in approximately
equal 1/3 increments on January 1st for three years following the grant date.
Amounts equivalent to cash dividends on the units accrue as additional units.
AEP awarded 105,910 restricted stock units, including dividends, in 2003, with a
weighted-average grant-date fair value of $22.17 per unit. Compensation cost is
recorded over the vesting period, based on the market value on the grant date.
Expense associated with units that are forfeited is reversed in the period of
forfeiture.

AEP awarded 300,000 restricted shares in January 2004, which vest over periods
ranging from 1 to 8 years. Compensation cost will be recorded over the vesting
period based on the market value of $30.76 per unit on the grant date.

Performance share units are equal in value to shares of AEP common stock but are
subject to an attached performance factor ranging from 0% to 200%. The
performance factor is determined at the end of the performance period based on
performance measure(s) established for each grant at the beginning of the
performance period by the Human Resources Committee of the Board of Directors.
Performance share units are typically paid in cash at the end of a three-year
vesting period, unless they are needed to satisfy a participant's stock
ownership requirement, in which case they are mandatorily deferred as phantom
stock units until the end of the participants AEP career. Phantom stock units
have a value equivalent to AEP common stock and are typically paid in cash upon
the participant's termination of employment. The compensation cost for
performance share units is recorded over the vesting period and both the
performance share and phantom stock unit liability is adjusted for changes in
fair market value. Amounts equivalent to cash dividends on both performance
share and phantom stock units accrue as additional units.

Under the Plan, the exercise price of all stock option grants must equal or
exceed the market price of AEP's common stock on the date of grant, and in
accordance with its policy, AEP does not record compensation expense. AEP
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 1 following the first, second and third anniversary of the grant date.

CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into
AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP
stock option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. Outstanding CSW stock options will continue in effect until all
options are exercised, cancelled or expired. Under the CSW stock option plan,
the option price was equal to the fair market 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.

A summary of AEP stock option transactions in fiscal periods 2003, 2002 and 2001
is as follows:

<TABLE>
<CAPTION>


                                             2003                           2002                                2001   
                                 ----------------------------    ----------------------------        ----------------------------   
  
                                                     Weighted                        Weighted                            Weighted
                                                     Average                          Average                             Average
                                     Options         Exercise       Options          Exercise            Options         Exercise
                                 (in thousands)       Price      (in thousands)        Price          (in thousands)       Price  
                                 --------------    ----------    --------------     ---------        --------------     --------- 
       <C>                            <C>              <C>            <C>               <C>               <C>               <C>
       Outstanding at
        beginning of year             8,787            $34            6,822             $37               6,610             $36 
          Granted                       927            $28            2,923             $27                 645             $45 
          Exercised                     (23)           $27             (600)            $36                (216)            $38 
          Forfeited                    (597)           $33             (358)            $41                (217)            $37 
                                      ------                          ------                              ------  
       Outstanding at end of year     9,094            $33            8,787             $34               6,822             $37 
                                      ======                          ======                              ======
       Options exercisable
        at end of year                3,909            $36            2,481             $36                 395             $43 
                                      ======                          ======                              ======

       Weighted average exercise price of options:
         -Granted above Market Price                   N/A                              $27                                 N/A
         -Granted at Market Price                      $28                              $27                                 $45 
</TABLE>


 
The following table summarizes information about AEP stock options outstanding
at December 31, 2003:

<TABLE>
<CAPTION>


                     Options Outstanding  
                     -------------------             

                                                                                           
                                                                                Weighted Average         Weighted Average
        Range of Exercise Prices               Number Outstanding               Remaining Life           Exercise Price
        ------------------------               ------------------               --------------           --------------
                                                 (in thousands)                   (in years)
        <C>                                             <C>                          <C>                       <C>   
        $25.73 - $27.95                                 3,530                        9.1                       $27.28
        $34.58 - $41.50                                 5,054                        6.6                       $35.74
        $43.79 - $49.00                                   510                        7.5                       $45.98
                                                        ------

                                                        9,094                        7.6                       $33.03
                                                        ======
</TABLE>



<TABLE>
<CAPTION>
                         
                    Options Exercisable   
                    -------------------           

        Range of Exercise Prices               Number Outstanding              Weighted Average Exercise Price
        ------------------------               ------------------              -------------------------------
                                                 (in thousands)
        <C>                                           <C>                                 <C>    
        $25.73 - $27.95                                  52                               $27.06
        $34.58 - $41.50                               3,610                               $35.78
        $43.79 - $49.00                                 247                               $46.57
                                                      ------

                                                      3,909                               $36.35
                                                      ======
</TABLE>


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

The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of AEP options granted:

<TABLE>
<CAPTION>

                                                            2003               2002                 2001
                                                            ----               ----                 -----
          <C>                                              <C>                 <C>                <C>  
          Risk Free Interest Rate                            3.92%               3.53%              4.87%
          Expected Life                                    7 years             7 years            7 years
          Expected Volatility                               27.57%              29.78%             28.40%
          Expected Dividend Yield                            4.86%               6.15%              6.05%


          Weighted average fair value of options:
           -Granted above Market Price                        N/A               $4.58                N/A  
           -Granted at Market Price                         $5.26               $4.37              $8.01 
</TABLE>



13.  BUSINESS SEGMENTS
----------------------


Our segments and their related business activities are as follows:

Utility Operations
o     Domestic generation of electricity for sale to retail and wholesale
      customers
o     Domestic electricity transmission and distribution

Investments - Gas Operations*
o     Gas pipeline and storage services

Investments - UK Operations**
o     International generation of electricity for sale to wholesale customers
o     Coal procurement and transportation to AEP plants and third parties

Investments - Other
o     Coal mining, bulk commodity barging operations and other energy supply
      businesses

*  Operations of Louisiana Intrastate Gas were classified as discontinued during
   2003.
** UK Operations were classified as discontinued during 2003.

The tables below present segment information for the twelve months ended
December 31, 2003, 2002 and 2001. These amounts include certain estimates and
allocations where necessary. Prior year amounts have been reclassified to
conform to the current year's presentation.

<TABLE>
<CAPTION>

                                                          Investments
                                                 ---------------------------------
                                     Utility        Gas          UK                        All     Reconciling
                                   Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                   ----------    ----------   ----------     -----        ------   -----------    ------------
2003                                                                     (in millions)
----                                                                                  
<C>                               <C>              <C>             <C>        <C>       <C>           <C>            <C> 
Revenues from:
  External Customers              $10,871          $3,097            $-       $ 577         $-            $ -        $14,545   
  Other Operating Segments              -             192             -          96         11           (299)             -    
Discontinued Operations,
   Net of Tax                           -             (91)         (507)         (7)         -              -           (605)  
Cumulative Effect of
  Accounting Changes,
   Net of Tax                         237             (23)          (21)          -          -              -            193   
Net Income (Loss)                   1,455            (404)         (528)       (284)      (129)             -            110   
Depreciation, Depletion and
  Amortization Expense              1,241              18             -          39          1              -          1,299   
Total Assets                       30,816           2,405         1,705       1,697     14,925        (14,804)        36,744   
Assets Held for Sale                1,033             240         1,624         185          -              -          3,082   
Investments in Equity 
  Method Subsidiaries                   -              36            38          87          -              -            161   
Gross Property Additions            1,323              25             -          10          -              -          1,358   
</TABLE>



*  All Other includes interest, litigation and other miscellaneous parent
   company expenses, as well as the operations of a service company subsidiary,
   which provides services at cost to the other operating segments.

<TABLE>
<CAPTION>

                                                          Investments
                                                ----------------------------------
                                     Utility        Gas          UK                        All     Reconciling
                                   Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                   ----------    ----------   ----------     -----        ------   -----------    ------------ 
2002                                                                     (in millions)
----                                                                                  
<C>                                 <C>            <C>            <C>       <C>          <C>          <C>             <C> 
Revenues from:
  External Customers                $10,446        $2,071            $-       $791           $-           $ -         $13,308   
  Other Operating Segments                -           222             -        147           10          (379)              -    
Discontinued Operations,
  Net of Tax                              -             8          (472)      (190)           -             -            (654)  
Cumulative Effect of
  Accounting Changes,
  Net of Tax                              -             -             -       (350)           -             -            (350)  
Net Income (Loss)                     1,154           (91)         (472)    (1,062)         (48)            -            (519)  
Depreciation, Depletion and
  Amortization Expense                1,268            13             -         67            -             -           1,348   
Total Assets                         29,431         3,912         1,215      1,947       18,388       (19,003)         35,890   
Assets Held for Sale                  1,866           375         1,150        210            -             -           3,601   
Investments in Equity
  Method Subsidiaries                     -            35             -        137            -             -             172   
Gross Property Additions              1,517            47             -         25           96             -           1,685  
</TABLE>

 

* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.

<TABLE>
<CAPTION>


                                                          Investments
                                               ---------------------------------
                                  Utility        Gas           UK                        All     Reconciling
                                 Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                 ----------    ----------   ----------     -----        ------   -----------    ------------ 
2001                                                                    (in millions)
----                                                                                 
<C>                               <C>             <C>          <C>         <C>         <C>           <C>           <C>
Revenues from:
  External Customers              $10,546         $1,797        $-         $410         $-            $-           $12,753   
  Other Operating Segments              -              -         -           86          5           (91)                -    
Discontinued Operations, 
  Net of Tax                            -             (4)      (41)          86          -             -                41   
Extraordinary Items,  
  Net of Tax                          (48)             -         -            -          -             -               (48)  
Cumulative Effect,
  Net of Tax                            -              -         -           18          -             -                18   
Net Income (Loss)                     911             87       (41)          86        (72)            -               971   
Depreciation, Depletion and
  Amortization Expense              1,193             15         -           25          -             -             1,233   
Gross Property Additions            1,397             14         -          137         98             -             1,646   
</TABLE>



* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.


14.  DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS
---------------------------------------------------


DERIVATIVES AND HEDGING
-----------------------

In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. We recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income (Loss) 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 transition adjustment were designated as cash flow
hedges and relate to foreign operations.

SFAS 133 requires recognition of all derivative instruments as either assets or
liabilities in the statement of financial position at fair value. Our accounting
for the changes in the fair value of a derivative instrument depends on whether
it qualifies, and has been designated, as part of a hedging relationship and
further, on the type of hedging relationship. We designate the hedging
instrument, based on the exposure being hedged, as a fair value hedge, a cash
flow hedge or a hedge of a net investment in a foreign operation. Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in SFAS 133. These contracts are not reported
at fair value, as otherwise required by SFAS 133.

For fair value hedges (i.e. hedging the exposure to changes in the fair value of
an asset, liability or an identified portion thereof that is attributable to a
particular risk), we recognize the gain or loss on the derivative instrument as
well as the offsetting loss or gain on the hedged item associated with the
hedged risk in Revenues in the Consolidated Statement of Operations during the
period of change. For cash flow hedges (i.e. hedging the exposure to variability
in expected future cash flows that is attributable to a particular risk), we
initially report the effective portion of the gain or loss on the derivative
instrument as a component of Other Accumulated Comprehensive Income and
subsequently reclassify it to Revenues in the Consolidated Statement of
Operations when the forecasted transaction affects earnings. The remaining gain
or loss on the derivative instrument in excess of the cumulative change in the
present value of future cash flows of the hedged item, if any, is recognized
currently in Revenues during the period of change. For a hedge of a net
investment in a foreign currency, we include the effective portion of the gain
or loss in Other Accumulated Comprehensive Income as part of the cumulative
translation adjustment. We recognize any ineffective portion of the gain or loss
in Revenues immediately during the period of change.

We recognize all derivative instruments at fair value in our Consolidated
Balance Sheets as either "Risk Management Assets" or "Risk Management
Liabilities." We do not consider contracts that have been elected normal
purchase or normal sale under SFAS 133 to be derivatives. Unrealized and
realized gains and losses on all derivative instruments are ultimately included
in Revenues in the Consolidated Statement of Operations on a net basis, with the
exception of physically settled Resale Gas Contracts for the purchase of natural
gas. The unrealized and realized gains and losses on these Resale Gas Contracts
are presented as Purchased Gas for Resale in the Consolidated Statement of
Operations.

Fair Value Hedging Strategies
-----------------------------

We enter into natural gas forward and swap transactions to hedge natural gas
inventory. The purpose of the hedging activity is to protect the natural gas
inventory against changes in fair value due to changes in the spot gas prices.
During the year ended December 31, 2003, we recognized a pre-tax loss of
approximately $3.4 million within revenues related to hedge ineffectiveness and
changes in time value excluded from the assessment of hedge ineffectiveness.


We enter into interest rate forward and swap transactions for interest rate risk
exposure management purposes. The interest rate forward and swap transactions
effectively modifies our exposure to interest risk by converting a portion of
our fixed-rate debt to a floating rate. We do not hedge all interest rate
exposure.

Cash Flow Hedging Strategies
----------------------------

We enter into forward contracts to protect against the reduction in value of
forecasted cash flows resulting from transactions denominated in foreign
currencies. When the dollar strengthens significantly against the foreign
currencies, the decline in value of future foreign currency revenue is offset by
gains in the value of the forward contracts designated as cash flow hedges.
Conversely, when the dollar weakens, the increase in the value of future foreign
currency cash flows is offset by losses in the value of forward contracts. We do
not hedge all foreign currency exposure.

We enter into interest rate forward and swap transactions in order to manage
interest rate risk exposure. These transactions effectively modify our exposure
to interest risk by converting a portion of our floating-rate debt to a fixed
rate. We do not hedge all interest rate exposure.

We enter into forward and swap transactions for the purchase and sale of
electricity and natural gas to manage the variable price risk related to the
forecasted purchase and sale of electricity. We closely monitor the potential
impacts of commodity price changes and, where appropriate, enter into contracts
to protect margins for a portion of future sales and generation revenues. We do
not hedge all variable price risk exposure related to the forecasted purchase
and sale of electricity.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on
our Consolidated Balance Sheets at December 31, 2003 are:

<TABLE>
<CAPTION>
                                                                                              Portion Expected to
                                                                   Accumulated                 Be Reclassified to
                             Hedging         Hedging           Other Comprehensive              Earnings during
                             Assets        Liabilities       Income (Loss) After Tax           the Next 12 Months
                             ------        -----------       -----------------------           ------------------
                                                                   (in millions)          
<C>                            <C>          <C>                       <C>                              <C>                    
Power and Gas                  $21          $(121)                    $(65)                            $(58)                  
Interest Rate                    -             (7)                      (9)*                             (8)                  
Foreign Currency                 -            (30)                     (20)                             (20)                  
                                                                      -----                            -----
                                                                      $(94)                            $(86)                  
                                                                      =====                            =====
</TABLE>



* Includes $6 million loss recorded in an equity investment.

The net losses from cash flow hedges in Accumulated Other Comprehensive Income
(Loss) at December 31, 2003 are expected to be reclassified to net income in the
next twelve months as the items being hedged settle. The actual amounts
reclassified from AOCI to Net Income can differ as a result of market price
changes. The maximum term for which the exposure to the variability of future
cash flows is being hedged is five years.

The following table represents the activity in Accumulated Other Comprehensive
Income (Loss) for derivative contracts that qualify as cash flow hedges at
December 31, 2003:
                                                            (in millions)

  Beginning Balance, January 1, 2003                              $(16)        
  Changes in fair value                                            (79)        
  Reclasses from AOCI to net gain                                    1          
                                                                  -----
  Ending Balance, December 31, 2003                               $(94)        
                                                                  =====

Hedge of Net Investment in Foreign Operations
---------------------------------------------

In 2001 and 2002, we used foreign denominated fixed-rate debt to protect the
value of our investments in foreign subsidiaries in the U.K. Realized gains and
losses from these hedges are not included in the income statement, but are shown
in the cumulative translation adjustment account included in Other Accumulated
Comprehensive Income.

During 2002, we recognized $64 million of net losses, included in the cumulative
translation adjustment, related to the foreign denominated fixed-rate debt.

FINANCIAL INSTRUMENTS
---------------------

The fair values of Long-term Debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange.

The book values and fair values of significant financial instruments at December
31, 2003 and 2002 are summarized in the following tables.

<TABLE>
<CAPTION>

                                                   2003                                       2002  
                                       ------------------------------           ----------------------------------     

                                       Book Value          Fair Value           Book Value              Fair Value
                                       ----------          ----------           ----------              ----------
                                                (in millions)                               (in millions)

<C>                                     <C>                   <C>                 <C>                    <C>      
Long-term Debt                          $14,101               $14,621             $10,190                $10,535  
Cumulative Preferred  
 Stocks of Subsidiaries 
 Subject to Mandatory  
 Redemption*                                 76                    76                  84                     77
Trust Preferred Securities                    -                     -                 321                    324  
</TABLE>


     * See Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
       for the effect of SFAS 150 in 2003.

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value
--------------------------------------------------------------------------

The trust investments which are classified as available for sale for 
decommissioning and SNF disposal, reported in "Spent Nuclear Fuel and 
Decommissioning Trusts" and "Assets Held for Sale" on our Consolidated Balance 
Sheets, are recorded at market value in accordance with SFAS 115 "Accounting 
for Certain Investments in Debt and Equity Securities." At December 31, 2003 
and 2002, the fair values of the trust investments were $1,107 million and $969
million, respectively, and had a cost basis of $995 million and $909 million, 
respectively. The change in market value in 2003, 2002, and 2001 was a net 
unrealized holding gain of $53 million and a net unrealized holding loss of 
$33 million and $11 million, respectively.


15.  INCOME TAXES
-----------------


The details of our consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:

<TABLE>
<CAPTION>

                                                                                 Year Ended December 31,
                                                                     -----------------------------------------------
                                                                     2003                 2002                  2001
                                                                     ----                 ----                  ----
                                                                                      (in millions)                            
<C>                                                                  <C>                  <C>                   <C>    
Federal:
  Current                                                            $297                 $307                  $411 
  Deferred                                                             34                  (60)                   54
                                                                     -----                -----                 -----
Total                                                                 331                  247                   465
                                                                     -----                -----                 -----

State and Local:
  Current                                                              19                   32                    61 
  Deferred                                                              1                   28                    34
                                                                     -----                -----                 -----
Total                                                                  20                   60                    95
                                                                     -----                -----                 -----

International:
  Current                                                               7                    8                    (7)
  Deferred                                                              -                    -                     -
                                                                     -----                -----                 -----
Total                                                                   7                    8                    (7)
                                                                     -----                -----                 -----

Total Income Tax as Reported Before
 Discontinued Operations, Extraordinary Items and
 Cumulative Effect                                                   $358                 $315                  $553
                                                                     =====                =====                 =====
</TABLE>



The following is a reconciliation of our consolidated 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.

<TABLE>
<CAPTION>

                                                                                   Year Ended December 31, 
                                                                        ---------------------------------------------
                                                                           2003              2002             2001
                                                                        ---------         ---------         --------
                                                                                         (in millions)                       

<C>                                                                          <C>              <C>             <C>  
Net Income (Loss)                                                            $110             $(519)            $971 
Discontinued Operations (net of income tax of $312 million, 
 $174 million and $14 million in 2003, 2002 and 2001,
 respectively)                                                                605               654              (41) 
Extraordinary Items (net of income tax of $20 million in 
 2001)                                                                          -                 -               48
Cumulative Effect of Accounting Change
 (net of income tax of $138 million in 2003)                                 (193)              350              (18)
Preferred Stock Dividends                                                       9                11               10
                                                                             -----            ------          -------
Income Before Preferred Stock Dividends of  Subsidiaries                      531               496              970 
Income Taxes Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                                    358               315              553
                                                                             -----            ------          -------
Pre-Tax Income                                                               $889              $811           $1,523
                                                                             =====            ======          =======

Income Taxes on Pre-Tax Income at Statutory Rate (35%)                       $311              $284             $533 
Increase (Decrease) in Income Taxes Resulting from the 
 Following Items:
  Depreciation                                                                 40                32               48 
  Asset Impairments and Investment Value Losses                                23                 4                - 
  Investment Tax Credits (net)                                                (33)              (35)             (37)
  Tax Effects of International Operations                                       8                27              (22)
  Energy Production Credits                                                   (15)              (14)               - 
  State Income Taxes                                                           13                39               62 
  Other                                                                        11               (22)             (31)
                                                                             -----            ------          -------

Total Income Taxes as Reported Before
  Discontinued Operations, Extraordinary Items and
  Cumulative Effect                                                          $358              $315             $553
                                                                             =====            ======          =======

Effective Income Tax Rate                                                    40.3%             38.8%            36.3%
</TABLE>




The following table shows our elements of the net deferred tax liability and the
significant temporary differences.

<TABLE>
<CAPTION>
                                                                              As of December 31, 
                                                                         --------------------------   

                                                                            2003             2002
                                                                         -----------       --------
                                                                                (in millions)                       
<C>                                                                       <C>               <C>    
Deferred Tax Assets                                                        $3,354            $2,604 
Deferred Tax Liabilities                                                   (7,311)           (6,520)
                                                                          --------         ---------
Net Deferred Tax Liabilities                                              $(3,957)          $(3,916)
                                                                          ========          ========

Property Related Temporary Differences                                    $(2,836)          $(3,195)
Amounts Due From Customers For Future Federal
 Income Taxes                                                                (389)             (360)
Deferred State Income Taxes                                                  (416)             (422)
Transition Regulatory Assets                                                 (254)             (234)
Regulatory Assets Designated for Securitization                              (281)             (310)
Deferred Income Taxes on Other Comprehensive Loss                             306               326 
All Other (net)                                                               (87)              279
                                                                          --------          --------
Net Deferred Tax Liabilities                                              $(3,957)          $(3,916)
                                                                          ========          ========
</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.

We join in the filing of a consolidated federal income tax return with our
affiliated companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is in accordance
with SEC rules under the 1935 Act. These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to them in
determining their current tax expense. The tax loss of the System parent
company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the parent company, the method of allocation
approximates a separate return result for each company in the consolidated
group.

16.  LEASES
-----------

Leases of property, plant and equipment are for periods up to 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:

<TABLE>
<CAPTION>


                                                                             Year Ended December 31,                   
                                                         ------------------------------------------------------------
                                                              2003                   2002                     2001   
                                                         --------------         -------------             -----------
                                                                                (in millions)

<C>                                                            <C>                    <C>                      <C>     
Lease Payments on Operating Leases                             $330                   $346                     $292    
Amortization of Capital Leases                                   64                     65                       82    
Interest on Capital Leases                                        9                     14                       22    
                                                               -----                  -----                    -----

Total Lease Rental Costs                                       $403                   $425                     $396    
                                                               =====                  =====                    =====
</TABLE>




Property, plant and equipment under capital leases and related obligations 
recorded on the Consolidated Balance Sheets are as follows:

<TABLE>
<CAPTION>
                                                                             December 31,         
                                                                       ----------------------  
                                                                          2003         2002   
                                                                       ---------    ---------      
                                                                            (in millions)

<C>                                                                       <C>           <C>    
Property, Plant and Equipment Under Capital Leases
  Production                                                               $37           $40    
  Distribution                                                              15            15    
  Other                                                                    470           687    
                                                                          -----         -----
Total Property, Plant and Equipment                                        522           742    
Accumulated Amortization                                                   218           299    
                                                                          -----         -----
Net Property, Plant and Equipment Under Capital Leases                    $304          $443    
                                                                          =====         =====

Obligations Under Capital Leases:
  Noncurrent Liability                                                    $131          $170    
  Liability Due Within One Year                                             51            58    
                                                                          -----         -----
Total Obligations under Capital Leases                                    $182          $228    
                                                                          =====         =====
</TABLE>


Future minimum lease payments consisted of the following at December 31, 2003:

<TABLE>
<CAPTION>

                                                                                Noncancelable
                                                          Capital Leases       Operating Leases
                                                          --------------       ----------------
                                                                     (in millions)

<C>                                                             <C>                <C>  
2004                                                             $63                 $291 
2005                                                              43                  255 
2006                                                              34                  237 
2007                                                              31                  227 
2008                                                              18                  214 
Later Years                                                       31                2,331
                                                                -----              -------
Total Future Minimum Lease Payments                              220               $3,555
                                                                                   =======

Less Estimated Interest Element                                   38
                                                                -----
Estimated Present Value of Future
 Minimum Lease Payments                                         $182
                                                                =====
</TABLE>



Power Generation Facility
-------------------------

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. The Facility is a "qualifying cogeneration facility" for purposes of PURPA.
Construction of the Facility was begun by Katco Funding, Limited Partnership
(Katco), an unrelated unconsolidated special purpose entity. Katco assigned its
interest in the Facility to Juniper in June 2003.

Juniper is an unaffiliated limited partnership, formed to construct or otherwise
acquire real and personal property for lease to third parties, to manage
financial assets and to undertake other activities related to asset financing.
Juniper arranged to finance the Facility with debt financing up to $494 million
and equity up to $31 million from investors with no relationship to AEP or any
of AEP's subsidiaries. Juniper will own the Facility and lease it to AEP after
construction is completed.

At December 31, 2002, we would have reported the Facility and related
obligations as an operating lease upon achieving commercial operation (COD). In
the fourth quarter of 2003, we chose to not seek funding from Juniper for
budgeted and approved pipeline construction costs related to the Facility. In
order to continue reporting the Facility as an off-balance sheet financing,
we were required to seek funding of our construction costs from Juniper. As a
result, we recorded $496 million of construction work in progress (CWIP) and the
related financing liability for the debt and equity as of December 31, 2003. At
December 31, 2003, the lease of the Facility is reported as an owned asset under
a lease financing transaction. Since the debt obligations of the Facility are
recorded on our financial statements, the obligations under the lease agreement
are excluded from the above table of future minimum lease payments.

We are the construction agent for Juniper. We expect to achieve COD in the
spring of 2004, at which time the obligation to make payments under the lease
agreement will begin to accrue and we will sublease the Facility to The Dow
Chemical Company (Dow). If COD does not occur on or before March 14, 2004,
Juniper has the right to terminate the project. In the event the project is
terminated before COD, we have the option to either purchase the Facility for
100% of Juniper's acquisition cost (in general, the outstanding debt and equity
associated with the Facility) or terminate the project and make a payment to
Juniper for 89.9% of project costs (in general, the acquisition cost less
certain financing costs).

The initial term of the lease agreement between Juniper and AEP commences on COD
and continues for five years. The lease contains extension options, and if all
extension options are exercised, the total term of the lease will be 30 years.
AEP's lease payments to Juniper during the initial term and each extended term
are sufficient for Juniper to make required debt payments under Juniper's debt
financing associated with the Facility and provide a return on equity to the
investors in Juniper. We have the right to purchase the Facility for the
acquisition cost during the last month of the initial term or on any monthly
rent payment date during any extended term. In addition, we may purchase the
Facility from Juniper for the acquisition cost at any time during the initial
term if we have arranged a sale of the Facility to an unaffiliated third party.
A purchase of the Facility from Juniper by AEP should not alter Dow's rights to
lease the Facility or our contract to purchase energy from Dow. If the lease
were renewed for up to a 30-year lease term, we may further renew the lease at
fair market value subject to Juniper's approval, purchase the Facility at its
acquisition cost, or sell the Facility, on behalf of Juniper, to an independent
third party. If the Facility is sold and the proceeds from the sale are
insufficient to pay all of Juniper's acquisition costs, we may be required to
make a payment (not to exceed $396 million) to Juniper of the excess of
Juniper's acquisition costs over the proceeds from the sale, provided that we
would not be required to make any payment if we have made the additional rental
prepayment described below. We have guaranteed the performance of our
subsidiaries to Juniper during the lease term. Because we now report the debt
related to the Facility on our balance sheet, the fair value of the liability
for our guarantee (the $396 million payment discussed above) is not separately
reported.

At December 31, 2003, Juniper's acquisition costs for the Facility totaled $496
million, and total costs for the completed Facility are currently expected to be
approximately $525 million. For the 30-year extended lease term, the base lease
rental is a variable rate obligation indexed to three-month LIBOR. Consequently,
as market interest rates increase, the base rental payments under the lease will
also increase. Annual payments of approximately $18 million represent future
minimum payments for interest on Juniper's financing structure during the
initial term calculated using the indexed LIBOR rate (1.15% at December 31,
2003). An additional rental prepayment (up to $396 million) may be due on June
30, 2004 unless Juniper has refinanced its present debt financing on a long-term
basis. Juniper is currently planning to refinance by June 30, 2004. The Facility
is collateral for the debt obligation of Juniper. At December 31, 2003, we
reflected $396 million of the $496 million recorded obligation as long-term debt
due within one year. Our maximum required cash payment as a result of our
financing transaction with Juniper is $396 million as well as interest payments
during the lease term. Due to the treatment of the Facility as a financing of an
owned asset, the recorded liability of $496 million is greater than our maximum
possible cash payment obligation to Juniper.

Dow will use a portion of the energy produced by the Facility and sell the
excess energy. OPCo has agreed to purchase up to approximately 800 MW of such
excess energy from Dow. OPCo has also agreed to sell up to approximately 800 MW
of energy to Tractebel Energy Marketing, Inc. (TEM) for a period of 20 years
under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA) at a
price that is currently in excess of market. Beginning May 1, 2003, OPCo
tendered replacement capacity, energy and ancillary services to TEM pursuant to
the PPA that TEM rejected as non-conforming.

See further discussion in Notes 7 and 10.

Gavin Lease
-----------

OPCo has entered into an agreement with JMG, an unrelated 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 commercial
paper, 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. Prior to July 1, 2003, the lease was
accounted for as an operating lease. Payments under the lease agreement are
based on JMG's cost of financing (both debt and equity) and include an
amortization component plus the cost of administration. OPCo and AEP do not have
an ownership interest in JMG and do 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 on behalf of
JMG. 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 on behalf of JMG. In case of a sale at
less than the adjusted acquisition cost, OPCo must pay the difference to JMG.

On March 31, 2003, OPCo made a prepayment of $90 million under this lease
structure. AEP recognizes lease expense on a straight-line basis over the
remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The
asset will be amortized over the remaining lease term, which ends in the first
quarter of 2010.

On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon
consolidation, OPCo recorded the assets and liabilities of JMG ($469.6 million).
OPCo now records the depreciation, interest and other operating expenses of JMG
and eliminates JMG's revenues against OPCo's operating lease expenses. There was
no cumulative effect of an accounting change recorded as a result of our
requirement to consolidate JMG, and there was no change in net income due to the
consolidation of JMG. Since the debt obligations of JMG are now consolidated,
the JMG lease is no longer accounted for on a consolidated basis as an operating
lease and has been excluded from the above table of future minimum lease
payments.

Rockport Lease
--------------

AEGCo and I&M entered into a sale and leaseback transaction in 1989 with
Wilmington Trust Company (Owner Trustee) an unrelated unconsolidated trustee for
Rockport Plant Unit 2 (the plant). Owner Trustee was capitalized with equity
from six owner participants with no relationship to AEP or any of its
subsidiaries and debt from a syndicate of banks and securities in a private
placement to certain institutional investors.  The future minimum lease 
payments for each respective company are $1.4 billion.

The FASB and other accounting constituencies continue to interpret the 
application of FIN 46R.  As a result, we are continuing to review the 
application of this new interpretation as it relates to the Rockport Plant Unit
2 transaction.

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the future minimum lease payments schedule earlier in
this note. The lease term is for 33 years with potential renewal options. At the
end of the lease term, AEGCo and I&M have the option to renew the lease or the
Owner Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an ownership
interest in the Owner Trustee and do not guarantee its debt.

Railcar Lease
-------------

In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years. We intend to renew the lease for
the full twenty years.
At the end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the purchase
price amount specified in the lease, projected at the lease inception to be the
then fair market value, or (c) return the railcars and arrange a third party
sale (return-and-sale option). The lease is accounted for as an operating lease
with the future payment included in the future minimum lease payments schedule
earlier in this note. This operating lease agreement allows us to avoid a large
initial capital expenditure, and to spread our railcar costs evenly over the
expected twenty-year usage.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under
the return-and-sale option discussed above will equal at least a lessee
obligation amount specified in the lease, which declines over the term from
approximately 86% to 77% of the projected fair market value of the equipment. At
December 31, 2003, the maximum potential loss was approximately $31.5 million
($20.5 million net of tax) assuming the fair market value of the equipment is
zero at the end of the current lease term. The railcars are subleased for one
year to an unaffiliated company under an operating lease. The sublessee may
renew the lease for up to four additional one-year terms. AEP has other rail car
lease arrangements that do not utilize this type of structure.


17.  FINANCING ACTIVITIES
-------------------------


Trust Preferred Securities
--------------------------

PSO, SWEPCo and TCC have wholly-owned business trusts that have issued trust
preferred securities. The trusts which hold mandatorily redeemable trust
preferred securities were deconsolidated effective July 1, 2003 due to the
implementation of FIN 46. Therefore, $321 million ($75 million PSO, $110 million
SWEPCo and $136 million TCC), previously reported at December 31, 2002 as
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries, is now reported as two components on the Balance Sheet. The $10
million investment in the trust is now reported as Other within Other
Non-Current Assets while the $331 million of subordinated debentures are now
reported as Notes Payable to Trust within Long-term Debt.

The Junior Subordinated Debentures of PSO and TCC mature on April 30, 2037. In
October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are
now due October 1, 2043. The following Trust Preferred Securities issued by the
wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding
at December 31, 2003 and 2002:


<TABLE>
<CAPTION>
                                                                                              Amount
                                            Units                           Amount in        Reported           Description of
                                           Issued/        Amount in       Notes Payable      Prior to            Underlying
                                         Outstanding       Other            to Trust          FIN 46            Debentures of  
Business Trust       Security            at 12/31/03    at 12/31/03(a)    at 12/31/03(b)  at 12/31/02(c)         Registrant  
--------------       --------            -----------    -------------     -------------   --------------        -------------- 
                                                        (in millions)     (in millions)    (in millions)

<C>                  <C>                   <C>              <C>              <C>              <C>            <C>           
CPL Capital I        8.00%, Series A       5,450,000        $5               $141             $136           TCC, $141 million, 
                                                                                                              8.00%, Series A

PSO Capital I        8.00%, Series A       3,000,000         2                 77               75           PSO, $77 million,
                                                                                                              8.00%, Series A

SWEPCo Capital I     7.875%, Series A              -         -                  -              110           SWEPCo, $113 million,
                                                                                                              7.875%, Series A

SWEPCo Capital I     5.25%, Series B         110,000         3                113                -           SWEPCo, $113 million,
                                           -----------     ----              -----            -----           5.25% five year fixed
                                                                                                              rate period, Series B
                                                                                                              
                                                                                                          

Total                                      8,560,000       $10               $331             $321     
                                           ==========      ====              =====            =====
</TABLE>



(a) Amounts are in Other within Other Non-Current Assets.
(b) Amounts are in Notes Payable to Trust within Long-term Debt.
(c) Amounts reported on Balance Sheet prior to FIN 46.


Each of the business trusts is treated as a non-consolidated 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.

Minority Interest in Finance Subsidiary
---------------------------------------

We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was 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 for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. As managing member, SubOne consolidated Caddis. Steelhead is an
unconsolidated special purpose entity and had an original capital structure of
$750 million (currently approximately $525 million) of which 3% is equity from
investors with no relationship to us or any of our subsidiaries and 97% is debt
from a syndicate of banks. The $525 million invested in Caddis by Steelhead was
loaned to SubOne. The loan to SubOne is due August 2006. Net proceeds from the
proposed sale of LIG will be used to reduce the outstanding balance of the loan
from Caddis (see Note 10 for additional information on LIG and HPL).

On July 1, 2003, due to the application of FIN 46, we deconsolidated Caddis,
which included amounts previously reported as Minority Interest in Finance
Subsidiary ($759 million at December 31, 2002 and $533 million at June 30,
2003). As a result, a note payable to Caddis is reported as a component of
Long-term Debt ($527 million at December 31, 2003). Due to the prospective
application of FIN 46, we did not change the presentation of Minority Interest
in Finance Subsidiary in periods prior to July 1, 2003.

On May 9, 2003, SubOne borrowed $225 million from us and used the proceeds to
reduce the outstanding balance of the loan from Caddis, which Caddis used to
reduce the preferred interest held by Steelhead. This payment eliminated the
convertible preferred stock of AEP Gas Holding which under certain conditions
had been convertible to AEP common stock.

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,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of outstanding debt in excess of $50 million would
be an event of default under the credit agreement.

SubOne has deposited $422 million in a cash reserve fund in order to comply with
certain covenants in the credit agreement. Pursuant to the terms of the credit
agreement, SubOne subsequently loaned these funds to affiliates, and we
guaranteed the repayment obligations of these affiliates. These loans must be
repaid in the event our credit ratings fall below investment grade.

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. Liquidation of Caddis could negatively impact our
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 us.

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 is making quarterly interest payments on the senior notes at an initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP makes contract adjustment
payments to the purchaser at the annual rate of 3.50% on the forward purchase
contracts. The present value of the contract adjustment payments was recorded as
a $31 million liability in Equity Unit Senior Notes offset by a charge to
Paid-in Capital in June 2002. Interest payments on the senior notes are reported
as interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.

AEP applies the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that the
proceeds received as a result of the forward purchase contract are used to
repurchase outstanding shares.

Lines of Credit - AEP System
----------------------------

We use our corporate borrowing program to meet the short-term borrowing needs of
our subsidiaries. The corporate borrowing program includes a utility money pool,
which funds the utility subsidiaries, and a non-utility money pool, which funds
the majority of the non-utility subsidiaries. In addition, we also fund, as
direct borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or operational
reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion
to support our commercial paper program. At December 31, 2003, AEP had $326
million outstanding in short-term borrowings of which $282 million was
commercial paper supported by the revolving credit facilities. In addition, JMG
has commercial paper outstanding in the amount of $26 million. This commercial
paper is specifically associated with the Gavin scrubber lease identified in
Note 16 "Leases". This commercial paper does not reduce available liquidity to
AEP. The maximum amount of commercial paper outstanding during the year, which
had a weighted average interest rate during 2003 of 1.98%, was $1.5 billion
during January 2003. 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. On March 7, 2003, Standard
& Poor's Rating Services reaffirmed AEP's A-2 short-term rating for commercial
paper.

Outstanding Short-term Debt consisted of:

                                   December 31,   
                                   ------------
                                 2003        2002
                                 ----        ---- 
                                  (in millions)
Balance Outstanding:
  Notes Payable                   $18       $1,322
  Commercial Paper - AEP          282        1,417
  Commercial Paper - JMG           26            - 
                                 -----      -------
  Total                          $326       $2,739 
                                 =====      =======

Sale of Receivables - AEP Credit
--------------------------------

AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, AEP Credit sells an interest
in the receivables it acquires to the commercial paper conduits and banks and
receives cash. This transaction constitutes a sale of receivables in accordance
with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance
sheet and allowing AEP Credit to repay any debt obligations. AEP has no
ownership interest in the commercial paper conduits and does not consolidate
these entities in accordance with GAAP. We continue to service the receivables.
We entered into this off-balance sheet transaction to allow AEP Credit to repay
its outstanding debt obligations, continue to purchase the AEP operating
companies' receivables, and accelerate its cash collections.

AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 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. 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 receivable less an allowance for anticipated
uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with
certain registrant subsidiaries and, until the first quarter of 2002, with
non-affiliated companies. These subsidiaries include CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority
to sell accounts receivable in all of its regulatory jurisdictions, only a
portion of APCo's accounts receivable are sold to AEP Credit. 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:

<TABLE>
<CAPTION>
                                                                                       Year Ended December 31,
                                                                                       -----------------------
                                                                                         2003           2002 
                                                                                         ----           ----
                                                                                            (in millions)

        <C>                                                                             <C>             <C>   
        Proceeds from Sale of Accounts Receivable                                       $5,221          $5,513
        Accounts Receivable Retained Interest Less Uncollectible
         Accounts and Amounts Pledged as Collateral                                        124              76
        Deferred Revenue from Servicing Accounts Receivable                                  1               1
        Loss on Sale of Accounts Receivable                                                  7               4
        Average Variable Discount Rate                                                    1.33%           1.92%
        Retained Interest if 10% Adverse Change in Uncollectible Accounts                  122              74
        Retained Interest if 20% Adverse Change in Uncollectible Accounts                  121              72
</TABLE>



Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:

<TABLE>
<CAPTION>
                                                                                                  Face Value
                                                                                            Year Ended December 31,
                                                                                            -----------------------
                                                                                                2003       2002
                                                                                                ----       ----  
                                                                                                 (in millions)

      <C>                                                                                     <C>          <C>    
      Customer Accounts Receivable Retained                                                   $1,155       $1,553 
       Accrued Unbilled Revenues Retained                                                        596          551 
       Miscellaneous Accounts Receivable Retained                                                 83           93 
       Allowance for Uncollectible Accounts Retained                                            (124)        (108)
                                                                                              -------      -------
       Total Net Balance Sheet Accounts Receivable                                             1,710        2,089 

       Customer Accounts Receivable Securitized (Affiliate)                                      385          454
                                                                                              -------      ------
       Total Accounts Receivable Managed                                                      $2,095       $2,543
                                                                                              =======      =======

       Net Uncollectible Accounts Written Off                                                    $39          $48
                                                                                              =======      =======
</TABLE>



Customer accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit. Miscellaneous accounts receivable
have been fully retained and not securitized.

At December 31, 2003, delinquent customer accounts receivable for the electric
utility affiliates that AEP Credit currently factors was $30 million.


18.  UNAUDITED QUARTERLY FINANCIAL INFORMATION
----------------------------------------------


Our unaudited quarterly financial information is as follows:

<TABLE>
<CAPTION>

                                                                             2003 Quarterly Periods Ended    
                                                                             ----------------------------               
                                                                 March 31      June 30      September 30     December 31
                                                                 --------      -------      ------------     -----------
(In Millions - Except Per Share Amounts)  
----------------------------------------   
<C>                                                               <C>           <C>             <C>            <C>     
Revenues                                                          $3,834        $3,451          $3,940         $3,320  
Operating Income (Loss)                                              630           393             735           (126) 
Income (Loss) Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                           294           185             298           (255) 
Net Income (Loss)                                                    440           175             257           (762) 
Earnings (Loss) per Share Before Discontinued
 Operations, Extraordinary Items and Cumulative Effect*
                                                                    0.83          0.47            0.75          (0.65) 
Earnings (Loss) per Share**                                         1.24          0.44            0.65          (1.93) 

</TABLE>



<TABLE>
<CAPTION>
                                                            
                                                                              2002 Quarterly Periods Ended 
                                                                              ----------------------------                  
                                                                 March 31      June 30      September 30     December 31 
                                                                 ---------     -------      ------------     -----------
(In Millions - Except Per Share Amounts)   
----------------------------------------  
<C>                                                              <C>            <C>             <C>             <C>     
Revenues                                                         $2,802         $3,395          $3,639          $3,472  
Operating Income                                                    420            433             781             170  
Income (Loss) Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                          134            167             385            (201)
Net Income (Loss)                                                  (169)            62             425            (837)
Earnings (Loss) per Share Before Discontinued
 Operations, Extraordinary Items and Cumulative
 Effect***                                                         0.42           0.51            1.14           (0.59)
Earnings (Loss) per Share****                                     (0.53)          0.19            1.25           (2.47)
</TABLE>




* Amounts for 2003 do not add to $1.35 earnings per share before Discontinued
  Operations, Extraordinary Loss and Cumulative Effect due to rounding and the
  dilutive effect of shares issued in 2003.

** Amounts for 2003 do not add to $0.29 earnings per share due to rounding and
   the dilutive effect of shares issued in 2003.

*** Amounts for 2002 do not add to $1.46 earnings per share before Discontinued
    Operations, Extraordinary Loss and Cumulative Effect due to rounding.

**** Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.

Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative
Effect for the fourth quarter 2003 ($255 million loss) and 2002 ($201 million
loss) were significantly lower than the previous three quarters due to asset
impairments, investment value losses and other related charges. These pre-tax
writedowns ($650 million in the fourth quarter 2003 and $593 million in the
fourth quarter 2002) were made to reflect impairments and discontinued
operations as discussed in Note 10.


19.  SUBSEQUENT EVENTS (UNAUDITED)
----------------------------------

After December 31, 2003, we entered into separate agreements to dispose of the
following investments:

Investment                          Sales Price            Date of Agreement
----------                          -----------            -----------------
                                   (in millions)

Oklaunion Power Station                $42.8               January 30, 2004

LIG Pipeline and its subsidiaries      $76.2               February 13, 2004

STP                                   $332.6               February 27, 2004

We anticipate these sales to be completed during 2004 and that the impact on
results of operations will not be significant.

The Nanyang General Light (Pushan) investment was sold for $60.7 million on 
March 2, 2004.  This sale had no significant impact on our results of 
operations.         

On March 10, 2004, we entered into an agreement to sell four domestic 
Independent Power Producer (IPP) investments for a sales price of $156 million.
We anticipate this sale to be completed during 2004 and to result in a 
pre-tax gain of approximately $100 million.

<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 subsidiary companies as of December 31, 2003
and 2002, 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, 2003. 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 subsidiary companies as of December 31, 2003 and 2002,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities" effective January 1, 2003.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities" effective 
July 1, 2003.




/s/ Deloitte & Touche LLP

Columbus, Ohio
March 5, 2004




<PAGE>



MANAGEMENT'S RESPONSIBILITY
---------------------------

The management of American Electric Power Company, Inc. (the Company) 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 aud