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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)


                             AEP TEXAS NORTH COMPANY


                                       AND


                                BANK ONE, N. A.,


                                                                    


                                   AS TRUSTEE


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


                                    INDENTURE


                          Dated as of February 1, 2003


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




<PAGE>


                              CROSS-REFERENCE TABLE

    Section of
Trust Indenture Act                                               Section of
of 1939, as amended                                               Indenture

310(a)......................................................         7.09
310(b)......................................................         7.08
      ......................................................         7.10
310(c)......................................................
                                                                   Inapplicable
311(a)......................................................         7.13
311(b)......................................................         7.13
311(c)......................................................
                                                                   Inapplicable
312(a)......................................................         5.01
      ......................................................         5.02(a)
312(b)......................................................         5.02(c)
      ......................................................         5.02(d)
312(c)......................................................         5.02(e)
313(a)......................................................         5.04(a)
313(b)......................................................         5.04(b)
313(c)......................................................         5.04(a)
      ......................................................         5.04(b)
313(d)......................................................         5.04(c)
314(a)......................................................         5.03
314(b)......................................................
                                                                   Inapplicable
314(c)......................................................        13.06(a)
314(d)......................................................
                                                                   Inapplicable
314(e)......................................................        13.06(b)
314(f)......................................................
                                                                   Inapplicable
315(a)......................................................         7.01(a)
      ......................................................         7.02
315(b)......................................................         6.07
315(c)......................................................         7.01(a)
315(d)......................................................         7.01(b)
315(e)......................................................         6.08
316(a)......................................................         6.06
      ......................................................         8.04
316(b)......................................................         6.04
316(c)......................................................         8.01
317(a)......................................................         6.02
317(b)......................................................         4.03
318(a)......................................................        13.08



<PAGE>


                                TABLE OF CONTENTS

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

                                    RECITALS:

Purpose of Indenture.........................................................1
Compliance with legal requirements...........................................1
Purpose of and consideration for Indenture...................................1

ARTICLE ONE - DEFINITIONS

      Section 1.01

            Definitions......................................................2

ARTICLE TWO - ISSUE, DESCRIPTION, TERMS, EXECUTION,
REGISTRATION AND EXCHANGE OF SECURITIES

      Section 2.01
            Designation, terms, amount, authentication
            and delivery of Securities.......................................8

      Section 2.02
            Form of Security and Trustee's certificate.......................9

      Section 2.03...........................................................9
            Date and denominations of Securities,
            and provisions for payment of
 principal,
            premium and interest.............................................9

      Section 2.04
            Execution of Securities.........................................11

      Section 2.05
            Exchange of Securities..........................................12

      Section 2.06
            Temporary Securities............................................13

      Section 2.07
            Mutilated, destroyed, lost or
            stolen Securities...............................................14

      Section 2.08
            Cancellation of surrendered Securities..........................14

      Section 2.09
            Provisions of Indenture and Securities
            for sole benefit of parties and
            Securityholders.................................................15

      Section 2.10
            Appointment of Authenticating Agent.............................15

      Section 2.11
            Global Security.................................................15

      Section 2.12
            Payment in Proper Currency......................................16

      Section 2.13
            Identification of Securities....................................17

ARTICLE THREE - REDEMPTION OF SECURITIES AND
SINKING FUND PROVISIONS

      Section 3.01
            Redemption of Securities........................................17

      Section 3.02
            Notice of redemption............................................17

      Section 3.03
            When Securities called for
            redemption become due and payable...............................18

      Section 3.04
            Sinking Fund for Securities.....................................19

      Section 3.05
            Satisfaction of Sinking Fund....................................19
            Payments with Securities

      Section 3.06
            Redemption of Securities for
            Sinking Fund....................................................19

ARTICLE FOUR - PARTICULAR COVENANTS OF THE COMPANY

      Section 4.01
            Payment of principal (and premium
            if any) and interest on Securities..............................20

      Section 4.02
            Maintenance of office or agency for payment of Securities,
            designation of office or agency for payment, registration, 
            transfer and exchange of Securities.............................20

      Section 4.03
            Duties of paying agent..........................................20

      Section 4.04
            Appointment to fill vacancy in
            office of Trustee...............................................21

      Section 4.05
            Restriction on consolidation,
            merger or sale..................................................21

ARTICLE FIVE - SECURITYHOLDERS' LISTS AND REPORTS
BY THE COMPANY AND THE TRUSTEE

      Section 5.01
            Company to furnish Trustee information
            as to names and addresses of
            Securityholders.................................................21

      Section 5.02
            Trustee to preserve information
             as to names and addresses of
             Securityholders received by it
             in capacity of paying agent....................................22

      Section 5.03
            Annual and other reports to be filed
            by Company with Trustee.........................................23

      Section 5.04
            Trustee to transmit annual report
            to Securityholders..............................................24

ARTICLE SIX - REMEDIES OF THE TRUSTEE AND
SECURITYHOLDERS ON EVENT OF DEFAULT

      Section 6.01
            Events of default defined.......................................25

      Section 6.02
            Covenant of Company to pay to
            Trustee whole amount due on
            Securities on default in payment
            of interest or principal (and
            premium, if any)................................................27

      Section 6.03
            Application of monies collected by Trustee......................28

      Section 6.04
            Limitation on suits by holders of Securities....................29

      Section 6.05
            Remedies Cumulative.............................................29

      Section 6.06
            Rights of holders of majority in
            principal amount of Securities to
            direct trustee and to waive defaults............................30

      Section 6.07
            Trustees to give notice of defaults
            known to it, but may withhold in
            certain circumstances...........................................30

      Section 6.08
            Requirements of an undertaking to pay
            costs in certain suits under Indenture
            or against Trustee..............................................31

ARTICLE SEVEN - CONCERNING THE TRUSTEE

      Section 7.01
            Upon Event of Default occurring and continuing, Trustee shall
            exercise powers vested in it, and use same degree of care 
            and skill in their exercise, as prudent individual will use.....31

      Section 7.02
            Trustee may rely on documents believed
            genuine and properly signed or presented........................32


      Section 7.03
            Trustee not liable for recitals in
             Indenture or in Securities.....................................34


      Section 7.04
            Trustee, paying agent or Security
            Registrar may own Security......................................34

      Section 7.05
            Monies received by Trustee to be held
            in Trust without interest.......................................34

      Section 7.06
            Trustee entitled to compensation,
             reimbursement and indemnity....................................34


      Section 7.07
            Right of Trustee to rely on certificate
            of officers of Company where no other
            evidence specifically prescribed................................35

      Section 7.08
            Trustee acquiring conflicting interest
            to eliminate conflict or resign.................................35

      Section 7.09
            Requirements for eligibility of
            trustee.........................................................35

      Section 7.10
             Resignation of Trustee and
             appointment of successor.......................................35


      Section 7.11
            Acceptance by successor Trustee.................................37


      Section 7.12
            Successor to Trustee by merger, consolidation
            of succession to business.......................................38

      Section 7.13
            Limitations on rights of Trustee as a
            creditor to obtain payment of certain
            claims..........................................................38

ARTICLE EIGHT - CONCERNING THE SECURITYHOLDERS

      Section 8.01
            Evidence of action by Securityholders...........................38

      Section 8.02
            Proof of execution of instruments and of
            holding of Securities...........................................39

      Section 8.03
            Who may be deemed owners of Securities..........................39

      Section 8.04
            Securities owned by Company or controlled
            or controlling companies disregarded for
            certain purposes................................................39

      Section 8.05
            Instruments executed by Securityholders
            bind future holders.............................................40

ARTICLE NINE - SUPPLEMENTAL INDENTURES

      Section 9.01
            Purposes for which supplemental indenture
            may be entered into without consent of
            Securityholders.................................................40

      Section 9.02
            Modification of Indenture with consent
            of Securityholders..............................................42

      Section 9.03
            Effect of supplemental indentures...............................43

      Section 9.04
            Securities may bear notation of changes
            by supplemental indentures......................................44

      Section 9.05
            Opinion of Counsel..............................................44

ARTICLE TEN - CONSOLIDATION, MERGER AND SALE

      Section 10.01
            Consolidations or mergers of Company
            and sales or conveyances of property
            of Company permitted............................................44

      Section 10.02
            Rights and duties of successor company..........................44


      Section 10.03
            Opinion of Counsel..............................................45

ARTICLE ELEVEN - DEFEASANCE AND CONDITIONS TO DEFEASANCE; UNCLAIMED MONIES

      Section 11.01
            Defeasance and conditions to defeasance.........................45

      Section 11.02
            Application by Trustee of funds deposited
            for payment of Securities.......................................47

      Section 11.03
            Repayment of monies held by paying agent........................47

      Section 11.04
            Repayment of monies held by Trustee.............................47

      Section 11.05
            Delivery of Officer's Certificate
            and Opinion of Counsel..........................................47

ARTICLE TWELVE - IMMUNITY OF INCORPORATORS, STOCKHOLDERS,
OFFICERS AND DIRECTORS

      Section 12.01
            Incorporators, Stockholders, officers and
            directors of Company exempt from individual
            liability.......................................................47

ARTICLE THIRTEEN - MISCELLANEOUS PROVISIONS

      Section 13.01
            Successors and assigns of Company
            bound by Indenture..............................................48

      Section 13.02
            Acts of board, committee or officer
            of successor company valid......................................48

      Section 13.03
            Surrender of powers by Company..................................48

      Section 13.04
            Required notices or demands may by
            served by mail..................................................48

      Section 13.05
            Indenture and Securities to be construed
            in accordance with laws of the State
            of New York.....................................................49

      Section 13.06
            Officers' Certificate and Opinion of
            Counsel to be furnished upon applications
            or demands by company...........................................49


      Section 13.07
            Payments due on non-Business Days...............................49

      Section 13.08
            Provisions required by Trust Indenture
            Act of 1939 to control..........................................49

      Section 13.09
            Indenture may be executed in counterparts.......................49

      Section 13.10
            Separability of Indenture provisions............................49

      Section 13.11
            Assignment by Company to subsidiary.............................50

      Section 13.12
            Headings........................................................50

      Section 13.13
            Securities in Foreign Currencies................................50

ACCEPTANCE OF TRUST BY TRUSTEE..............................................51

TESTIMONIUM.................................................................51

SIGNATURES AND SEALS........................................................51

ACKNOWLEDGEMENTS............................................................52





<PAGE>

      THIS INDENTURE, dated as of the 1st day of February, 2003, between AEP
TEXAS NORTH COMPANY, a corporation duly organized and existing under the laws of
the State of Texas (hereinafter sometimes referred to as the "Company"), and
BANK ONE, N. A., a national banking association organized under the laws of the
United States, as trustee (hereinafter sometimes referred to as the "Trustee"):

      WHEREAS, for its lawful corporate purposes, the Company has duly
authorized the execution and delivery of this Indenture to provide for the
issuance of unsecured promissory notes or other evidences of indebtedness
(hereinafter referred to as the "Securities"), in an unlimited aggregate
principal amount to be issued from time to time in one or more series as in this
Indenture provided, as registered Securities without coupons, to be
authenticated by the certificate of the Trustee, and which will rank pari passu
with all other unsecured and unsubordinated debt of the Company;

      WHEREAS, to provide the terms and conditions upon which the Securities are
to be authenticated, issued and delivered, the Company has duly authorized the
execution of this Indenture;

      WHEREAS, the Securities and the certificate of authentication to be borne
by the Securities (the "Certificate of Authentication") are to be substantially
in such forms as may be approved by a Company Order (as defined below), or set
forth in this Indenture or in any indenture supplemental to this Indenture;

      AND WHEREAS, all acts and things necessary to make the Securities issued
pursuant hereto, when executed by the Company and authenticated and delivered by
the Trustee as in this Indenture provided, the valid, binding and legal
obligations of the Company, and to constitute these presents a valid indenture
and agreement according to its terms, have been done and performed or will be
done and performed prior to the issuance of such Securities, and the execution
of this Indenture has been and the issuance hereunder of the Securities has been
or will be prior to issuance in all respects duly authorized, and the Company,
in the exercise of the legal right and power in it vested, executes this
Indenture and proposes to make, execute, issue and deliver the Securities;

      NOW, THEREFORE, THIS INDENTURE WITNESSETH:

      That in order to declare the terms and conditions upon which the
Securities are and are to be authenticated, issued and delivered, and in
consideration of the premises, of the purchase and acceptance of the Securities
by the holders thereof and of the sum of one dollar ($1.00) to it duly paid by
the Trustee at the execution of these presents, the receipt whereof is hereby
acknowledged, the Company covenants and agrees with the Trustee, for the equal
and proportionate benefit (subject to the provisions of this Indenture) of the
respective holders from time to time of the Securities, without any
discrimination, preference or priority of any one Security over any other by
reason of priority in the time of issue, sale or negotiation thereof, or
otherwise, except as provided herein, as follows:

                                  ARTICLE ONE
                                   DEFINITIONS

SECTION 1.01. The terms defined in this Section (except as in this Indenture
otherwise expressly provided or unless the context otherwise requires) for all
purposes of this Indenture, any Company Order, any Board Resolution, and any
indenture supplemental hereto shall have the respective meanings specified in
this Section. All other terms used in this Indenture which are defined in the
Trust Indenture Act of 1939, as amended, or which are by reference in such Act
defined in the Securities Act of 1933, as amended (except as herein otherwise
expressly provided or unless the context otherwise requires), shall have the
meanings assigned to such terms in said Trust Indenture Act and in said
Securities Act as in force at the date of the execution of this instrument.

Affiliate:

The term "Affiliate" of the Company shall mean any company at least a majority
of whose outstanding voting stock shall at the time be owned by the Company, or
by one or more direct or indirect subsidiaries of or by the Company and one or
more direct or indirect subsidiaries of the Company. For the purposes only of
this definition of the term "Affiliate", the term "voting stock", as applied to
the stock of any company, shall mean stock of any class or classes having
ordinary voting power for the election of a majority of the directors of such
company, other than stock having such power only by reason of the occurrence of
a contingency.

Authenticating Agent:

The term "Authenticating Agent" shall mean an authenticating agent with
respect to all or any of the series of Securities, as the case may be, appointed
with respect to all or any series of the Securities, as the case may be, by the
Trustee pursuant to Section 2.10.

Authorized Officer:

The term "Authorized Officer" shall mean the Chairman of the Board, the
President, any Vice President, the Treasurer, any Assistant Treasurer or any
other officer or agent of the Company duly authorized by the Board of Directors
to act in respect of matters relating to this Indenture.

Board of Directors or Board:

The term "Board of Directors" or "Board" shall mean the Board of Directors of
the Company, or any duly authorized committee of such Board.

Board Resolution:

The term "Board Resolution" shall mean a copy of a resolution certified by the
Secretary or an Assistant Secretary of the Company to have been duly adopted by
the Board of Directors and to be in full force and effect on the date of such
certification.

Business Day:

The term "Business Day", with respect to any Security, shall mean any day that
(a) in the Place of Payment (or in any of the Places of Payment, if more than
one) in which amounts are payable as specified in the form of such Security and
(b) in the city in which the Trustee administers its corporate trust business,
is not a day on which banking institutions are authorized or required by law or
regulation to close.

Certificate:

The term "Certificate" shall mean a certificate signed by an Authorized Officer.
The Certificate need not comply with the provisions of Section 13.06.

Commission:

The term "Commission" shall mean the Securities and Exchange Commission, as from
time to time constituted, created under the Securities Exchange Act of 1934, as
amended (the "Exchange Act") or if at any time after the execution of this
instrument such Commission is not existing and performing the duties now
assigned to it under the Trust Indenture Act, then the body, if any, performing
such duties on such date.

Company:

The term "Company" shall mean AEP Texas North Company, a corporation duly
organized and existing under the laws of Texas, and, subject to the provisions
of Article Ten, shall also include its successors and assigns.

Company Order:

The term "Company Order" shall mean a written order signed in the name of the
Company by an Authorized Officer and the Secretary or an Assistant Secretary of
the Company, pursuant to a Board Resolution establishing a series of Securities.

Corporate Trust Office:

The term "Corporate Trust Office" shall mean the office of the Trustee at which
at any particular time its corporate trust business shall be principally
administered, which office at the date of the execution of this Indenture is
located at
                                                       .
Default:

The term "Default" shall mean any event, act or condition which with notice or
lapse of time, or both, would constitute an Event of Default.

Depository:

The term "Depository" shall mean, with respect to Securities of any series, for
which the Company shall determine that such Securities will be issued as a
Global Security, The Depository Trust Company, New York, New York, another
clearing agency, or any successor registered as a clearing agency under the
Exchange Act or other applicable statute or regulation, which, in each case,
shall be designated by the Company pursuant to either Section 2.01 or 2.11.

Discount Security:

The term "Discount Security" means any Security which provides for an amount
less than the principal amount thereof to be due and payable upon a declaration
of acceleration of the maturity thereof pursuant to Section 6.01(b).

Dollar:

The term "Dollar" or "$" means a dollar or other equivalent unit in such coin or
currency of the United States as at the time shall be legal tender for the
payment of public and private debts.

Eligible Obligations:

The term "Eligible Obligations" means (a) with respect to Securities denominated
in Dollars, Governmental Obligations; or (b) with respect to Securities
denominated in a currency other than Dollars or in a composite currency, such
other obligations or instruments as shall be specified with respect to such
Securities, as contemplated by Section 2.01.

Event of Default:

The term "Event of Default" with respect to Securities of a particular series
shall mean any event specified in Section 6.01, continued for the period of
time, if any, therein designated.

Global Security:

The term "Global Security" shall mean, with respect to any series of Securities,
a Security executed by the Company and authenticated and delivered by the
Trustee to the Depository or pursuant to the Depository's instruction, all in
accordance with the Indenture, which shall be registered in the name of the
Depository or its nominee.

Governmental Authority:

The term "Governmental Authority" means the government of the United States or
of any State or Territory thereof or of the District of Columbia or of any
county, municipality or other political subdivision of any of the foregoing, or
any department, agency, authority or other instrumentality of any of the
foregoing.

Governmental Obligations:

The term "Governmental Obligations" shall mean securities that are (i) direct
obligations of the United States of America for the payment of which its full
faith and credit is pledged or (ii) obligations of a person controlled or
supervised by and acting as an agency or instrumentality of the United States,
the payment of which is unconditionally guaranteed as a full faith and credit
obligation by the United States, which, in either case, are not callable or
redeemable at the option of the issuer thereof, and shall also include a
depository receipt issued by a bank (as defined in Section 3(a)(2) of the
Securities Act of 1933, as amended) as custodian with respect to any such
Governmental Obligation or a specific payment of principal of or interest on any
such Governmental Obligation held by such custodian for the account of the
holder of such depository receipt; provided that (except as required by law)
such custodian is not authorized to make any deduction from the amount payable
to the holder of such depository receipt from any amount received by such
custodian in respect of the Governmental Obligation or the specific payment of
principal of or interest on the Governmental Obligation evidenced by such
depository receipt.

Indenture:

The term "Indenture" shall mean this instrument as originally executed, or, if
amended or supplemented as herein provided, as so amended or supplemented, and
shall include the terms of a particular series of Securities established as
contemplated by Section 2.01.

Instructions:

The term "Instructions" shall mean instructions acceptable to the Trustee issued
pursuant to a Company Order in connection with a Periodic Offering and signed by
an Authorized Officer. Instructions need not comply with the provisions of
Section 13.06.

Interest:

The term "interest" when used with respect to non-interest bearing Securities
shall mean interest payable after maturity (whether at stated maturity, upon
acceleration or redemption or otherwise) or after the date, if any, on which the
Company becomes obligated to acquire a Security, whether by purchase or
otherwise.

Interest Payment Date:

The term "Interest Payment Date" when used with respect to any installment of
interest on a Security of a particular series shall mean the date specified in
such Security or in a Board Resolution, Company Order or an indenture
supplemental hereto with respect to such series as the fixed date on which an
installment of interest with respect to Securities of that series is due and
payable.

Officers' Certificate:

The term "Officers' Certificate" shall mean a certificate signed by an
Authorized Officer and by the Secretary or Assistant Secretary of the Company.
Each such certificate shall include the statements provided for in Section
13.06, if and to the extent required by the provisions thereof.

Opinion of Counsel:

The term "Opinion of Counsel" shall mean an opinion in writing signed by legal
counsel, who may be an employee of or counsel for the Company. Each such opinion
shall include the statements provided for in Section 13.06, if and to the extent
required by the provisions thereof.

Outstanding:

The term "outstanding", when used with reference to Securities of any series,
shall, subject to the provisions of Section 8.04, mean, as of any particular
time, all Securities of that series theretofore authenticated and delivered by
the Trustee under this Indenture, except (a) Securities theretofore canceled by
the Trustee or any paying agent, or delivered to the Trustee or any paying agent
for cancellation or which have previously been canceled; (b) Securities or
portions thereof for the payment or redemption of which monies or Eligible
Obligations in the necessary amount shall have been deposited in trust with the
Trustee or with any paying agent (other than the Company) or shall have been set
aside and segregated in trust by the Company (if the Company shall act as its
own paying agent); provided, however, that if such Securities or portions of
such Securities are to be redeemed prior to the maturity thereof, notice of such
redemption shall have been given as in Article Three provided, or provision
satisfactory to the Trustee shall have been made for giving such notice; and (c)
Securities in lieu of or in substitution for which other Securities shall have
been authenticated and delivered pursuant to the terms of Section 2.07. The
principal amount of a Discount Security that shall be deemed to be Outstanding
for purposes of this Indenture shall be the amount of the principal thereof that
would be due and payable as of the date of such determination upon a declaration
of acceleration of the maturity thereof.

Periodic Offering:

The term "Periodic Offering" means an offering of Securities of a series from
time to time, during which any or all of the specific terms of the Securities,
including without limitation the rate or rates of interest, if any, thereon, the
maturity or maturities thereof and the redemption provisions, if any, with
respect thereto, are to be determined by the Company or its agents upon the
issuance of such Securities.

Person:

The term "person" means any individual, corporation, partnership, limited
liability company, joint venture, trust or unincorporated organization or any
Governmental Authority.

Place of Payment:

The term "Place of Payment" shall mean the place or places where the principal
of and interest, if any, on the Securities of any series are payable as
specified in accordance with Section 2.01.

Predecessor Security:

The term "Predecessor Security" of any particular Security shall mean every
previous Security evidencing all or a portion of the same debt as that evidenced
by such particular Security; and, for the purposes of this definition, any
Security authenticated and delivered under Section 2.07 in lieu of a lost,
destroyed or stolen Security shall be deemed to evidence the same debt as the
lost, destroyed or stolen Security.

Responsible Officer:

The term "Responsible Officer" when used with respect to the Trustee shall mean
the chairman of the board of directors, the president, any vice president, the
secretary, the treasurer, any trust officer, any corporate trust officer or any
other officer or assistant officer of the Trustee customarily performing
functions similar to those performed by the persons who at the time shall be
such officers, respectively, or to whom any corporate trust matter is referred
because of his or her knowledge of and familiarity with the particular subject.

Security or Securities:

The term "Security" or "Securities" shall mean any Security or Securities, as
the case may be, authenticated and delivered under this Indenture.

Securityholder:

The term "Securityholder", "holder of Securities" or "registered holder" shall
mean the person or persons in whose name or names a particular Security shall be
registered on the books of the Company kept for that purpose in accordance with
the terms of this Indenture.

Series:

The term "series" means a series of Securities established pursuant to this
Indenture and includes, if the context so requires, each Tranche thereof.

Tranche:

The term "Tranche" means Securities which (a) are of the same series and (b)
have identical terms except as to principal amount and/or date of issuance.

Trustee:

The term "Trustee" shall mean Bank One, N. A., and, subject to the provisions of
Article Seven, shall also include its successors and assigns, and, if at any
time there is more than one person acting in such capacity hereunder, "Trustee"
shall mean each such person. The term "Trustee" as used with respect to a
particular series of the Securities shall mean the trustee with respect to that
series.

Trust Indenture Act:

The term "Trust Indenture Act", subject to the provisions of Sections 9.01,
9.02, and 10.01, shall mean the Trust Indenture Act of 1939, as amended and in
effect at the date of execution of this Indenture.

United States:

The term "United States" means the United States of America, its Territories,
its possessions and other areas subject to its political jurisdiction.

                                  ARTICLE TWO

                      ISSUE, DESCRIPTION, TERMS, EXECUTION,
                     REGISTRATION AND EXCHANGE OF SECURITIES

SECTION 2.01. The aggregate principal amount of Securities which may be
authenticated and delivered under this Indenture is unlimited.

      The Securities may be issued from time to time in one or more series and
in one or more Tranches thereof. Each series shall be authorized by a Company
Order or Orders or one or more indentures supplemental hereto, which shall
specify whether the Securities of such series shall be subject to a Periodic
Offering. The Company Order or Orders or supplemental indenture and, in the case
of a Periodic Offering, Instructions or other procedures acceptable to the
Trustee specified in such Company Order or Orders, shall establish the terms of
the series, which may include the following: (i) any limitations on the
aggregate principal amount of the Securities to be authenticated and delivered
under this Indenture as part of such series (except for Securities authenticated
and delivered upon registration of transfer of, in exchange for or in lieu of
other Securities of that series); (ii) the stated maturity or maturities of such
series; (iii) the date or dates from which interest shall accrue, the Interest
Payment Dates on which such interest will be payable or the manner of
determination of such Interest Payment Dates and the record date for the
determination of holders to whom interest is payable on any such Interest
Payment Date; (iv) the interest rate or rates (which may be fixed or variable),
or method of calculation of such rate or rates, for such series; (v) the terms,
if any, regarding the redemption, purchase or repayment of such series (whether
at the option of the Company or a holder of the Securities of such series and
whether pursuant to a sinking fund or analogous provisions, including payments
made in cash in anticipation of future sinking fund obligations), including
redemption, purchase or repayment date or dates of such series, if any, and the
price or prices and other terms and conditions applicable to such redemption,
purchase or repayment (including any premium); (vi) whether or not the
Securities of such series shall be issued in whole or in part in the form of a
Global Security and, if so, the Depositary for such Global Security and the
related procedures with respect to transfer and exchange of such Global
Security; (vii) the designation of such series; (viii) the form of the
Securities of such series; (ix) the maximum annual interest rate, if any, of the
Securities permitted for such series; (x) whether the Securities of such series
shall be subject to Periodic Offering; (xi) the currency or currencies,
including composite currencies, in which payment of the principal of (and
premium, if any) and interest on the Securities of such series shall be payable,
if other than Dollars; (xii) any other information necessary to complete the
Securities of such series; (xiii) the establishment of any office or agency
pursuant to Section 4.02 hereof and any other place or places which the
principal of and interest, if any, on Securities of that series shall be
payable; (xiv) if other than denominations of $1,000 or any integral multiple
thereof, the denominations in which the Securities of the series shall be
issuable; (xv) the obligations or instruments, if any, which shall be considered
to be Eligible Obligations in respect of the Securities of such series
denominated in a currency other than Dollars or in a composite currency; (xvi)
whether or not the Securities of such series shall be issued as Discount
Securities and the terms thereof, including the portion of the principal amount
thereof which shall be payable upon declaration of acceleration of the maturity
thereof pursuant to Section 6.01(b); (xvii) if the principal of and premium, if
any, or interest, if any, on such Securities are to be payable, at the election
of the Company or the holder thereof, in coin or currency, including composite
currencies, other than that in which the Securities are stated to be payable,
the period or periods within which, and the terms and conditions upon which,
such election shall be made; (xviii) if the amount of payment of principal of
and premium, if any, or interest, if any, on such Securities may be determined
with reference to an index, formula or other method, or based on a coin or
currency other than that in which the Securities are stated to be payable, the
manner in which such amount shall be determined; (xix) whether the provisions of
Section 4.05 and Article Ten (or portions thereof) shall apply to the Securities
of a series; and (xx)any other terms of such series not inconsistent with this
Indenture.

      All Securities of any one series shall be substantially identical except
as to denomination and except as may otherwise be provided in or pursuant to any
such Company Order or in any indentures supplemental hereto.

      If any of the terms of the series are established by action taken pursuant
to a Company Order, a copy of an appropriate record of the applicable Board
Resolution shall be certified by the Secretary or an Assistant Secretary of the
Company and delivered to the Trustee at or prior to the delivery of the Company
Order setting forth the terms of that series.

SECTION 2.02. The Securities of any series shall be substantially of the tenor
and purport (i) as set forth in one or more indentures supplemental hereto or as
provided in a Company Order, or (ii) with respect to any Tranche of Securities
of a series subject to Periodic Offering, to the extent permitted by any of the
documents referred to in clause (i) above, in Instructions, or by other
procedures acceptable to the Trustee specified in such Company Order or Orders,
in each case with such appropriate insertions, omissions, substitutions and
other variations as are required or permitted by this Indenture, and may have
such letters, numbers or other marks of identification or designation and such
legends or endorsements printed, lithographed or engraved thereon as the Company
may deem appropriate and as are not inconsistent with the provisions of this
Indenture, or as may be required to comply with any law or with any rule or
regulation made pursuant thereto or with any rule or regulation of any stock
exchange on which Securities of that series may be listed or of the Depository,
or to conform to usage.

      The Trustee's Certificate of Authentication shall be in substantially the
following form:

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

      Dated:

      BANK ONE, N. A.

      By:___________________________
         Authorized Signatory"

SECTION 2.03. The Securities shall be issuable as registered Securities and in
the denominations of $1,000 or any integral multiple thereof, subject to
Sections 2.01(xi) and (xiv). The Securities of a particular series shall bear
interest payable on the dates and at the rate or rates specified with respect to
that series. Except as otherwise specified as contemplated by Section 2.01, the
principal of and the interest on the Securities of any series, as well as any
premium thereon in case of redemption thereof prior to maturity, shall be
payable in Dollars at the office or agency of the Company maintained for that
purpose. Each Security shall be dated the date of its authentication.

      The interest installment on any Security which is payable, and is
punctually paid or duly provided for, on any Interest Payment Date for
Securities of that series shall be paid to the person in whose name said
Security (or one or more Predecessor Securities) is registered at the close of
business on the regular record date for such interest installment, except that
interest payable on redemption or maturity shall be payable as set forth in the
Company Order or indenture supplemental hereto establishing the terms of such
series of Securities. Except as otherwise specified as contemplated by Section
2.01, interest on Securities will be computed on the basis of a 360-day year of
twelve 30-day months.

      Any interest on any Security which is payable, but is not punctually paid
or duly provided for, on any Interest Payment Date for Securities of the same
series (herein called "Defaulted Interest") shall forthwith cease to be payable
to the registered holder on the relevant regular record date by virtue of having
been such holder; and such Defaulted Interest shall be paid by the Company, at
its election, as provided in clause (1) or clause (2) below:

(1)   The Company may make payment of any Defaulted Interest on Securities to
      the persons in whose names such Securities (or their respective
      Predecessor Securities) are registered at the close of business on a
      special record date for the payment of such Defaulted Interest, which
      shall be fixed in the following manner: the Company shall notify the
      Trustee in writing of the amount of Defaulted Interest proposed to be paid
      on each such Security and the date of the proposed payment, and at the
      same time the Company shall deposit with the Trustee an amount of money
      equal to the aggregate amount proposed to be paid in respect of such
      Defaulted Interest or shall make arrangements satisfactory to the Trustee
      for such deposit prior to the date of the proposed payment, such money
      when deposited to be held in trust for the benefit of the persons entitled
      to such Defaulted Interest as in this clause provided. Thereupon the
      Trustee shall fix a special record date for the payment of such Defaulted
      Interest which shall not be more than 15 nor less than 10 days prior to
      the date of the proposed payment and not less than 10 days after the
      receipt by the Trustee of the notice of the proposed payment. The Trustee
      shall promptly notify the Company of such special record date and, in the
      name and at the expense of the Company, shall cause notice of the proposed
      payment of such Defaulted Interest and the special record date therefor to
      be mailed, first class postage prepaid, to each Securityholder at his or
      her address as it appears in the Security Register (as hereinafter
      defined), not less than 10 days prior to such special record date. Notice
      of the proposed payment of such Defaulted Interest and the special record
      date therefor having been mailed as aforesaid, such Defaulted Interest
      shall be paid to the persons in whose names such Securities (or their
      respective Predecessor Securities) are registered on such special record
      date and shall be no longer payable pursuant to the following clause (2).

(2)   The Company may make payment of any Defaulted Interest on any Securities
      in any other lawful manner not inconsistent with the requirements of any
      securities exchange on which such Securities may be listed, and upon such
      notice as may be required by such exchange, if, after notice given by the
      Company to the Trustee of the proposed payment pursuant to this clause,
      such manner of payment shall be deemed practicable by the Trustee.

      Unless otherwise set forth in a Company Order or one or more indentures
supplemental hereto establishing the terms of any series of Securities pursuant
to Section 2.01 hereof, the term "regular record date" as used in this Section
with respect to a series of Securities with respect to any Interest Payment Date
for such series shall mean either the fifteenth day of the month immediately
preceding the month in which an Interest Payment Date established for such
series pursuant to Section 2.01 hereof shall occur, if such Interest Payment
Date is the first day of a month, or the last day of the month immediately
preceding the month in which an Interest Payment Date established for such
series pursuant to Section 2.01 hereof shall occur, if such Interest Payment
Date is the fifteenth day of a month, whether or not such date is a Business
Day.

      Subject to the foregoing provisions of this Section, each Security of a
series delivered under this Indenture upon transfer of or in exchange for or in
lieu of any other Security of such series shall carry the rights to interest
accrued and unpaid, and to accrue, which were carried by such other Security.

SECTION 2.04. The Securities shall, subject to the provisions of Section 2.06,
be printed on steel engraved borders or fully or partially engraved, or legibly
typed, as the proper officer of the Company may determine, and shall be signed
on behalf of the Company by an Authorized Officer. The signature of such
Authorized Officer upon the Securities may be in the form of a facsimile
signature of a present or any future Authorized Officer and may be imprinted or
otherwise reproduced on the Securities and for that purpose the Company may use
the facsimile signature of any person who shall have been an Authorized Officer,
notwithstanding the fact that at the time the Securities shall be authenticated
and delivered or disposed of such person shall have ceased to be an Authorized
Officer.

      Only such Securities as shall bear thereon a Certificate of Authentication
substantially in the form established for such Securities, executed manually by
an authorized signatory of the Trustee, or by any Authenticating Agent with
respect to such Securities, shall be entitled to the benefits of this Indenture
or be valid or obligatory for any purpose. Such certificate executed by the
Trustee, or by any Authenticating Agent appointed by the Trustee with respect to
such Securities, upon any Security executed by the Company shall be conclusive
evidence that the Security so authenticated has been duly authenticated and
delivered hereunder and that the registered holder thereof is entitled to the
benefits of this Indenture.

      At any time and from time to time after the execution and delivery of this
Indenture, the Company may deliver Securities of any series executed by the
Company to the Trustee for authentication, together with an indenture
supplemental hereto or a Company Order for the authentication and delivery of
such Securities and the Trustee, in accordance with such supplemental indenture
or Company Order, shall authenticate and deliver such Securities; provided,
however, that in the case of Securities offered in a Periodic Offering, the
Trustee shall authenticate and deliver such Securities from time to time in
accordance with Instructions or such other procedures acceptable to the Trustee
as may be specified by or pursuant to such supplemental indenture or Company
Order delivered to the Trustee prior to the time of the first authentication of
Securities of such series.

      In authenticating such Securities and accepting the additional
responsibilities under this Indenture in relation to such Securities, the
Trustee shall receive and (subject to Section 7.01) shall be fully protected in
relying upon, (i) an Opinion of Counsel and (ii) and Officers' Certificate, each
stating that the form and terms thereof have been established in conformity with
the provisions of this Indenture; provided, however, that, with respect to
Securities of a series subject to a Periodic Offering, the Trustee shall be
entitled to receive such Opinion of Counsel and Officers' Certificate only once
at or prior to the time of the first authentication of Securities of such series
and that, in such opinion or certificate, the opinion or certificate described
above may state that when the terms of such Securities, or each Tranche thereof,
shall have been established pursuant to a Company Order or Orders or pursuant to
such procedures acceptable to the Trustee, as may be specified by a Company
Order, such terms will have been established in conformity with the provisions
of this Indenture. Each Opinion of Counsel and Officers' Certificate delivered
pursuant to this Section 2.04 shall include all statements prescribed in Section
13.06(b). Such Opinion of Counsel shall also be to the effect that when such
Securities have been executed by the Company and authenticated by the Trustee in
accordance with the provisions of this Indenture and delivered to and duly paid
for by the purchasers thereof, they will be valid and legally binding
obligations of the Company, enforceable in accordance with their terms (subject
to customary exceptions) and will be entitled to the benefits of this Indenture.

      With respect to Securities of a series subject to a Periodic Offering, the
Trustee may conclusively rely, as to the authorization by the Company of any of
such Securities, the forms and terms thereof and the legality, validity, binding
effect and enforceability thereof, upon the Company Order, Opinion of Counsel,
Officers' Certificate and other documents delivered pursuant to Sections 2.01
and this Section, as applicable, at or prior to the time of the first
authentication of Securities of such series unless and until such Company Order,
Opinion of Counsel, Officers' Certificate or other documents have been
superseded or revoked or expire by their terms.

      The Trustee shall not be required to authenticate such Securities if the
issue of such Securities pursuant to this Indenture will affect the Trustee's
own rights, duties or immunities under the Securities and this Indenture or
otherwise in a manner which is not reasonably acceptable to the Trustee.

SECTION 2.05. (a) Securities of any series may be exchanged upon presentation
thereof at the office or agency of the Company designated for such purpose, for
other Securities of such series of authorized denominations, and for a like
aggregate principal amount, upon payment of a sum sufficient to cover any tax or
other governmental charge in relation thereto, all as provided in this Section.
In respect of any Securities so surrendered for exchange, the Company shall
execute, the Trustee shall authenticate and such office or agency shall deliver
in exchange therefor the Security or Securities of the same series which the
Securityholder making the exchange shall be entitled to receive, bearing numbers
not contemporaneously outstanding.

     (b) The Company  shall keep,  or cause to be kept,  at its office or agency
designated  for such purpose in the Borough of Manhattan,  the City and State of
New York,  or such  other  location  designated  by the  Company a  register  or
registers (herein referred to as the "Security  Register") in which,  subject to
such reasonable regulations as it may prescribe,  the Company shall register the
Securities and the transfers of Securities as in this Article provided and which
at all  reasonable  times  shall  be open for  inspection  by the  Trustee.  The
registrar for the purpose of  registering  Securities and transfer of Securities
as herein  provided  shall be appointed as  authorized  by Board  Resolution  or
Company Order (the "Security Registrar").

      Upon surrender for transfer of any Security at the office or agency of the
Company designated for such purpose in the Borough of Manhattan, the City and
State of New York, or other location as aforesaid, the Company shall execute,
the Trustee shall authenticate and such office or agency shall deliver in the
name of the transferee or transferees a new Security or Securities of the same
series as the Security presented for a like aggregate principal amount.

      All Securities presented or surrendered for exchange or registration of
transfer, as provided in this Section, shall be accompanied (if so required by
the Company or the Security Registrar) by a written instrument or instruments of
transfer, in form satisfactory to the Company or the Security Registrar, duly
executed by the registered holder or by his duly authorized attorney in writing.

     (c) Except as provided in the first  paragraph of Section  2.07, no service
charge shall be made for any exchange or registration of transfer of Securities,
or issue of new Securities in case of partial  redemption of any series, but the
Company  may  require  payment  of a sum  sufficient  to cover  any tax or other
governmental  charge in  relation  thereto,  other than  exchanges  pursuant  to
Section 2.06, Section 3.03(b) and Section 9.04 not involving any transfer.

     (d) The  Company  shall  neither  be  required  (i) to issue,  exchange  or
register the transfer of any Securities during a period beginning at the opening
of business 15 days before the day of the mailing of a notice of  redemption  of
less than all the  outstanding  Securities  of the same series and ending at the
close of business on the day of such mailing,  nor (ii) to register the transfer
of or exchange of any  Securities of any series or portions  thereof  called for
redemption or as to which the holder thereof has exercised its right, if any, to
require the Company to repurchase such Security in whole or in part, except that
portion of such Security not required to be repurchased.  The provisions of this
Section 2.05 are, with respect to any Global  Security,  subject to Section 2.11
hereof.

SECTION 2.06. Pending the preparation of definitive Securities of any series,
the Company may execute, and the Trustee shall authenticate and deliver,
temporary Securities (printed, lithographed or typewritten) of any authorized
denomination, and substantially in the form of the definitive Securities in lieu
of which they are issued, but with such omissions, insertions and variations as
may be appropriate for temporary Securities, all as may be determined by the
Company. Every temporary Security of any series shall be executed by the Company
and be authenticated by the Trustee upon the same conditions and in
substantially the same manner, and with like effect, as the definitive
Securities of such series in accordance with Section 2.04. Without unnecessary
delay the Company will execute and will furnish definitive Securities of such
series and thereupon any or all temporary Securities of such series may be
surrendered in exchange therefor (without charge to the holders thereof), at the
office or agency of the Company designated for the purpose, and the Trustee
shall authenticate and such office or agency shall deliver in exchange for such
temporary Securities an equal aggregate principal amount of definitive
Securities of such series, unless the Company advises the Trustee to the effect
that definitive Securities need not be executed and furnished until further
notice from the Company. Until so exchanged, the temporary Securities of such
series shall be entitled to the same benefits under this Indenture as definitive
Securities of such series authenticated and delivered hereunder.

SECTION 2.07. In case any temporary or definitive Security shall become
mutilated or be destroyed, lost or stolen, the Company (subject to the next
succeeding sentence) shall execute, and upon its request the Trustee (subject as
aforesaid) shall authenticate and deliver, a new Security of the same series
bearing a number not contemporaneously outstanding, in exchange and substitution
for the mutilated Security, or in lieu of and in substitution for the Security
so destroyed, lost or stolen. In every case the applicant for a substituted
Security shall furnish to the Company and to the Trustee such security or
indemnity as may be required by them to save each of them harmless, and, in
every case of destruction, loss or theft, the applicant shall also furnish to
the Company and to the Trustee evidence to their satisfaction of the
destruction, loss or theft of the applicant's Security and of the ownership
thereof. The Trustee may authenticate any such substituted Security and deliver
the same upon the written request or authorization of any officer of the
Company. Upon the issuance of any substituted Security, the Company may require
the payment of a sum sufficient to cover any tax or other governmental charge
that may be imposed in relation thereto and any other expenses (including the
fees and expenses of the Trustee) connected therewith. In case any Security
which has matured or is about to mature shall become mutilated or be destroyed,
lost or stolen, the Company may, instead of issuing a substitute Security, pay
or authorize the payment of the same (without surrender thereof except in the
case of a mutilated Security) if the applicant for such payment shall furnish to
the Company and to the Trustee such security or indemnity as they may require to
save them harmless, and, in case of destruction, loss or theft, evidence to the
satisfaction of the Company and the Trustee of the destruction, loss or theft of
such Security and of the ownership thereof.

      Every Security issued pursuant to the provisions of this Section in
substitution for any Security which is mutilated, destroyed, lost or stolen
shall constitute an additional contractual obligation of the Company, whether or
not the mutilated, destroyed, lost or stolen Security shall be found at any
time, or be enforceable by anyone, and shall be entitled to all the benefits of
this Indenture equally and proportionately with any and all other Securities of
the same series duly issued hereunder. All Securities shall be held and owned
upon the express condition that the foregoing provisions are exclusive with
respect to the replacement or payment of mutilated, destroyed, lost or stolen
Securities, and shall preclude (to the extent lawful) any and all other rights
or remedies, notwithstanding any law or statute existing or hereafter enacted to
the contrary with respect to the replacement or payment of negotiable
instruments or other securities without their surrender.

SECTION 2.08. All Securities surrendered for the purpose of payment, redemption,
exchange or registration of transfer, or for credit against a sinking fund,
shall, if surrendered to the Company or any paying agent, be delivered to the
Trustee for cancellation, or, if surrendered to the Trustee, shall be canceled
by it, and no Securities shall be issued in lieu thereof except as expressly
required or permitted by any of the provisions of this Indenture. On request of
the Company, the Trustee shall deliver to the Company canceled Securities held
by the Trustee. In the absence of such request the Trustee may dispose of
canceled Securities in accordance with its standard procedures. If the Company
shall otherwise acquire any of the Securities, however, such acquisition shall
not operate as a redemption or satisfaction of the indebtedness represented by
such Securities unless and until the same are delivered to the Trustee for
cancellation.

SECTION 2.09. Nothing in this Indenture or in the Securities, express or
implied, shall give or be construed to give to any person, firm or corporation,
other than the parties hereto and the holders of the Securities, any legal or
equitable right, remedy or claim under or in respect of this Indenture, or under
any covenant, condition or provision herein contained; all such covenants,
conditions and provisions being for the sole benefit of the parties hereto and
of the holders of the Securities.

SECTION 2.10. So long as any of the Securities of any series remain outstanding
there may be an Authenticating Agent for any or all such series of Securities
which the Trustee shall have the right to appoint. Said Authenticating Agent
shall be authorized to act on behalf of the Trustee to authenticate Securities
of such series issued upon exchange, transfer or partial redemption thereof, and
Securities so authenticated shall be entitled to the benefits of this Indenture
and shall be valid and obligatory for all purposes as if authenticated by the
Trustee hereunder. All references in this Indenture to the authentication of
Securities by the Trustee shall be deemed to include authentication by an
Authenticating Agent for such series except for authentication upon original
issuance or pursuant to Section 2.07 hereof. Each Authenticating Agent shall be
acceptable to the Company and shall be a corporation which has a combined
capital and surplus, as most recently reported or determined by it, sufficient
under the laws of any jurisdiction under which it is organized or in which it is
doing business to conduct a trust business, and which is otherwise authorized
under such laws to conduct such business and is subject to supervision or
examination by Federal or State authorities. If at any time any Authenticating
Agent shall cease to be eligible in accordance with these provisions it shall
resign immediately.

      Any Authenticating Agent may at any time resign by giving written notice
of resignation to the Trustee and to the Company. The Trustee may at any time
(and upon request by the Company shall) terminate the agency of any
Authenticating Agent by giving written notice of termination to such
Authenticating Agent and to the Company. Upon resignation, termination or
cessation of eligibility of any Authenticating Agent, the Trustee may appoint an
eligible successor Authenticating Agent acceptable to the Company. Any successor
Authenticating Agent, upon acceptance of its appointment hereunder, shall become
vested with all the rights, powers and duties of its predecessor hereunder as if
originally named as an Authenticating Agent pursuant hereto. The Company agrees
to pay to each Authenticating Agent from time to time reasonable compensation
for its services under this Section.

SECTION 2.11. (a) If the Company shall establish pursuant to Section 2.01 that
the Securities of a particular series are to be issued as a Global Security,
then the Company shall execute and the Trustee shall, in accordance with Section
2.04, authenticate and deliver, a Global Security which (i) shall represent, and
shall be denominated in an amount equal to the aggregate principal amount of,
all of the Outstanding Securities of such series, (ii) shall be registered in
the name of the Depository or its nominee, (iii) shall be authenticated and
delivered by the Trustee to the Depository or pursuant to the Depository's
instruction and (iv) shall bear a legend substantially to the following effect:
"Except as otherwise provided in Section 2.11 of the Indenture, this Security
may be transferred, in whole but not in part, only to another nominee of the
Depository or to a successor Depository or to a nominee of such successor
Depository."

     (b)  Notwithstanding the provisions of Section 2.05, the Global Security of
a series may be transferred, in whole but not in part and in the manner provided
in Section 2.05, only to another  nominee of the Depository for such series,  or
to a successor Depository for such series selected or approved by the Company or
to a nominee of such successor Depository.

     (c) If at any time the Depository  for a series of Securities  notifies the
Company that it is unwilling or unable to continue as Depository for such series
or if at any time the  Depository  for such series shall no longer be registered
or in good  standing  under the  Exchange  Act, or other  applicable  statute or
regulation  and a successor  Depository  for such series is not appointed by the
Company  within 90 days after the Company  receives such notice or becomes aware
of such  condition,  as the case may be,  this  Section  2.11 shall no longer be
applicable to the  Securities  of such series and the Company will execute,  and
subject to Section 2.05, the Trustee will authenticate and deliver Securities of
such  series in  definitive  registered  form  without  coupons,  in  authorized
denominations,  and in an  aggregate  principal  amount  equal to the  principal
amount of the  Global  Security  of such  series  in  exchange  for such  Global
Security. In addition, the Company may at any time determine that the Securities
of any series shall no longer be represented  by a Global  Security and that the
provisions of this Section 2.11 shall no longer apply to the  Securities of such
series. In such event the Company will execute, and subject to Section 2.05, the
Trustee, upon receipt of an Officers' Certificate  evidencing such determination
by the  Company,  will  authenticate  and deliver  Securities  of such series in
definitive registered form without coupons, in authorized denominations,  and in
an  aggregate  principal  amount  equal to the  principal  amount of the  Global
Security of such series in exchange for such Global Security.  Upon the exchange
of the Global Security for such Securities in definitive registered form without
coupons, in authorized  denominations,  the Global Security shall be canceled by
the Trustee.  Such  Securities in definitive  registered form issued in exchange
for the Global Security  pursuant to this Section 2.11(c) shall be registered in
such names and in such authorized  denominations as the Depository,  pursuant to
instructions  from its  direct or  indirect  participants  or  otherwise,  shall
instruct the Security  Registrar.  The Trustee shall deliver such  Securities to
the Depository for delivery to the persons in whose names such Securities are so
registered.

SECTION 2.12. In the case of the Securities of any series denominated in any
currency other than Dollars or in a composite currency (the "Required
Currency"), except as otherwise specified with respect to such Securities as
contemplated by Section 2.01, the obligation of the Company to make any payment
of the principal thereof, or the premium or interest thereon, shall not be
discharged or satisfied by any tender by the Company, or recovery by the
Trustee, in any currency other than the Required Currency, except to the extent
that such tender or recovery shall result in the Trustee timely holding the full
amount of the Required Currency then due and payable. If any such tender or
recovery is in a currency other than the Required Currency, the Trustee may take
such actions as it considers appropriate to exchange such currency for the
Required Currency. The costs and risks of any such exchange, including, without
limitation, the risks of delay and exchange rate fluctuation, shall be borne by
the Company, the Company shall remain fully liable for any shortfall or
delinquency in the full amount of Required Currency then due and payable, and in
no circumstances shall the Trustee be liable therefor except in the case of its
negligence or willful misconduct.

SECTION 2.13. The Company in issuing Securities may use "CUSIP" numbers (if then
generally in use) and, if so used, the Trustee shall use "CUSIP" numbers in
notices of redemption as a convenience to holders of Securities; provided that
any such notice may state that no representation is made as to the correctness
of such numbers either as printed on the Securities or contained in any notice
of redemption and that reliance may be placed only on the other identification
numbers printed on the Securities, and any such redemption shall not be affected
by any defect in or omission of such numbers. The Company shall promptly notify
the Trustee of any change in the CUSIP numbers.

ARTICLE Three
                    REDEMPTION OF SECURITIES AND SINKING FUND PROVISIONS

SECTION 3.01. The Company may redeem the Securities of any series issued
hereunder on and after the dates and in accordance with the terms established
for such series pursuant to Section 2.01 hereof.

SECTION 3.02. (a) In case the Company shall desire to exercise such right to
redeem all or, as the case may be, a portion of the Securities of any series in
accordance with the right reserved so to do, it shall give notice of such
redemption to holders of the Securities of such series to be redeemed by
mailing, first class postage prepaid, a notice of such redemption not less than
30 days and not more than 60 days before the date fixed for redemption of that
series to such holders at their last addresses as they shall appear upon the
Security Register. Any notice which is mailed in the manner herein provided
shall be conclusively presumed to have been duly given, whether or not the
registered holder receives the notice. In any case, failure duly to give such
notice to the holder of any Security of any series designated for redemption in
whole or in part, or any defect in the notice, shall not affect the validity of
the proceedings for the redemption of any other Securities of such series or any
other series. In the case of any redemption of Securities prior to the
expiration of any restriction on such redemption or subject to compliance with
certain conditions provided in the terms of such Securities or elsewhere in this
Indenture, the Company shall furnish the Trustee with an Officers' Certificate
evidencing compliance with any such restriction or condition.

      Unless otherwise so provided as to a particular series of Securities, if
at the time of mailing of any notice of redemption the Company shall not have
deposited with the paying agent an amount in cash sufficient to redeem all of
the Securities called for redemption, including accrued interest to the date
fixed for redemption, such notice shall state that it is subject to the receipt
of redemption moneys by the paying agent on or before the date fixed for
redemption (unless such redemption is mandatory) and such notice shall be of no
effect unless such moneys are so received on or before such date.

      Each such notice of redemption shall identify the Securities to be
redeemed (including CUSIP numbers, if any), specify the date fixed for
redemption and the redemption price at which Securities of that series are to be
redeemed, and shall state that payment of the redemption price of such
Securities to be redeemed will be made at the office or agency of the Company,
upon presentation and surrender of such Securities, that interest accrued to the
date fixed for redemption will be paid as specified in said notice, that from
and after said date interest will cease to accrue and that the redemption is for
a sinking fund, if such is the case. If less than all the Securities of a series
are to be redeemed, the notice to the holders of Securities of that series to be
redeemed in whole or in part shall specify the particular Securities to be so
redeemed. In case any Security is to be redeemed in part only, the notice which
relates to such Security shall state the portion of the principal amount thereof
to be redeemed, and shall state that on and after the redemption date, upon
surrender of such Security, a new Security or Securities of such series in
principal amount equal to the unredeemed portion thereof will be issued.

     (b) If less than all the  Securities  of a series are to be  redeemed,  the
Company  shall give the Trustee at least 45 days'  notice in advance of the date
fixed for redemption  (unless the Trustee shall agree to a shorter period) as to
the aggregate  principal amount of Securities of the series to be redeemed,  and
thereupon the Trustee  shall select,  by lot or in such other manner as it shall
deem  appropriate  and fair in its  discretion  and  which may  provide  for the
selection  of a portion or portions  (equal to $1,000 or any  integral  multiple
thereof, subject to Sections 2.01(xi) and (xiv)) of the principal amount of such
Securities of a  denomination  larger than $1,000  (subject as  aforesaid),  the
Securities to be redeemed and shall  thereafter  promptly  notify the Company in
writing of the numbers of the Securities to be redeemed, in whole or in part.

      The Company may, if and whenever it shall so elect, by delivery of
instructions signed on its behalf by an Authorized Officer, instruct the Trustee
or any paying agent to call all or any part of the Securities of a particular
series for redemption and to give notice of redemption in the manner set forth
in this Section, such notice to be in the name of the Company or its own name as
the Trustee or such paying agent may deem advisable. In any case in which notice
of redemption is to be given by the Trustee or any such paying agent, the
Company shall deliver or cause to be delivered to, or permit to remain with, the
Trustee or such paying agent, as the case may be, such Security Register,
transfer books or other records, or suitable copies or extracts therefrom,
sufficient to enable the Trustee or such paying agent to give any notice by mail
that may be required under the provisions of this Section.

SECTION 3.03. (a) If the giving of notice of redemption shall have been
completed as above provided, the Securities or portions of Securities of the
series to be redeemed specified in such notice shall become due and payable on
the date and at the place stated in such notice at the applicable redemption
price, together with, subject to the Company Order or supplemental indenture
hereto establishing the terms of such series of Securities, interest accrued to
the date fixed for redemption and interest on such Securities or portions of
Securities shall cease to accrue on and after the date fixed for redemption,
unless the Company shall default in the payment of such redemption price and
accrued interest with respect to any such Security or portion thereof. On
presentation and surrender of such Securities on or after the date fixed for
redemption at the place of payment specified in the notice, said Securities
shall be paid and redeemed at the applicable redemption price for such series,
together with, subject to the Company Order or supplemental indenture hereto
establishing the terms of such series of Securities, interest accrued thereon to
the date fixed for redemption.

     (b)  Upon  presentation  of any  Security  of such  series  which  is to be
redeemed  in  part  only,  the  Company  shall  execute  and the  Trustee  shall
authenticate  and the office or agency  where the  Security is  presented  shall
deliver to the holder thereof,  at the expense of the Company, a new Security or
Securities of the same series,  of authorized  denominations in principal amount
equal to the unredeemed portion of the Security so presented.

SECTION 3.04. The provisions of this Section 3.04 and Sections 3.05 and 3.06
shall be applicable to any sinking fund for the retirement of Securities of a
series, except as otherwise specified as contemplated by Section 2.01 for
Securities of such series.

      The minimum amount of any sinking fund payment provided for by the terms
of Securities of any series is herein referred to as a "mandatory sinking fund
payment", and any payment in excess of such minimum amount provided for by the
terms of Securities of any series is herein referred to as an "optional sinking
fund payment". If provided for by the terms of Securities of any series, the
cash amount of any sinking fund payment may be subject to reduction as provided
in Section 3.05. Each sinking fund payment shall be applied to the redemption of
Securities of such series as provided for by the terms of Securities of such
series.

SECTION 3.05. The Company (i) may deliver Outstanding Securities of a series
(other than any previously called for redemption) and (ii) may apply as a credit
Securities of a series which have been redeemed either at the election of the
Company pursuant to the terms of such Securities or through the application of
permitted optional sinking fund payments pursuant to the terms of such
Securities, in each case in satisfaction of all or any part of any mandatory
sinking fund payment; provided that such Securities have not been previously so
credited. Such Securities shall be received and credited for such purpose by the
Trustee at the redemption price specified in such Securities for redemption
through operation of the mandatory sinking fund and the amount of such mandatory
sinking fund payment shall be reduced accordingly.

SECTION 3.06. Not less than 45 days prior to each sinking fund payment date for
any series of Securities, the Company will deliver to the Trustee an Officers'
Certificate specifying the amount of the next ensuing sinking fund payment for
that series pursuant to the terms of that series, the portion thereof, if any,
which is to be satisfied by delivering and crediting Securities of that series
pursuant to Section 3.05 and the basis for such credit and will, together with
such Officers' Certificate, deliver to the Trustee any Securities to be so
delivered. Not less than 30 days before each such sinking fund payment date the
Trustee shall select the Securities to be redeemed upon such sinking fund
payment date in the manner specified in Section 3.02 and cause notice of the
redemption thereof to be given in the name of and at the expense of the Company
in the manner provided in Section 3.02, except that the notice of redemption
shall also state that the Securities of such series are being redeemed by
operation of the sinking fund and the sinking fund payment date. Such notice
having been duly given, the redemption of such Securities shall be made upon the
terms and in the manner stated in Section 3.03.

                                  ARTICLE FOUR
                       PARTICULAR COVENANTS OF THE COMPANY

      The Company covenants and agrees for each series of the Securities as
follows:

SECTION 4.01. The Company will duly and punctually pay or cause to be paid the
principal of (and premium, if any) and interest on the Securities of that series
at the time and place and in the manner provided herein and established with
respect to such Securities.

SECTION 4.02. So long as any series of the Securities remain outstanding, the
Company agrees to maintain an office or agency with respect to each such series,
which shall be in the Borough of Manhattan, the City and State of New York or at
such other location or locations as may be designated as provided in this
Section 4.02, where (i) Securities of that series may be presented for payment,
(ii) Securities of that series may be presented as hereinabove authorized for
registration of transfer and exchange, and (iii) notices and demands to or upon
the Company in respect of the Securities of that series and this Indenture may
be given or served, such designation to continue with respect to such office or
agency until the Company shall, by written notice signed by an Authorized
Officer and delivered to the Trustee, designate some other office or agency for
such purposes or any of them. If at any time the Company shall fail to maintain
any such required office or agency or shall fail to furnish the Trustee with the
address thereof, such presentations, notices and demands may be made or served
at the Corporate Trust Office of the Trustee, and the Company hereby appoints
the Trustee as its agent to receive all such presentations, notices and demands.
The Trustee will initially act as paying agent for the Securities.

      The Company may also from time to time, by written notice signed by an
Authorized Officer and delivered to the Trustee, designate one or more other
offices or agencies for the foregoing purposes within or outside the Borough of
Manhattan, City of New York, and may from time to time rescind such
designations; provided, however, that no such designation or rescission shall in
any manner relieve the Company of its obligations to maintain an office or
agency in the Borough of Manhattan, City of New York for the foregoing purposes.
The Company will give prompt written notice to the Trustee of any change in the
location of any such other office or agency.

SECTION 4.03. (a) If the Company shall appoint one or more paying agents for all
or any series of the Securities, other than the Trustee, the Company will cause
each such paying agent to execute and deliver to the Trustee an instrument in
which such agent shall agree with the Trustee, subject to the provisions of this
Section:

     (1)  that it will hold all sums held by it as such agent for the payment of
          the principal of (and premium,  if any) or interest on the  Securities
          of that series  (whether such sums have been paid to it by the Company
          or by any other obligor of such  Securities)  in trust for the benefit
          of the persons entitled thereto;

     (2)  that it will give the Trustee notice of any failure by the Company (or
          by any other  obligor of such  Securities)  to make any payment of the
          principal of (and  premium,  if any) or interest on the  Securities of
          that series when the same shall be due and payable;

     (3)  that it will,  at any  time  during  the  continuance  of any  failure
          referred to in the preceding  paragraph (a)(2) above, upon the written
          request of the Trustee,  forthwith pay to the Trustee all sums so held
          in trust by such paying agent; and

     (4)  that it will  perform all other duties of paying agent as set forth in
          this Indenture.

     (b) If the Company  shall act as its own paying  agent with  respect to any
series of the Securities, it will on or before each due date of the principal of
(and  premium,  if any) or interest on  Securities  of that  series,  set aside,
segregate  and hold in trust for the benefit of the persons  entitled  thereto a
sum  sufficient  to pay such  principal  (and  premium,  if any) or  interest so
becoming due on  Securities of that series until such sums shall be paid to such
persons or otherwise disposed of as herein provided and will promptly notify the
Trustee  of such  action,  or any  failure  (by it or any other  obligor on such
Securities)  to take such action.  Whenever  the Company  shall have one or more
paying agents for any series of Securities,  it will,  prior to each due date of
the  principal of (and  premium,  if any) or interest on any  Securities of that
series, deposit with the paying agent a sum sufficient to pay the principal (and
premium,  if any) or interest so becoming  due, such sum to be held in trust for
the benefit of the persons entitled to such principal,  premium or interest, and
(unless such paying agent is the Trustee) the Company will  promptly  notify the
Trustee of its action or failure so to act.

     (c)  Anything  in this  Section to the  contrary  notwithstanding,  (i) the
agreement  to hold sums in trust as provided  in this  Section is subject to the
provisions  of Section  11.04,  and (ii) the  Company  may at any time,  for the
purpose of obtaining the satisfaction and discharge of this Indenture or for any
other  purpose,  pay, or direct any paying agent to pay, to the Trustee all sums
held in trust by the Company or such paying  agent,  such sums to be held by the
Trustee  upon the same terms and  conditions  as those upon which such sums were
held by the Company or such paying  agent;  and, upon such payment by any paying
agent to the  Trustee,  such paying  agent  shall be  released  from all further
liability with respect to such money.

SECTION 4.04. The Company, whenever necessary to avoid or fill a vacancy in the
office of Trustee, will appoint, in the manner provided in Section 7.10, a
Trustee, so that there shall at all times be a Trustee hereunder.

SECTION 4.05. Unless a Company Order or supplemental indenture establishing the
series of Securities provides otherwise, the Company will not, while any of the
Securities remain outstanding, consolidate with, or merge into, or merge into
itself, or sell or convey all or substantially all of its property to any other
Person unless the provisions of Article Ten hereof are complied with.

                                  ARTICLE FIVE
                SECURITYHOLDERS' LISTS AND REPORTS BY THE COMPANY
                                 AND THE TRUSTEE

SECTION 5.01. The Company will furnish or cause to be furnished to the Trustee
(a) on each regular record date (as defined in Section 2.03) for the Securities
of each Tranche of a series a list, in such form as the Trustee may reasonably
require, of the names and addresses of the holders of such Tranche of Securities
as of such regular record date, provided, that the Company shall not be
obligated to furnish or cause to be furnished such list at any time that the
list shall not differ in any respect from the most recent list furnished to the
Trustee by the Company and (b) at such other times as the Trustee may request in
writing within 30 days after the receipt by the Company of any such request, a
list of similar form and content as of a date not more than 15 days prior to the
time such list is furnished; provided, however, no such list need be furnished
for any series for which the Trustee shall be the Security Registrar.

SECTION 5.02. (a) The Trustee shall preserve, in as current a form as is
reasonably practicable, all information as to the names and addresses of the
holders of Securities contained in the most recent list furnished to it as
provided in Section 5.01 and as to the names and addresses of holders of
Securities received by the Trustee in its capacity as Security Registrar (if
acting in such capacity).

     (b) The Trustee may destroy any list furnished to it as provided in Section
5.01 upon receipt of a new list so furnished.

     (c) In case three or more holders of  Securities  of a series  (hereinafter
referred to as "applicants") apply in writing to the Trustee, and furnish to the
Trustee  reasonable  proof that each such  applicant  has owned a Security for a
period of at least six months preceding the date of such  application,  and such
application  states that the applicants desire to communicate with other holders
of Securities of such series or holders of all Securities  with respect to their
rights under this  Indenture or under such  Securities,  and is accompanied by a
copy of the form of proxy or other  communication  which such applicants propose
to transmit, then the Trustee shall, within five Business Days after the receipt
of such application, at its election, either:

     (1)  afford to such applicants  access to the information  preserved at the
          time by the Trustee in  accordance  with the  provisions of subsection
          (a) of this Section 5.02; or

     (2)  inform  such  applicants  as to the  approximate  number of holders of
          Securities  of such series or of all  Securities,  as the case may be,
          whose names and addresses  appear in the information  preserved at the
          time by the Trustee,  in accordance  with the provisions of subsection
          (a) of this Section 5.02, and as to the approximate cost of mailing to
          such Securityholders the form of proxy or other communication, if any,
          specified in such application.

     (d) If the Trustee shall elect not to afford such applicants access to such
information,  the Trustee shall,  upon the written  request of such  applicants,
mail to each  holder of such  series or of all  Securities,  as the case may be,
whose name and address appears in the  information  preserved at the time by the
Trustee in accordance  with the  provisions  of  subsection  (a) of this Section
5.02, a copy of the form of proxy or other  communication  which is specified in
such request,  with reasonable  promptness  after a tender to the Trustee of the
material to be mailed and of  payment,  or  provision  for the  payment,  of the
reasonable  expenses of mailing,  unless within five days after such tender, the
Trustee shall mail to such  applicants  and file with the  Commission,  together
with a copy of the  material  to be mailed,  a written  statement  to the effect
that, in the opinion of the Trustee,  such mailing would be contrary to the best
interests of the holders of Securities of such series or of all  Securities,  as
the case may be,  or would be in  violation  of  applicable  law.  Such  written
statement  shall specify the basis of such  opinion.  If the  Commission,  after
opportunity for a hearing upon the objections specified in the written statement
so filed, shall enter an order refusing to sustain any of such objections or if,
after  the  entry of an order  sustaining  one or more of such  objections,  the
Commission  shall find,  after notice and opportunity for hearing,  that all the
objections so sustained have been met and shall enter an order so declaring, the
Trustee  shall mail  copies of such  material to all such  Securityholders  with
reasonable  promptness  after the entry of such  order and the  renewal  of such
tender;  otherwise,  the Trustee shall be relieved of any  obligation or duty to
such applicants respecting their application.

     (e) Each and every holder of the  Securities,  by receiving and holding the
same,  agrees with the Company and the Trustee  that neither the Company nor the
Trustee  nor  any  paying  agent  nor  any  Security  Registrar  shall  be  held
accountable by reason of the disclosure of any such  information as to the names
and addresses of the holders of Securities in accordance  with the provisions of
subsection  (c) of this  Section,  regardless  of the  source  from  which  such
information was derived,  and that the Trustee shall not be held  accountable by
reason of mailing any material  pursuant to a request made under said subsection
(c).

SECTION 5.03. (a) The Company covenants and agrees to file with the Trustee,
within 30 days after the Company is required to file the same with the
Commission, a copy of the annual reports and of the information, documents and
other reports (or a copy of such portions of any of the foregoing as the
Commission may from time to time by rules and regulations prescribe) which the
Company may be required to file with the Commission pursuant to Section 13 or
Section 15(d) of the Exchange Act; or, if the Company is not required to file
information, documents or reports pursuant to either of such sections, then to
file with the Trustee and, unless the Commission shall not accept such
information, documents or reports, the Commission, in accordance with the rules
and regulations prescribed from time to time by the Commission, such of the
supplementary and periodic information, documents and reports which may be
required pursuant to Section 13 of the Exchange Act, in respect of a security
listed and registered on a national securities exchange as may be prescribed
from time to time in such rules and regulations.

     (b) The  Company  covenants  and  agrees to file with the  Trustee  and the
Commission, in accordance with the rules and regulations prescribed from time to
time by the Commission, such additional information,  documents and reports with
respect to compliance by the Company with the conditions and covenants  provided
for in this  Indenture  as may be  required  from time to time by such rules and
regulations.

     (c) The  Company  covenants  and agrees to  transmit  by mail,  first class
postage  prepaid,  or reputable  over-night  delivery service which provides for
evidence of receipt, to the Securityholders, as their names and addresses appear
upon the  Security  Register,  within 30 days after the filing  thereof with the
Trustee, such summaries of any information, documents and reports required to be
filed by the Company  pursuant to subsections (a) and (b) of this Section as may
be  required  by  rules  and  regulations  prescribed  from  time to time by the
Commission.

     (d) The  Company  covenants  and agrees to furnish  to the  Trustee,  on or
before  May 15 in  each  calendar  year  in  which  any of  the  Securities  are
outstanding, or on or before such other day in each calendar year as the Company
and the Trustee may from time to time agree upon, a Certificate as to compliance
with all conditions  and covenants  under this  Indenture.  For purposes of this
subsection (d), such compliance shall be determined without regard to any period
of grace or requirement of notice provided under this Indenture.

     (e)  Delivery  of such  information,  documents  or reports to the  Trustee
pursuant to Section  5.03(a) or 5.03(b) is for  informational  purposes only and
the Trustee's  receipt thereof shall not constitute  constructive  notice of any
information   contained  therein  or  determinable  from  information  contained
therein,  including,  in the case of Section 5.03(b),  the Company's  compliance
with any of the covenants hereunder.

SECTION 5.04. (a) On or before July 15 in each year in which any of the
Securities are outstanding, the Trustee shall transmit by mail, first class
postage prepaid, to the Securityholders, as their names and addresses appear
upon the Security Register, a brief report dated as of the preceding May 15,
with respect to any of the following events which may have occurred within the
previous twelve months (but if no such event has occurred within such period no
report need be transmitted):

     (1)  any  change  to  its   eligibility   under  Section   7.09,   and  its
          qualifications under Section 310(b) of the Trust Indenture Act;

     (2)  the creation of or any material change to a relationship  specified in
          paragraphs (1) through (10) of Section 310 of the Trust Indenture Act;

     (3)  the character and amount of any advances (and if the Trustee elects so
          to state,  the  circumstances  surrounding the making thereof) made by
          the Trustee (as such) which remain  unpaid on the date of such report,
          and for the  reimbursement  of which it  claims or may claim a lien or
          charge, prior to that of the Securities, on any property or funds held
          or  collected by it as trustee if such  advances so  remaining  unpaid
          aggregate  more  than  1/2  of 1%  of  the  principal  amount  of  the
          Securities outstanding on the date of such report;

     (4)  any change to the amount,  interest  rate,  and  maturity  date of all
          other  indebtedness  owing by the Company,  or by any other obligor on
          the Securities, to the Trustee in its individual capacity, on the date
          of such  report,  with a brief  description  of any  property  held as
          collateral  security  therefor,  except any indebtedness  based upon a
          creditor  relationship  arising in any manner  described in paragraphs
          (2), (3), (4) or (6) of Section 311(b) of the Trust Indenture Act;

     (5)  any  change to the  property  and  funds,  if any,  physically  in the
          possession of the Trustee as such on the date of such report;

     (6)  any release,  or release and substitution,  of property subject to the
          lien, if any, of this Indenture  (and the  consideration  thereof,  if
          any) which it has not previously reported;

     (7)  any  additional   issue  of  Securities  which  the  Trustee  has  not
          previously reported; and

     (8)  any action taken by the Trustee in the performance of its duties under
          this Indenture  which it has not previously  reported and which in its
          opinion  materially  affects the  Securities or the  Securities of any
          series, except any action in respect of a default, notice of which has
          been or is to be withheld by it in accordance  with the  provisions of
          Section 6.07.

     (b) The Trustee shall transmit by mail, first class postage prepaid, to the
Securityholders, as their names and addresses appear upon the Security Register,
a brief report with respect to the  character and amount of any advances (and if
the  Trustee  elects so to  state,  the  circumstances  surrounding  the  making
thereof)  made by the  Trustee  as  such  since  the  date  of the  last  report
transmitted  pursuant to the provisions of subsection (a) of this Section (or if
no such report has yet been so transmitted,  since the date of execution of this
Indenture),  for the  reimbursement  of which it  claims  or may claim a lien or
charge prior to that of the  Securities  of any series on property or funds held
or collected by it as Trustee, and which it has not previously reported pursuant
to this subsection if such advances  remaining unpaid at any time aggregate more
than 10% of the principal  amount of Securities  of such series  outstanding  at
such time, such report to be transmitted within 90 days after such time.

     (c) A copy of each such report shall,  at the time of such  transmission to
Securityholders,  be filed by the  Trustee  with the  Company,  with each  stock
exchange upon which any  Securities  are listed (if so listed) and also with the
Commission.  The Company agrees to notify the Trustee when any Securities become
listed on any stock exchange.

                                  ARTICLE SIX
                   REMEDIES OF THE TRUSTEE AND SECURITYHOLDERS
                               ON EVENT OF DEFAULT

SECTION 6.01. (a) Whenever used herein with respect to Securities of a
particular series, "Event of Default" means any one or more of the following
events which has occurred and is continuing:

     (1)  default in the payment of any  installment of interest upon any of the
          Securities  of that series,  as and when the same shall become due and
          payable, and continuance of such default for a period of 30 days;

     (2)  default in the payment of the  principal of (or  premium,  if any, on)
          any of the Securities of that series as and when the same shall become
          due and payable whether at maturity, upon redemption,  pursuant to any
          sinking fund obligation,  by declaration or otherwise, and continuance
          of such default for a period of 3 Business Days;

     (3)  failure on the part of the  Company  duly to  observe  or perform  any
          other of the  covenants or  agreements on the part of the Company with
          respect to that  series  contained  in such  Securities  or  otherwise
          established  with  respect to that  series of  Securities  pursuant to
          Section  2.01  hereof or  contained  in this  Indenture  (other than a
          covenant  or  agreement  which  has been  expressly  included  in this
          Indenture  solely for the benefit of one or more series of  Securities
          other  than such  series)  for a period  of 90 days  after the date on
          which  written  notice  of  such  failure,  requiring  the  same to be
          remedied  and  stating  that  such  notice is a  "Notice  of  Default"
          hereunder,  shall have been given to the  Company by the  Trustee,  by
          registered or certified mail, or to the Company and the Trustee by the
          holders of at least 33% in principal  amount of the Securities of that
          series at the time outstanding;

     (4)  a decree or order by a court having jurisdiction in the premises shall
          have been entered  adjudging the Company as bankrupt or insolvent,  or
          approving  as  properly  filed  a  petition  seeking   liquidation  or
          reorganization of the Company under the Federal Bankruptcy Code or any
          other  similar  applicable  Federal or State law,  and such  decree or
          order shall have  continued  unvacated and unstayed for a period of 90
          consecutive days; or an involuntary case shall be commenced under such
          Code in respect of the Company and shall  continue  undismissed  for a
          period  of 90  consecutive  days or an order  for  relief in such case
          shall  have  been  entered;  or a decree  or  order of a court  having
          jurisdiction   in  the  premises  shall  have  been  entered  for  the
          appointment on the ground of insolvency or bankruptcy of a receiver or
          custodian  or  liquidator  or trustee or  assignee  in  bankruptcy  or
          insolvency of the Company or of its property, or for the winding up or
          liquidation  of its  affairs,  and such  decree  or order  shall  have
          remained  in  force   unvacated  and  unstayed  for  a  period  of  90
          consecutive days;

     (5)  the Company shall institute  proceedings to be adjudicated a voluntary
          bankrupt,  or shall  consent to the filing of a bankruptcy  proceeding
          against  it, or shall  file a petition  or answer or  consent  seeking
          liquidation or reorganization under the Federal Bankruptcy Code or any
          other similar applicable Federal or State law, or shall consent to the
          filing of any such  petition,  or shall consent to the  appointment on
          the ground of  insolvency  or bankruptcy of a receiver or custodian or
          liquidator or trustee or assignee in bankruptcy or insolvency of it or
          of its  property,  or shall  make an  assignment  for the  benefit  of
          creditors; or

     (6)  the  occurrence  of  any  other  Event  of  Default  with  respect  to
          Securities of such series, as contemplated by Section 2.01 hereof.

     (b)  The  Company  shall  file  with  the  Trustee  written  notice  of the
occurrence  of any Event of Default  within five  Business Days of the Company's
becoming aware of any such Event of Default. In each and every such case, unless
the principal of all the Securities of that series shall have already become due
and payable, either the Trustee or the holders of not less than 33% in aggregate
principal amount of the Securities of that series then outstanding hereunder, by
notice  in  writing  to the  Company  (and  to the  Trustee  if  given  by  such
Securityholders),  may declare the principal (or, if any of such  Securities are
Discount  Securities,  such portion of the  principal  amount  thereof as may be
specified by their terms as  contemplated by Section 2.01) of all the Securities
of that series to be due and payable immediately,  and upon any such declaration
the same  shall  become  and  shall be  immediately  due and  payable,  anything
contained in this  Indenture or in the  Securities of that series or established
with  respect to that  series  pursuant to Section  2.01 hereof to the  contrary
notwithstanding.

     (c) Section 6.01(b),  however,  is subject to the condition that if, at any
time after the  principal  of the  Securities  of that series shall have been so
declared due and  payable,  and before any judgment or decree for the payment of
the monies due shall have been obtained or entered as hereinafter provided,  the
Company shall pay or shall deposit with the Trustee a sum  sufficient to pay all
matured  installments of interest upon all the Securities of that series and the
principal of (and  premium,  if any, on) any and all  Securities  of that series
which shall have become due otherwise than by  acceleration  (with interest upon
such  principal  and  premium,  if any,  and, to the extent that such payment is
enforceable under applicable law, upon overdue installments of interest,  at the
rate per annum  expressed in the  Securities  of that series to the date of such
payment or deposit) and the amount  payable to the Trustee  under  Section 7.06,
and any and all  defaults  under the  Indenture,  other than the  nonpayment  of
principal on  Securities of that series which shall not have become due by their
terms,  shall have been remedied or waived as provided in Section 6.06, then and
in every such case the holders of a majority in  aggregate  principal  amount of
the Securities of that series then outstanding, by written notice to the Company
and to the Trustee,  may rescind and annul such declaration and its consequences
with respect to that series of Securities;  but no such rescission and annulment
shall  extend to or shall  affect any  subsequent  default,  or shall impair any
right consequent thereon.

     (d) In case  the  Trustee  has been  directed  by  Securityholders  and has
proceeded to enforce any right with respect to  Securities  of that series under
this Indenture and such  proceedings  shall have been  discontinued or abandoned
because of such  rescission  or  annulment or for any other reason or shall have
been  determined  adversely  to the  Trustee,  then and in every  such  case the
Company and the Trustee shall be restored respectively to their former positions
and rights hereunder, and all rights, remedies and powers of the Company and the
Trustee shall continue as though no such proceedings had been taken.

SECTION 6.02. (a) The Company covenants that in case an Event of Default
described in subsection 6.01(a)(1) or (a)(2) shall have occurred and be
continuing, upon demand of the Trustee, the Company will pay to the Trustee, for
the benefit of the holders of the Securities of that series, the whole amount
that then shall have become due and payable on all such Securities for principal
(and premium, if any) or interest, or both, as the case may be, with interest
upon the overdue principal (and premium, if any) and (to the extent that payment
of such interest is enforceable under applicable law and without duplication of
any other amounts paid by the Company in respect thereof) upon overdue
installments of interest at the rate per annum expressed in the Securities of
that series; and, in addition thereto, such further amount as shall be
sufficient to cover the costs and expenses of collection, and the amount payable
to the Trustee under Section 7.06.

     (b) In case the Company shall fail  forthwith to pay such amounts upon such
demand,  the Trustee,  in its own name and as trustee of an express trust, shall
be entitled and  empowered to institute any action or  proceedings  at law or in
equity for the  collection of the sums so due and unpaid,  and may prosecute any
such action or proceeding to judgment or final decree,  and may enforce any such
judgment  or  final  decree  against  the  Company  or  other  obligor  upon the
Securities  of that series and collect in the manner  provided by law out of the
property  of the Company or other  obligor  upon the  Securities  of that series
wherever situated the monies adjudged or decreed to be payable.

     (c) In  case  of any  receivership,  insolvency,  liquidation,  bankruptcy,
reorganization,   readjustment,   arrangement,  composition  or  other  judicial
proceedings affecting the Company, any other obligor on such Securities,  or the
creditors  or property of either,  the Trustee  shall have power to intervene in
such  proceedings and take any action therein that may be permitted by the court
and shall (except as may be otherwise  provided by law) be entitled to file such
proofs of claim and other papers and  documents as may be necessary or advisable
in order to have the claims of the Trustee and of the holders of  Securities  of
such series allowed for the entire amount due and payable by the Company or such
other  obligor  under  this  Indenture  at  the  date  of  institution  of  such
proceedings  and for any  additional  amount which may become due and payable by
the Company or such other  obligor  after such date,  and to collect and receive
any monies or other property  payable or  deliverable on any such claim,  and to
distribute  the same after the  deduction  of the amount  payable to the Trustee
under  Section  7.06;  and any  receiver,  assignee or trustee in  bankruptcy or
reorganization is hereby authorized by each of the holders of Securities of such
series to make such payments to the Trustee,  and, in the event that the Trustee
shall consent to the making of such payments  directly to such  Securityholders,
to pay to the Trustee any amount due it under Section 7.06.

     (d) All rights of action and of asserting  claims under this Indenture,  or
under any of the terms  established  with respect to  Securities of that series,
may be enforced by the Trustee without the possession of any of such Securities,
or the production thereof at any trial or other proceeding relative thereto, and
any such suit or  proceeding  instituted  by the Trustee shall be brought in its
own name as trustee of an express  trust,  and any  recovery of judgment  shall,
after  provision  for payment to the  Trustee of any  amounts due under  Section
7.06,  be for the  ratable  benefit  of the  holders of the  Securities  of such
series.

      In case of an Event of Default hereunder, the Trustee may in its
discretion proceed to protect and enforce the rights vested in it by this
Indenture by such appropriate judicial proceedings as the Trustee shall deem
most effectual to protect and enforce any of such rights, either at law or in
equity or in bankruptcy or otherwise, whether for the specific enforcement of
any covenant or agreement contained in the Indenture or in aid of the exercise
of any power granted in this Indenture, or to enforce any other legal or
equitable right vested in the Trustee by this Indenture or by law.

      Nothing herein contained shall be deemed to authorize the Trustee to
authorize or consent to or accept or adopt on behalf of any Securityholder any
plan of reorganization, arrangement, adjustment or composition affecting the
Securities of that series or the rights of any holder thereof or to authorize
the Trustee to vote in respect of the claim of any Securityholder in any such
proceeding.

SECTION 6.03. Any monies collected by the Trustee pursuant to Section 6.02 with
respect to a particular series of Securities shall be applied in the order
following, at the date or dates fixed by the Trustee and, in case of the
distribution of such monies on account of principal (or premium, if any) or
interest, upon presentation of the several Securities of that series, and
stamping thereon the payment, if only partially paid, and upon surrender thereof
if fully paid:

            FIRST:      To the payment of costs and expenses of collection and 
      of all amounts payable to the Trustee under Section 7.06;

            SECOND: To the payment of the amounts then due and unpaid upon
      Securities of such series for principal (and premium, if any) and
      interest, in respect of which or for the benefit of which such money has
      been collected, ratably, without preference or priority of any kind,
      according to the amounts due and payable on such Securities for principal
      (and premium, if any) and interest, respectively; and

            THIRD:      To the Company.

SECTION 6.04. No holder of any Security of any series shall have any right by
virtue or by availing of any provision of this Indenture to institute any suit,
action or proceeding in equity or at law upon or under or with respect to this
Indenture or for the appointment of a receiver or trustee, or for any other
remedy hereunder, unless such holder previously shall have given to the Trustee
written notice of an Event of Default and of the continuance thereof with
respect to Securities of such series specifying such Event of Default, as
hereinbefore provided, and unless also the holders of not less than 33% in
aggregate principal amount of the Securities of such series then outstanding
shall have made written request upon the Trustee to institute such action, suit
or proceeding in its own name as trustee hereunder and shall have offered to the
Trustee such reasonable indemnity as it may require against the costs, expenses
and liabilities to be incurred therein or thereby, and the Trustee for 60 days
after its receipt of such notice, request and offer of indemnity, shall have
failed to institute any such action, suit or proceeding; it being understood and
intended, and being expressly covenanted by the taker and holder of every
Security of such series with every other such taker and holder and the Trustee,
that no one or more holders of Securities of such series shall have any right in
any manner whatsoever by virtue or by availing of any provision of this
Indenture to affect, disturb or prejudice the rights of the holders of any other
of such Securities, or to obtain or seek to obtain priority over or preference
to any other such holder, or to enforce any right under this Indenture, except
in the manner herein provided and for the equal, ratable and common benefit of
all holders of Securities of such series. For the protection and enforcement of
the provisions of this Section, each and every Securityholder and the Trustee
shall be entitled to such relief as can be given either at law or in equity.

      Notwithstanding any other provisions of this Indenture, however, the right
of any holder of any Security to receive payment of the principal of (and
premium, if any) and interest on such Security, as therein provided, on or after
the respective due dates expressed in such Security (or in the case of
redemption, on the redemption date), or to institute suit for the enforcement of
any such payment on or after such respective dates or redemption date, shall not
be impaired or affected without the consent of such holder.

SECTION 6.05. (a) All powers and remedies given by this Article to the Trustee
or to the Securityholders shall, to the extent permitted by law, be deemed
cumulative and not exclusive of any others thereof or of any other powers and
remedies available to the Trustee or the holders of the Securities, by judicial
proceedings or otherwise, to enforce the performance or observance of the
covenants and agreements contained in this Indenture or otherwise established
with respect to such Securities.

     (b) No delay or  omission  of the  Trustee  or of any  holder of any of the
Securities  to exercise  any right or power  accruing  upon any Event of Default
occurring and continuing as aforesaid  shall impair any such right or power,  or
shall  be  construed  to be a  waiver  of any such  default  or an  acquiescence
therein;  and, subject to the provisions of Section 6.04, every power and remedy
given by this Article or by law to the Trustee or to the  Securityholders may be
exercised from time to time, and as often as shall be deemed  expedient,  by the
Trustee or by the Securityholders.

SECTION 6.06. The holders of a majority in aggregate principal amount of the
Securities of any series at the time outstanding, determined in accordance with
Section 8.04, shall have the right to direct the time, method and place of
conducting any proceeding for any remedy available to the Trustee, or exercising
any trust or power conferred on the Trustee with respect to such series;
provided, however, that such direction shall not be in conflict with any rule of
law or with this Indenture or unduly prejudicial to the rights of holders of
Securities of any other series at the time outstanding determined in accordance
with Section 8.04 not parties thereto. Subject to the provisions of Section
7.01, the Trustee shall have the right to decline to follow any such direction
if the Trustee in good faith shall, by a Responsible Officer or Officers of the
Trustee, determine that the proceeding so directed might involve the Trustee in
personal liability. The holders of a majority in aggregate principal amount of
the Securities of any series at the time outstanding affected thereby,
determined in accordance with Section 8.04, may on behalf of the holders of all
of the Securities of such series waive any past default in the performance of
any of the covenants contained herein or established pursuant to Section 2.01
with respect to such series and its consequences, except a default in the
payment of the principal of, or premium, if any, or interest on, any of the
Securities of that series as and when the same shall become due by the terms of
such Securities otherwise than by acceleration (unless such default has been
cured and a sum sufficient to pay all matured installments of interest and
principal otherwise than by acceleration and any premium has been deposited with
the Trustee (in accordance with Section 6.01(c))) or a call for redemption of
Securities of that series. Upon any such waiver, the default covered thereby
shall be deemed to be cured for all purposes of this Indenture and the Company,
the Trustee and the holders of the Securities of such series shall be restored
to their former positions and rights hereunder, respectively; but no such waiver
shall extend to any subsequent or other default or impair any right consequent
thereon.

SECTION 6.07. The Trustee shall, within 90 days after the occurrence of a
default with respect to a particular series, transmit by mail, first class
postage prepaid, to the holders of Securities of that series, as their names and
addresses appear upon the Security Register, notice of all defaults with respect
to that series known to the Trustee, unless such defaults shall have been cured
or waived before the giving of such notice (the term "defaults" for the purposes
of this Section being hereby defined to be the events specified in subsections
(1), (2), (3), (4), (5), (6) and (7) of Section 6.01(a), not including any
periods of grace provided for therein and irrespective of the giving of notice
provided for by subsection (4) of Section 6.01(a)); provided, that, except in
the case of default in the payment of the principal of (or premium, if any) or
interest on any of the Securities of that series or in the payment of any
sinking or analogous fund installment established with respect to that series,
the Trustee shall be protected in withholding such notice if and so long as the
board of directors, the executive committee, or a trust committee of directors
and/or Responsible Officers, of the Trustee in good faith determine that the
withholding of such notice is in the interests of the holders of Securities of
that series; provided further, that in the case of any default of the character
specified in Section 6.01(a)(4) with respect to Securities of such series no
such notice to the holders of the Securities of that series shall be given until
at least 30 days after the occurrence thereof.

      The Trustee shall not be deemed to have knowledge of any default, except
(i) a default under subsection (a)(1), (a)(2) or (a)(3) of Section 6.01 as long
as the Trustee is acting as paying agent for such series of Securities or (ii)
any default as to which the Trustee shall have received written notice or a
Responsible Officer charged with the administration of this Indenture shall have
obtained written notice.

SECTION 6.08. All parties to this Indenture agree, and each holder of any
Securities by his or her acceptance thereof shall be deemed to have agreed, that
any court may in its discretion require, in any suit for the enforcement of any
right or remedy under this Indenture, or in any suit against the Trustee for any
action taken or omitted by it as Trustee, the filing by any party litigant in
such suit of an undertaking to pay the costs of such suit, and that such court
may in its discretion assess reasonable costs, including reasonable attorneys'
fees, against any party litigant in such suit, having due regard to the merits
and good faith of the claims or defenses made by such party litigant; but the
provisions of this Section shall not apply to any suit instituted by the
Trustee, to any suit instituted by any Securityholder, or group of
Securityholders, holding more than 10% in aggregate principal amount of the
outstanding Securities of any series, or to any suit instituted by any
Securityholder for the enforcement of the payment of the principal of (or
premium, if any) or interest on any Security of such series, on or after the
respective due dates expressed in such Security or established pursuant to this
Indenture.

                                 ARTICLE SEVEN
                             CONCERNING THE TRUSTEE

SECTION 7.01. (a) The Trustee, prior to the occurrence of an Event of Default
with respect to Securities of a series and after the curing of all Events of
Default with respect to Securities of that series which may have occurred, shall
undertake to perform with respect to Securities of such series such duties and
only such duties as are specifically set forth in this Indenture, and no implied
covenants or obligations shall be read into this Indenture against the Trustee.
In case an Event of Default with respect to Securities of a series has occurred
(which has not been cured or waived), the Trustee shall exercise with respect to
Securities of that series such of the rights and powers vested in it by this
Indenture, and use the same degree of care and skill in their exercise, as a
prudent man would exercise or use under the circumstances in the conduct of his
own affairs.

     (b) No  provision  of this  Indenture  shall be  construed  to relieve  the
Trustee from liability for its own negligent  action,  its own negligent failure
to act, or its own willful misconduct, except that:

     (1)  prior to the  occurrence  of an  Event  of  Default  with  respect  to
          Securities  of a series  and after the  curing or  waiving of all such
          Events of Default with respect to that series which may have occurred:

          (i)  the duties and  obligations  of the Trustee shall with respect to
               Securities  of such  series be  determined  solely by the express
               provisions of this Indenture, and the Trustee shall not be liable
               with  respect  to  Securities  of  such  series  except  for  the
               performance of such duties and  obligations  as are  specifically
               set  forth  in  this  Indenture,  and  no  implied  covenants  or
               obligations  shall  be  read  into  this  Indenture  against  the
               Trustee; and

          (ii) in the  absence  of bad  faith  on the part of the  Trustee,  the
               Trustee   may  with   respect  to   Securities   of  such  series
               conclusively  rely,  as to the  truth of the  statements  and the
               correctness  of  the  opinions   expressed   therein,   upon  any
               certificates or opinions  furnished to the Trustee and conforming
               to the  requirements  of this  Indenture;  but in the case of any
               such  certificates or opinions which by any provision  hereof are
               specifically required to be furnished to the Trustee, the Trustee
               shall be under a duty to examine the same to determine whether or
               not they conform to the  requirements of this Indenture (but need
               not  confirm  or   investigate   the  accuracy  of   mathematical
               calculations or other facts stated therein);

     (2)  the Trustee shall not be liable for any error of judgment made in good
          faith by a Responsible Officer or Responsible Officers of the Trustee,
          unless  it  shall  be  proved  that  the  Trustee  was   negligent  in
          ascertaining the pertinent facts;

     (3)  the Trustee  shall not be liable with  respect to any action  taken or
          omitted  to be  taken  by it in good  faith  in  accordance  with  the
          direction  of the  holders  of not less than a majority  in  principal
          amount  of the  Securities  of any  series  at  the  time  outstanding
          relating to the time,  method and place of conducting  any  proceeding
          for any remedy  available to the Trustee,  or exercising  any trust or
          power  conferred upon the Trustee under this Indenture with respect to
          the Securities of that series; and

     (4)  none of the provisions  contained in this Indenture  shall require the
          Trustee  to expend or risk its own  funds or  otherwise  incur or risk
          personal  financial  liability in the performance of any of its duties
          or in the  exercise  of any of its  rights or powers,  if the  Trustee
          reasonably  believes  that the repayment of such funds or liability is
          not  reasonably  assured  to it under the terms of this  Indenture  or
          adequate indemnity against such risk is not reasonably assured to it.

     (c) Whether or not therein  expressly so provided,  every provision of this
Indenture  relating to the conduct or  affecting  the  liability of or affording
protection  to  the  Trustee,  or any  other  capacity  the  Trustee  may  serve
hereunder, shall be subject to the provisions of this Section 7.01.

SECTION 7.02.     Except as otherwise provided in Section 7.01:

     (a) The  Trustee  may  conclusively  rely and shall be fully  protected  in
acting or refraining  from acting upon any resolution,  certificate,  statement,
instrument, opinion, report, notice, request, direction, consent, order, demand,
approval,  bond,  security or other  paper or document  believed by it (i) to be
genuine  and (ii) to have  been  signed  or  presented  by the  proper  party or
parties;

     (b) Any request, direction, order or demand of the Company mentioned herein
shall  be  sufficiently   evidenced  by  a  Board  Resolution  or  an  Officers'
Certificate (unless other evidence in respect thereof is specifically prescribed
herein);

     (c) The  Trustee may consult  with  counsel and the written  advice of such
counsel or any Opinion of Counsel shall be full and complete  authorization  and
protection  in respect of any action  taken or suffered or omitted  hereunder in
good faith and in reliance thereon;

     (d) The Trustee  shall be under no obligation to exercise any of the rights
or powers vested in it by this  Indenture at the request,  order or direction of
any of the Securityholders, pursuant to the provisions of this Indenture, unless
such  Securityholders  shall have  offered to the Trustee  security or indemnity
satisfactory  to it against the costs,  expenses  and  liabilities  which may be
incurred therein or thereby;  nothing herein contained shall,  however,  relieve
the Trustee of the  obligation,  upon the occurrence of an Event of Default with
respect  to a series of the  Securities  (which has not been cured or waived) to
exercise with respect to Securities of that series such of the rights and powers
vested in it by this Indenture,  and to use the same degree of care and skill in
their exercise,  as a prudent man would exercise or use under the  circumstances
in the conduct of his own affairs;

     (e) The Trustee  shall not be liable for any action  taken or omitted to be
taken by it in good  faith and  believed  by it to be  authorized  or within the
discretion or rights or powers conferred upon it by this Indenture;

     (f) The Trustee shall not be bound to make any investigation into the facts
or  matters  stated  in  any  resolution,  certificate,  statement,  instrument,
opinion, report, notice, request, consent,  direction,  order, demand, approval,
bond, security, or other papers or documents,  unless requested in writing so to
do by the  holders  of not less  than a  majority  in  principal  amount  of the
outstanding  Securities of the particular series affected thereby (determined as
provided in Section  8.04);  provided,  however,  that if the  payment  within a
reasonable time to the Trustee of the costs,  expenses or liabilities  likely to
be incurred by it in the making of such  investigation is, in the opinion of the
Trustee, not reasonably assured to the Trustee by the security afforded to it by
the terms of this  Indenture,  the  Trustee  may  require  reasonable  indemnity
against  such costs,  expenses or  liabilities  as a condition  precedent  to so
proceeding.  The reasonable  expense of every such examination  shall be paid by
the Company  or, if paid by the  Trustee,  shall be repaid by the  Company  upon
demand.  Notwithstanding the foregoing,  the Trustee, in its direction, may make
such further inquiry or  investigation  into such facts or matters as it may see
fit. In making any  investigation  required or authorized by this  subparagraph,
the  Trustee  shall be entitled to examine  books,  records and  premises of the
Company, personally or by agent or attorney;

     (g) The  Trustee  may  execute  any of the  trusts or powers  hereunder  or
perform  any  duties  hereunder  either  directly  or by or  through  agents  or
attorneys  and the  Trustee  shall  not be  responsible  for any  misconduct  or
negligence  on the part of any agent or attorney  appointed  with due care by it
hereunder;

     (h) The  permissive  right of the Trustee to do things  enumerated  in this
Indenture shall not be construed as a duty.

SECTION 7.03. (a) The recitals contained herein and in the Securities (other
than the Certificate of Authentication on the Securities) shall be taken as the
statements of the Company, and the Trustee assumes no responsibility for the
correctness of the same.

     (b) The Trustee makes no  representations as to the validity or sufficiency
of this Indenture or of the Securities.

     (c) The Trustee shall not be accountable  for the use or application by the
Company of any of the Securities or of the proceeds of such  Securities,  or for
the use or application of any monies paid over by the Trustee in accordance with
any provision of this Indenture or established  pursuant to Section 2.01, or for
the use or application of any monies received by any paying agent other than the
Trustee.

SECTION 7.04. The Trustee or any paying agent or Security Registrar, in its
individual or any other capacity, may become the owner or pledgee of Securities
with the same rights it would have if it were not Trustee, paying agent or
Security Registrar.

SECTION 7.05. Subject to the provisions of Section 11.04, all monies received by
the Trustee shall, until used or applied as herein provided, be held in trust
for the purposes for which they were received, but need not be segregated from
other funds except to the extent required by law. The Trustee shall be under no
liability for interest on any monies received by it hereunder except such as it
may agree in writing with the Company to pay thereon.

SECTION 7.06. (a) The Company covenants and agrees to pay to the Trustee from
time to time, and the Trustee shall be entitled to, reasonable compensation
(which shall not be limited by any provision of law in regard to the
compensation of a trustee of an express trust) for all services rendered by it
in the execution of the trusts hereby created and in the exercise and
performance of any of the powers and duties hereunder of the Trustee, and the
Company will pay or reimburse the Trustee upon its request for all reasonable
expenses, disbursements and advances incurred or made by the Trustee in
accordance with any of the provisions of this Indenture (including the
reasonable compensation and the reasonable expenses and disbursements of its
counsel and agents and of all persons not regularly in its employ) except any
such expense, disbursement or advance as may arise from its negligence, willful
misconduct or bad faith. The Company also covenants to indemnify the Trustee
(and its officers, agents, directors and employees) for, and to hold it harmless
against, any loss, liability or expense incurred without negligence, willful
misconduct or bad faith on the part of the Trustee and arising out of or in
connection with the acceptance or administration of this trust, including the
reasonable costs and expenses of defending itself against any claim or liability
in connection with the exercise or performance of any of its powers or duties
hereunder.

     (b) The  obligations  of the Company under this Section to  compensate  and
indemnify  the  Trustee  and to pay  or  reimburse  the  Trustee  for  expenses,
disbursements and advances shall constitute additional  indebtedness  hereunder.
Such  additional  indebtedness  shall be  secured by a lien prior to that of the
Securities upon all property and funds held or collected by the Trustee as such,
except  funds  held in  trust  for the  benefit  of the  holders  of  particular
Securities.

     (c) Without  prejudice to any other rights  available to the Trustee  under
applicable  law,  when the  Trustee  incurs  expenses  or  renders  services  in
connection with an Event of Default, the expenses (including  reasonable charges
and expenses of its counsel) and  compensation  for its services are intended to
constitute  expenses  of  administration   under  applicable  federal  or  state
bankruptcy, insolvency or similar law.

     (d) The provisions of this Section 7.06 shall survive the  satisfaction and
discharge of this Indenture or the appointment of a successor trustee.

SECTION 7.07. Except as otherwise provided in Section 7.01, whenever in the
administration of the provisions of this Indenture the Trustee shall deem it
necessary or desirable that a matter be proved or established prior to taking or
suffering or omitting to take any action hereunder, such matter (unless other
evidence in respect thereof be herein specifically prescribed) may, in the
absence of bad faith on the part of the Trustee, be deemed to be conclusively
proved and established by an Officers' Certificate delivered to the Trustee and
such certificate, in the absence of bad faith on the part of the Trustee, shall
be full warrant to the Trustee for any action taken, suffered or omitted to be
taken by it under the provisions of this Indenture upon the faith thereof.

SECTION 7.08. If the Trustee has acquired or shall acquire a conflicting
interest within the meaning of the Trust Indenture Act, the Trustee shall either
eliminate such interest or resign, to the extent and in the manner provided by,
and subject to the provisions of, the Trust Indenture Act and this Indenture.

SECTION 7.09. There shall at all times be a Trustee with respect to the
Securities issued hereunder which shall at all times be a corporation organized
and doing business under the laws of the United States of America or any State
or Territory thereof or of the District of Columbia, or a corporation or other
person permitted to act as trustee by the Commission, authorized under such laws
to exercise corporate trust powers, having a combined capital and surplus of at
least 50 million dollars, and subject to supervision or examination by Federal,
State, Territorial, or District of Columbia authority. If such corporation
publishes reports of condition at least annually, pursuant to law or to the
requirements of the aforesaid supervising or examining authority, then for the
purposes of this Section, the combined capital and surplus of such corporation
shall be deemed to be its combined capital and surplus as set forth in its most
recent report of condition so published. The Company may not, nor may any person
directly or indirectly controlling, controlled by, or under common control with
the Company, serve as Trustee. In case at any time the Trustee shall cease to be
eligible in accordance with the provisions of this Section, the Trustee shall
resign immediately in the manner and with the effect specified in Section 7.10.

SECTION 7.10. (a) The Trustee or any successor hereafter appointed, may at any
time resign with respect to the Securities of one or more series by giving
written notice thereof to the Company and by transmitting notice of resignation
by mail, first class postage prepaid, to the Securityholders of such series, as
their names and addresses appear upon the Security Register. Upon receiving such
notice of resignation, the Company shall promptly appoint a successor trustee
with respect to Securities of such series by written instrument, in duplicate,
executed by order of the Board of Directors, one copy of which instrument shall
be delivered to the resigning Trustee and one copy to the successor trustee. If
no successor trustee shall have been so appointed and have accepted appointment
within 30 days after the mailing of such notice of resignation, the resigning
Trustee may petition any court of competent jurisdiction for the appointment of
a successor trustee with respect to Securities of such series, or any
Securityholder of that series who has been a bona fide holder of a Security or
Securities for at least six months may, subject to the provisions of Section
6.08, on behalf of himself and all others similarly situated, petition any such
court for the appointment of a successor trustee. Such court may thereupon after
such notice, if any, as it may deem proper and prescribe, appoint a successor
trustee.

     (b) In case at any time any of the following shall occur:

          (1)  the Trustee  shall fail to comply with the  provisions of Section
               7.08 after  written  request  therefor  by the  Company or by any
               Securityholder  who has been a bona fide  holder of a Security or
               Securities for at least six months; or

          (2)  The Trustee  shall cease to be  eligible in  accordance  with the
               provisions of Section 7.09 and shall fail to resign after written
               request therefor by the Company or by any such Securityholder; or

          (3)  the  Trustee  shall  become  incapable  of  acting,  or  shall be
               adjudged a bankrupt or insolvent, or a receiver of the Trustee or
               of its property  shall be appointed,  or any public officer shall
               take  charge or control  of the  Trustee  or of its  property  or
               affairs  for  the  purpose  of  rehabilitation,  conservation  or
               liquidation;

then, in any such case, the Company may remove the Trustee with respect to all
Securities and appoint a successor trustee by written instrument, in duplicate,
executed by order of the Board of Directors, one copy of which instrument shall
be delivered to the Trustee so removed and one copy to the successor trustee,
or, subject to the provisions of Section 6.08, unless, with respect to
subsection (b)(1) above, the Trustee's duty to resign is stayed as provided in
Section 310(b) of the Trust Indenture Act, any Securityholder who has been a
bona fide holder of a Security or Securities for at least six months may, on
behalf of himself and all others similarly situated, petition any court of
competent jurisdiction for the removal of the Trustee and the appointment of a
successor trustee. Such court may thereupon after such notice, if any, as it may
deem proper and prescribe, remove the Trustee and appoint a successor trustee.

     (c)  The  holders  of a  majority  in  aggregate  principal  amount  of the
Securities  of any  series at the time  outstanding  may at any time  remove the
Trustee with respect to such series and appoint a successor trustee.

     (d)  Any  resignation  or  removal  of the  Trustee  and  appointment  of a
successor  trustee with respect to the Securities of a series pursuant to any of
the  provisions  of this  Section  shall become  effective  upon  acceptance  of
appointment by the successor trustee as provided in Section 7.11.

     (e)  Any  successor  trustee  appointed  pursuant  to this  Section  may be
appointed  with respect to the  Securities  of one or more series or all of such
series,  and at any time there  shall be only one  Trustee  with  respect to the
Securities of any particular series.

SECTION 7.11. (a) In case of the appointment hereunder of a successor trustee
with respect to all Securities, every such successor trustee so appointed shall
execute, acknowledge and deliver to the Company and to the retiring Trustee an
instrument accepting such appointment, and thereupon the resignation or removal
of the retiring Trustee shall become effective and such successor trustee,
without any further act, deed or conveyance, shall become vested with all the
rights, powers, trusts and duties of the retiring Trustee; but, on the request
of the Company or the successor trustee, such retiring Trustee shall, upon
payment of its charges, execute and deliver an instrument transferring to such
successor trustee all the rights, powers, and trusts of the retiring Trustee and
shall duly assign, transfer and deliver to such successor trustee all property
and money held by such retiring Trustee hereunder, subject to any prior lien
provided for in Section 7.06(b).

     (b) In  case of the  appointment  hereunder  of a  successor  trustee  with
respect to the Securities of one or more (but not all) series, the Company,  the
retiring  Trustee and each  successor  trustee with respect to the Securities of
one or more series shall  execute and deliver an indenture  supplemental  hereto
wherein each successor trustee shall accept such appointment and which (1) shall
contain  such  provisions  as shall be  necessary  or  desirable to transfer and
confirm to, and to vest in,  each  successor  trustee  all the  rights,  powers,
trusts and duties of the retiring Trustee with respect to the Securities of that
or those series to which the appointment of such successor trustee relates,  (2)
shall  contain  such  provisions  as shall be deemed  necessary  or desirable to
confirm that all the rights,  powers,  trusts and duties of the retiring Trustee
with respect to the  Securities of that or those series as to which the retiring
Trustee is not retiring shall continue to be vested in the retiring Trustee, and
(3) shall add to or change any of the  provisions of this  Indenture as shall be
necessary  to  provide  for or  facilitate  the  administration  of  the  trusts
hereunder by more than one Trustee,  it being  understood that nothing herein or
in such supplemental indenture shall constitute such Trustees co-trustees of the
same  trust,  that  each  such  Trustee  shall be  trustee  of a trust or trusts
hereunder separate and apart from any trust or trusts hereunder  administered by
any other such Trustee and that no Trustee shall be  responsible  for any act or
failure  to act on the  part  of any  other  Trustee  hereunder;  and  upon  the
execution and delivery of such supplemental indenture the resignation or removal
of the retiring Trustee shall become  effective to the extent provided  therein,
such  retiring  Trustee  shall with respect to the  Securities  of that or those
series  to which the  appointment  of such  successor  trustee  relates  have no
further  responsibility  for  the  exercise  of  rights  and  powers  or for the
performance  of the  duties and  obligations  vested in the  Trustee  under this
Indenture,  and each such  successor  trustee,  without any further act, deed or
conveyance,  shall become vested with all the rights,  powers, trusts and duties
of the retiring  Trustee with respect to the  Securities of that or those series
to which the appointment of such successor  trustee relates;  but, on request of
the Company or any successor  trustee,  such retiring Trustee shall duly assign,
transfer and deliver to such successor  trustee,  to the extent  contemplated by
such  supplemental  indenture,  the  property  and money  held by such  retiring
Trustee  hereunder  with  respect to the  Securities  of that or those series to
which the appointment of such successor trustee relates.

     (c) Upon request of any such successor  trustee,  the Company shall execute
any and all instruments  for more fully and certainly  vesting in and confirming
to such  successor  trustee all such  rights,  powers and trusts  referred to in
paragraph (a) or (b) of this Section, as the case may be.

     (d) No successor trustee shall accept its appointment unless at the time of
such  acceptance  such  successor  trustee  shall be  qualified  under the Trust
Indenture Act and eligible under this Article.

     (e) Upon  acceptance of appointment  by a successor  trustee as provided in
this  Section,  the Company  shall  transmit  notice of the  succession  of such
trustee hereunder by mail, first class postage prepaid, to the  Securityholders,
as their names and addresses appear upon the Security  Register.  If the Company
fails to transmit such notice within ten days after acceptance of appointment by
the  successor  trustee,  the  successor  trustee  shall cause such notice to be
transmitted at the expense of the Company.

SECTION 7.12. Any corporation into which the Trustee may be merged or converted
or with which it may be consolidated, or any corporation resulting from any
merger, conversion or consolidation to which the Trustee shall be a party, or
any corporation succeeding to all or substantially all of the corporate trust
business of the Trustee, shall be the successor of the Trustee hereunder,
provided such corporation shall be qualified under the provisions of the Trust
Indenture Act and eligible under the provisions of Section 7.09, without the
execution or filing of any paper or any further act on the part of any of the
parties hereto, anything herein to the contrary notwithstanding. In case any
Securities shall have been authenticated, but not delivered, by the Trustee then
in office, any successor by merger, conversion or consolidation to such
authenticating Trustee may adopt such authentication and deliver the Securities
so authenticated with the same effect as if such successor Trustee had itself
authenticated such Securities.

SECTION 7.13. If and when the Trustee shall become a creditor of the Company (or
any other obligor upon the Securities), the Trustee shall be subject to the
provisions of the Trust Indenture Act regarding collection of claims against the
Company (or any other obligor upon the Securities).

                                 ARTICLE EIGHT
                         CONCERNING THE SECURITYHOLDERS

SECTION 8.01. Whenever in this Indenture it is provided that the holders of a
majority or specified percentage in aggregate principal amount of the Securities
of a particular series may take any action (including the making of any demand
or request, the giving of any notice, consent or waiver or the taking of any
other action), the fact that at the time of taking any such action the holders
of such majority or specified percentage of that series have joined therein may
be evidenced by any instrument or any number of instruments of similar tenor
executed by such holders of Securities of that series in person or by agent or
proxy appointed in writing.

      If the Company shall solicit from the Securityholders of any series any
request, demand, authorization, direction, notice, consent, waiver or other
action, the Company may, at its option, as evidenced by an Officers'
Certificate, fix in advance a record date for such series for the determination
of Securityholders entitled to give such request, demand, authorization,
direction, notice, consent, waiver or other action, but the Company shall have
no obligation to do so. If such a record date is fixed, such request, demand,
authorization, direction, notice, consent, waiver or other action may be given
before or after the record date, but only the Securityholders of record at the
close of business on the record date shall be deemed to be Securityholders for
the purposes of determining whether Securityholders of the requisite proportion
of outstanding Securities of that series have authorized or agreed or consented
to such request, demand, authorization, direction, notice, consent, waiver or
other action, and for that purpose the outstanding Securities of that series
shall be computed as of the record date; provided that no such authorization,
agreement or consent by such Securityholders on the record date shall be deemed
effective unless it shall become effective pursuant to the provisions of this
Indenture not later than six months after the record date.

      In determining whether the holders of the requisite aggregate principal
amount of Securities of a particular series have concurred in any direction,
consent or waiver under this Indenture, the principal amount of a Discount
Security that shall be deemed to be outstanding for such purposes shall be the
amount of the principal thereof that would be due and payable as of the date of
such determination upon a declaration of acceleration of the maturity thereof
pursuant to Section 6.01.

SECTION 8.02. Subject to the provisions of Section 7.01, proof of the execution
of any instrument by a Securityholder (such proof will not require notarization)
or his agent or proxy and proof of the holding by any person of any of the
Securities shall be sufficient if made in the following manner:

     (a)  The  fact  and  date  of the  execution  by  any  such  person  of any
          instrument  may be proved in any reasonable  manner  acceptable to the
          Trustee.

     (b)  The ownership of Securities  shall be proved by the Security  Register
          of such  Securities  or by a  certificate  of the  Security  Registrar
          thereof.

     (c)  The Trustee may require such  additional  proof of any matter referred
          to in this Section as it shall deem necessary.

SECTION 8.03. Prior to the due presentment for registration of transfer of any
Security, the Company, the Trustee, any paying agent and any Security Registrar
may deem and treat the person in whose name such Security shall be registered
upon the books of the Company as the absolute owner of such Security (whether or
not such Security shall be overdue and notwithstanding any notice of ownership
or writing thereon made by anyone other than the Security Registrar) for the
purpose of receiving payment of or on account of the principal of and premium,
if any, and (subject to Section 2.03) interest on such Security and for all
other purposes; and neither the Company nor the Trustee nor any paying agent nor
any Security Registrar shall be affected by any notice to the contrary.

SECTION 8.04. In determining whether the holders of the requisite aggregate
principal amount of Securities of a particular series have concurred in any
direction, consent or waiver under this Indenture, Securities of that series
which are owned by the Company or any other obligor on the Securities of that
series or by any person directly or indirectly controlling or controlled by or
under common control with the Company or any other obligor on the Securities of
that series shall be disregarded and deemed not to be outstanding for the
purpose of any such determination, except that for the purpose of determining
whether the Trustee shall be protected in relying on any such direction, consent
or waiver, only Securities of such series which the Trustee actually knows are
so owned shall be so disregarded. Securities so owned which have been pledged in
good faith may be regarded as outstanding for the purposes of this Section, if
the pledgee shall establish to the satisfaction of the Trustee the pledgee's
right so to act with respect to such Securities and that the pledgee is not a
person directly or indirectly controlling or controlled by or under direct or
indirect common control with the Company or any such other obligor. In case of a
dispute as to such right, any decision by the Trustee taken upon the advice of
counsel shall be full protection to the Trustee.

SECTION 8.05. At any time prior to (but not after) the evidencing to the
Trustee, as provided in Section 8.01, of the taking of any action by the holders
of the majority or percentage in aggregate principal amount of the Securities of
a particular series specified in this Indenture in connection with such action,
any holder of a Security of that series which is shown by the evidence to be
included in the Securities the holders of which have consented to such action
may, by filing written notice with the Trustee, and upon proof of holding as
provided in Section 8.02, revoke such action so far as concerns such Security.
Except as aforesaid any such action taken by the holder of any Security shall be
conclusive and binding upon such holder and upon all future holders and owners
of such Security, and of any Security issued in exchange therefor, on
registration of transfer thereof or in place thereof, irrespective of whether or
not any notation in regard thereto is made upon such Security. Any action taken
by the holders of the majority or percentage in aggregate principal amount of
the Securities of a particular series specified in this Indenture in connection
with such action shall be conclusively binding upon the Company, the Trustee and
the holders of all the Securities of that series.

                                  ARTICLE NINE
                             SUPPLEMENTAL INDENTURES

SECTION 9.01. In addition to any supplemental indenture otherwise authorized by
this Indenture, the Company, when authorized by a Board Resolution, and the
Trustee may from time to time and at any time enter into an indenture or
indentures supplemental hereto (which shall conform to the provisions of the
Trust Indenture Act as then in effect), without the consent of the
Securityholders, for one or more of the following purposes:

     (a)  to evidence the succession of another  person to the Company,  and the
          assumption  by any such  successor  of the  covenants  of the  Company
          contained  herein  or  otherwise   established  with  respect  to  the
          Securities; or

     (b)  to  add to  the  covenants  of the  Company  such  further  covenants,
          restrictions,  conditions  or  provisions  for the  protection  of the
          holders  of the  Securities  of all or any  series,  and to  make  the
          occurrence, or the occurrence and continuance,  of a default in any of
          such additional  covenants,  restrictions,  conditions or provisions a
          default or an Event of Default with respect to such series  permitting
          the enforcement of all or any of the several remedies provided in this
          Indenture as herein set forth;  provided,  however, that in respect of
          any such additional covenant, restriction, condition or provision such
          supplemental  indenture  may provide for a particular  period of grace
          after default (which period may be shorter or longer than that allowed
          in the  case  of  other  defaults)  or may  provide  for an  immediate
          enforcement  upon such default or may limit the remedies  available to
          the Trustee upon such default or may limit the right of the holders of
          a majority in aggregate  principal  amount of the  Securities  of such
          series to waive such default; or

     (c)  to cure any  ambiguity  or to  correct  or  supplement  any  provision
          contained  herein  or in  any  supplemental  indenture  which  may  be
          defective or inconsistent with any other provision contained herein or
          in any  supplemental  indenture,  or to make such other  provisions in
          regard to matters or questions  arising under this  Indenture as shall
          not be  inconsistent  with the  provisions of this Indenture and shall
          not adversely affect the interests of the holders of the Securities of
          any series; or

     (d)  to change or eliminate any of the  provisions of this  Indenture or to
          add any new provision to this Indenture;  provided, however, that such
          change, elimination or addition shall become effective only when there
          is no  Security  outstanding  of  any  series  created  prior  to  the
          execution  of such  supplemental  indenture  that is  entitled  to the
          benefit of such provisions; or

     (e)  to  establish  the  form or  terms  of  Securities  of any  series  as
          permitted by Section 2.01; or

     (f)  to add any  additional  Events of Default  with  respect to all or any
          series of outstanding Securities; or

     (g)  to provide collateral security for the Securities; or

     (h)  to provide for the  authentication  and delivery of bearer  securities
          and  coupons  appertaining  thereto  representing  interest,  if  any,
          thereon and for the  procedures  for the  registration,  exchange  and
          replacement  thereof  and  for  the  giving  of  notice  to,  and  the
          solicitation of the vote or consent of, the holders  thereof,  and for
          any other matters incidental thereto; or

          (i)  to  evidence  and  provide  for  the  acceptance  of  appointment
               hereunder by a separate or successor  Trustee with respect to the
               Securities  of one or more  series and to add to or change any of
               the provisions of this Indenture as shall be necessary to provide
               for or facilitate the  administration  of the trusts hereunder by
               more than one Trustee,  pursuant to the  requirements  of Article
               Seven; or

     (j)  to change any place or places where (1) the  principal of and premium,
          if any, and interest, if any, on all or any series of Securities shall
          be payable, (2) all or any series of Securities may be surrendered for
          registration  of transfer,  (3) all or any series of Securities may be
          surrendered  for  exchange  and (4) notices and demands to or upon the
          Company  in  respect  of all or any  series  of  Securities  and  this
          Indenture may be served; provided,  however, that any such place shall
          be located  in New York,  New York or be the  principal  office of the
          Company; or

     (k)  to provide  for the payment by the  Company of  additional  amounts in
          respect  of certain  taxes  imposed  on  certain  holders  and for the
          treatment of such  additional  amounts as interest and for all matters
          incidental thereto; or

     (l)  to provide for the issuance of  Securities  denominated  in a currency
          other than  Dollars or in a  composite  currency  and for all  matters
          incidental thereto.

      Without limiting the generality of the foregoing, if the Trust Indenture
Act as in effect at the date of the execution and delivery of this Indenture or
at any time thereafter shall be amended and

     (x)  if any  such  amendment  shall  require  one or  more  changes  to any
          provisions   hereof  or  the  inclusion   herein  of  any   additional
          provisions,  or shall by  operation  of law be deemed  to effect  such
          changes or incorporate such provisions by reference or otherwise, this
          Indenture  shall be deemed to have been  amended  so as to  conform to
          such  amendment  to the Trust  Indenture  Act, and the Company and the
          Trustee may, without the consent of any Securityholders,  enter into a
          supplemental  indenture  hereto to effect or evidence  such changes or
          additional provisions; or

     (y)  if any such  amendment  shall  permit one or more  changes  to, or the
          elimination  of,  any  provisions  hereof  which,  at the  date of the
          execution and delivery hereof or at any time thereafter,  are required
          by the Trust  Indenture  Act to be contained  herein,  this  Indenture
          shall be  deemed to have  been  amended  to  effect  such  changes  or
          elimination,  and the Company and the Trustee may, without the consent
          of any Securityholders,  enter into a supplemental indenture hereto to
          effect such changes or elimination; or

     (z)  if, by reason of any such amendment,  one or more provisions which, at
          the  date  of  the  execution  and  delivery  hereof  or at  any  time
          thereafter,  are required by the Trust  Indenture  Act to be contained
          herein  shall be deemed to be  incorporated  herein  by  reference  or
          otherwise, or otherwise made applicable hereto, and shall no longer be
          required to be  contained  herein,  the  Company and the Trustee  may,
          without the consent of any Securityholders,  enter into a supplemental
          indenture hereto to effect the elimination of such provisions.

      The Trustee is hereby authorized to join with the Company in the execution
of any such supplemental indenture, and to make any further appropriate
agreements and stipulations which may be therein contained, but the Trustee
shall not be obligated to enter into any such supplemental indenture which
affects the Trustee's own rights, duties or immunities under this Indenture or
otherwise.

      Any supplemental indenture authorized by the provisions of this Section
may be executed by the Company and the Trustee without the consent of the
holders of any of the Securities at the time outstanding, notwithstanding any of
the provisions of Section 9.02.

SECTION 9.02. With the consent (evidenced as provided in Section 8.01) of the
holders of not less than a majority in aggregate principal amount of the
Securities of each series affected by such supplemental indenture or indentures
at the time outstanding, the Company, when authorized by a Board Resolution, and
the Trustee may from time to time and at any time enter into an indenture or
indentures supplemental hereto (which shall conform to the provisions of the
Trust Indenture Act as then in effect) for the purpose of adding any provisions
to or changing in any manner or eliminating any of the provisions of this
Indenture or of any supplemental indenture or of modifying in any manner the
rights of the holders of the Securities of such series under this Indenture;
provided, however, that no such supplemental indenture shall (i) extend the
fixed maturity of any Securities of any series, or reduce the principal amount
thereof, or reduce the rate or extend the time of payment of interest thereon,
or reduce any premium payable upon the redemption thereof, or reduce the amount
of the principal of a Discount Security that would be due and payable upon a
declaration of acceleration of the maturity thereof pursuant to Section 6.01,
without the consent of the holders of each Security then outstanding and
affected, (ii) reduce the aforesaid percentage of Securities, the holders of
which are required to consent to any such supplemental indenture, or reduce the
percentage of Securities, the holders of which are required to waive any default
and its consequences, without the consent of the holder of each Security then
outstanding and affected thereby, or (iii) modify any provision of Section
6.01(c) (except to increase the percentage of principal amount of securities
required to rescind and annul any declaration of amounts due and payable under
the Securities) without the consent of the holders of each Security then
outstanding and affected thereby.

      Upon the request of the Company, accompanied by a Board Resolution
authorizing the execution of any such supplemental indenture, and upon the
filing with the Trustee of evidence of the consent of Securityholders required
to consent thereto as aforesaid, the Trustee shall join with the Company in the
execution of such supplemental indenture unless such supplemental indenture
affects the Trustee's own rights, duties or immunities under this Indenture or
otherwise, in which case the Trustee may in its discretion, but shall not be
obligated to, enter into such supplemental indenture.

      A supplemental indenture that changes or eliminates any covenant or other
provision of this Indenture that has expressly been included solely for the
benefit of one or more particular series of Securities, or that modifies the
rights of holders of Securities of such series with respect to such covenant or
other provision, shall be deemed not to affect the rights under this Indenture
of the holders of Securities of any other series.

      It shall not be necessary for the consent of the Securityholders of any
series affected thereby under this Section to approve the particular form of any
proposed supplemental indenture, but it shall be sufficient if such consent
shall approve the substance thereof.

      Promptly after the execution by the Company and the Trustee of any
supplemental indenture pursuant to the provisions of this Section, the Trustee
shall transmit by mail, first class postage prepaid, a notice, setting forth in
general terms the substance of such supplemental indenture, to the
Securityholders of all series affected thereby as their names and addresses
appear upon the Security Register. Any failure of the Trustee to mail such
notice, or any defect therein, shall not, however, in any way impair or affect
the validity of any such supplemental indenture.

SECTION 9.03. Upon the execution of any supplemental indenture pursuant to the
provisions of this Article or of Section 10.01, this Indenture shall, with
respect to such series, be and be deemed to be modified and amended in
accordance therewith and the respective rights, limitations of rights,
obligations, duties and immunities under this Indenture of the Trustee, the
Company and the holders of Securities of the series affected thereby shall
thereafter be determined, exercised and enforced hereunder subject in all
respects to such modifications and amendments, and all the terms and conditions
of any such supplemental indenture shall be and be deemed to be part of the
terms and conditions of this Indenture for any and all purposes.

SECTION 9.04. Securities of any series, affected by a supplemental indenture,
authenticated and delivered after the execution of such supplemental indenture
pursuant to the provisions of this Article, Article Two or Article Seven or of
Section 10.01, may bear a notation in form approved by the Company, provided
such form meets the requirements of any exchange upon which such series may be
listed, as to any matter provided for in such supplemental indenture. If the
Company shall so determine, new Securities of that series so modified as to
conform, in the opinion of the Board of Directors, to any modification of this
Indenture contained in any such supplemental indenture may be prepared by the
Company, authenticated by the Trustee and delivered in exchange for the
Securities of that series then outstanding.

SECTION 9.05. The Trustee, subject to the provisions of Section 7.01, shall be
entitled to receive, and shall be fully protected in relying upon, an Opinion of
Counsel as conclusive evidence that any supplemental indenture executed pursuant
to this Article is authorized or permitted by, and conforms to, the terms of
this Article and that it is proper for the Trustee under the provisions of this
Article to join in the execution thereof.

                                  ARTICLE TEN
                         CONSOLIDATION, MERGER AND SALE

SECTION 10.01. Unless a Company Order or supplemental indenture establishing a
series of Securities provides otherwise, nothing contained in this Indenture or
in any of the Securities shall prevent any consolidation or merger of the
Company with or into any other corporation or corporations (whether or not
affiliated with the Company), or successive consolidations or mergers in which
the Company or its successor or successors shall be a party or parties, or shall
prevent any sale, conveyance, transfer or other disposition of all or
substantially all of the property of the Company or its successor or successors
as an entirety, or substantially as an entirety, to any other corporation
(whether or not affiliated with the Company or its successor or successors)
authorized to acquire and operate the same; provided, however, the Company
hereby covenants and agrees that, upon any such consolidation, merger, sale,
conveyance, transfer or other disposition, the due and punctual payment of the
principal of (premium, if any) and interest on all of the Securities of all
series in accordance with the terms of each series, according to their tenor,
and the due and punctual performance and observance of all the covenants and
conditions of this Indenture with respect to each series or established with
respect to such series pursuant to Section 2.01 to be kept or performed by the
Company, shall be expressly assumed, by supplemental indenture (which shall
conform to the provisions of the Trust Indenture Act as then in effect)
satisfactory in form to the Trustee executed and delivered to the Trustee by the
entity formed by such consolidation, or into which the Company shall have been
merged, or by the entity which shall have acquired such property.

SECTION 10.02. Unless a Company Order or supplemental indenture establishing a
series of Securities provides otherwise:

(a)  In case of any such consolidation,  merger, sale,  conveyance,  transfer or
     other disposition and upon the assumption by the successor corporation,  by
     supplemental   indenture,   executed  and  delivered  to  the  Trustee  and
     satisfactory in form to the Trustee, of the due and punctual payment of the
     principal of and premium,  if any, and interest on all of the Securities of
     all series  outstanding and the due and punctual  performance of all of the
     covenants and conditions of this  Indenture or established  with respect to
     each  series  of the  Securities  pursuant  to  Section  2.01 to be kept or
     performed  by the  Company  with  respect to each  series,  such  successor
     corporation  shall succeed to and be substituted for the Company,  with the
     same effect as if it had been named  herein as the party of the first part,
     and thereupon (provided, that in the case of a lease, the term of the lease
     is at least as long as the longest  maturity of any Securities  outstanding
     at  such  time)  the  predecessor  corporation  shall  be  relieved  of all
     obligations  and covenants  under this Indenture and the  Securities.  Such
     successor  corporation  thereupon  may  cause to be  signed,  and may issue
     either  in  its  own  name  or in the  name  of the  Company  or any  other
     predecessor  obligor  on the  Securities,  any  or  all  of the  Securities
     issuable  hereunder  which  theretofore  shall not have been  signed by the
     Company and delivered to the Trustee; and, upon the order of such successor
     company,  instead of the Company, and subject to all the terms,  conditions
     and   limitations   in  this  Indenture   prescribed,   the  Trustee  shall
     authenticate  and shall deliver any Securities  which previously shall have
     been signed and delivered by the officers of the predecessor Company to the
     Trustee  for  authentication,  and  any  Securities  which  such  successor
     corporation  thereafter  shall  cause to be  signed  and  delivered  to the
     Trustee  for  that  purpose.  All the  Securities  so  issued  shall in all
     respects have the same legal rank and benefit  under this  Indenture as the
     Securities theretofore or thereafter issued in accordance with the terms of
     this Indenture as though all of such Securities had been issued at the date
     of the execution hereof.

(b)  In case of any such consolidation,  merger, sale,  conveyance,  transfer or
     other  disposition  such  changes  in  phraseology  and  form  (but  not in
     substance) may be made in the Securities  thereafter to be issued as may be
     appropriate.

(c)  Nothing  contained  in this  Indenture  or in any of the  Securities  shall
     prevent the Company  from  merging  into itself or acquiring by purchase or
     otherwise all or any part of the property of any other corporation (whether
     or not affiliated with the Company).

SECTION 10.03. The Trustee, subject to the provisions of Section 7.01, may
receive an Opinion of Counsel as conclusive evidence that any such
consolidation, merger, sale, conveyance, transfer or other disposition, and any
such assumption, comply with the provisions of this Article.

ARTICLE Eleven
                 DEFEASANCE AND CONDITIONS TO DEFEASANCE; UNCLAIMED MONIES

SECTION 11.01. Securities of a series may be defeased in accordance with their
terms and, unless the Company Order or supplemental indenture establishing the
series otherwise provides, in accordance with this Article.

      The Company at any time may terminate as to a series all of its
obligations for such series under this Indenture ("legal defeasance option").
The Company at any time may terminate as to a series its obligations, if any,
under any restrictive covenant which may be applicable to a particular series
("covenant defeasance option"). However, in the case of the legal defeasance
option, the Company's obligations in Sections 2.05, 2.07, 4.02, 7.06, 7.10 and
11.04 shall survive until the Securities of the series are no longer
outstanding; thereafter the Company's obligations in Sections 7.06, 7.10 and
11.04 shall survive.

      The Company may exercise its legal defeasance option notwithstanding its
prior exercise of its covenant defeasance option. If the Company exercises its
legal defeasance option, a series may not be accelerated because of an Event of
Default. If the Company exercises its covenant defeasance option, a series may
not be accelerated by reference to any restrictive covenant which may be
applicable to a particular series so defeased under the terms of the series.

      The Trustee, upon request of and at the cost and expense of the Company,
shall, subject to compliance with Section 13.06, acknowledge in writing the
discharge of those obligations that the Company terminates.

      The Company may exercise as to a series its legal defeasance option or its
covenant defeasance option if:

(1)   The Company irrevocably deposits in trust with the Trustee or another
      trustee (x) money in an amount which shall be sufficient; or (y) Eligible
      Obligations the principal of and the interest on which when due, without
      regard to reinvestment thereof, will provide moneys, which, together with
      the money, if any, deposited or held by the Trustee or such other trustee,
      shall be sufficient; or (z) a combination of money and Eligible
      Obligations which shall be sufficient, to pay the principal of and
      premium, if any, and interest, if any, due and to become due on such
      Securities on or prior to maturity;

(2)   the Company delivers to the Trustee a Certificate to the effect that the
      requirements set forth in clause (1) above have been satisfied;

(3)   immediately after the deposit no Default exists; and

(4)   the Company delivers to the Trustee an Opinion of Counsel to the effect
      that holders of the series will not recognize income, gain or loss for
      Federal income tax purposes as a result of the defeasance but will realize
      income, gain or loss on the Securities, including payments of interest
      thereon, in the same amounts and in the same manner and at the same time
      as would have been the case if such defeasance had not occurred and which,
      in the case of legal defeasance, shall be (x) accompanied by a ruling of
      the Internal Revenue Service issued to the Company or (y) based on a
      change in law or regulation occurring after the date hereof; and

(5)   the deposit specified in paragraph (1) above shall not result in the
      Company, the Trustee or the trust created in connection with such
      defeasance being deemed an "investment company" under the Investment
      Company Act of 1940, as amended.

      In the event the Company exercises its option to effect a covenant
defeasance with respect to the Securities of any series as described above and
the Securities of that series are thereafter declared due and payable because of
the occurrence of any Event of Default other than the Event of Default caused by
failing to comply with the covenants which are defeased, the amount of money and
securities on deposit with the Trustee may not be sufficient to pay amounts due
on the Securities of that series at the time of the acceleration resulting from
such Event of Default. However, the Company shall remain liable for such
payments.

SECTION 11.02. All monies or Eligible Obligations deposited with the Trustee
pursuant to Section 11.01 shall be held in trust and shall be available for
payment as due, either directly or through any paying agent (including the
Company acting as its own paying agent), to the holders of the particular series
of Securities for the payment or redemption of which such monies or Eligible
Obligations have been deposited with the Trustee.

SECTION 11.03. In connection with the satisfaction and discharge of this
Indenture all monies or Eligible Obligations then held by any paying agent under
the provisions of this Indenture shall, upon demand of the Company, be paid to
the Trustee and thereupon such paying agent shall be released from all further
liability with respect to such monies or Eligible Obligations.

SECTION 11.04. Any monies or Eligible Obligations deposited with any paying
agent or the Trustee, or then held by the Company, in trust for payment of
principal of or premium or interest on the Securities of a particular series
that are not applied but remain unclaimed by the holders of such Securities for
at least two years after the date upon which the principal of (and premium, if
any) or interest on such Securities shall have respectively become due and
payable, upon the written request of the Company and unless otherwise required
by mandatory provisions of applicable escheat or abandoned or unclaimed property
law, shall be repaid to the Company on May 31 of each year or (if then held by
the Company) shall be discharged from such trust; and thereupon the paying agent
and the Trustee shall be released from all further liability with respect to
such monies or Eligible Obligations, and the holder of any of the Securities
entitled to receive such payment shall thereafter, as an unsecured general
creditor, look only to the Company for the payment thereof.

SECTION 11.05. In connection with any satisfaction and discharge of this
Indenture pursuant to this Article Eleven, the Company shall deliver to the
Trustee an Officers' Certificate and an Opinion of Counsel to the effect that
all conditions precedent in this Indenture provided for relating to such
satisfaction and discharge have been complied with.

                                 ARTICLE TWELVE
                     IMMUNITY OF INCORPORATORS, STOCKHOLDERS, OFFICERS
                                  AND DIRECTORS

SECTION 12.01. No recourse under or upon any obligation, covenant or agreement
of this Indenture, or of any Security, or for any claim based thereon or
otherwise in respect thereof, shall be had against any incorporator,
stockholder, officer or director, past, present or future as such, of the
Company or of any predecessor or successor corporation, either directly or
through the Company or any such predecessor or successor corporation, whether by
virtue of any constitution, statute or rule of law, or by the enforcement of any
assessment or penalty or otherwise; it being expressly understood that this
Indenture and the obligations issued hereunder are solely corporate obligations,
and that no such personal liability whatever shall attach to, or is or shall be
incurred by, the incorporators, stockholders, officers or directors as such, of
the Company or of any predecessor or successor corporation, or any of them,
because of the creation of the indebtedness hereby authorized, or under or by
reason of the obligations, covenants or agreements contained in this Indenture
or in any of the Securities or implied therefrom; and that any and all such
personal liability of every name and nature, either at common law or in equity
or by constitution or statute, of, and any and all such rights and claims
against, every such incorporator, stockholder, officer or director as such,
because of the creation of the indebtedness hereby authorized, or under or by
reason of the obligations, covenants or agreements contained in this Indenture
or in any of the Securities or implied therefrom, are hereby expressly waived
and released as a condition of, and as a consideration for, the execution of
this Indenture and the issuance of such Securities.

                                ARTICLE THIRTEEN
                            MISCELLANEOUS PROVISIONS

SECTION 13.01. All the covenants, stipulations, promises and agreements in this
Indenture contained by or on behalf of the Company shall bind its successors and
assigns, whether so expressed or not.

SECTION 13.02. Any act or proceeding by any provision of this Indenture
authorized or required to be done or performed by any board, committee or
officer of the Company shall and may be done and performed with like force and
effect by the corresponding board, committee or officer of any corporation that
shall at the time be the lawful sole successor of the Company.

SECTION 13.03. The Company by instrument in writing executed by authority of
two-thirds of its Board of Directors and delivered to the Trustee may surrender
any of the powers reserved to the Company under this Indenture and thereupon
such power so surrendered shall terminate both as to the Company and as to any
successor corporation.

SECTION 13.04. Except as otherwise expressly provided herein any notice or
demand which by any provision of this Indenture is required or permitted to be
given or served by the Trustee or by the holders of Securities to or on the
Company may be given or served by being deposited first class postage prepaid in
a post office letter box addressed (until another address is filed in writing by
the Company with the Trustee), as follows: AEP Texas North Company, 1 Riverside
Plaza, Columbus, Ohio 43215, Attention: Treasurer. Any notice, election, request
or demand by the Company or any Securityholder to or upon the Trustee shall be
deemed to have been sufficiently given or made, for all purposes, if given or
made in writing at the Corporate Trust Office of the Trustee.

SECTION 13.05. This Indenture and each Security shall be deemed to be a contract
made under the laws of the State of New York, and for all purposes shall be
construed in accordance with the laws of said State.

SECTION 13.06. (a) Upon any application or demand by the Company to the Trustee
to take any action under any of the provisions of this Indenture, the Company
shall furnish to the Trustee an Officers' Certificate stating that all
conditions precedent provided for in this Indenture relating to the proposed
action have been complied with and an Opinion of Counsel stating that in the
opinion of such counsel all such conditions precedent have been complied with,
except that in the case of any such application or demand as to which the
furnishing of such documents is specifically required by any provision of this
Indenture relating to such particular application or demand, no additional
certificate or opinion need be furnished.

     (b)  Each  certificate  or  opinion  provided  for in  this  Indenture  and
delivered to the Trustee with respect to compliance with a condition or covenant
in this  Indenture  (other  than the  certificate  provided  pursuant to Section
5.03(d) of this Indenture)  shall include (1) a statement that the person making
such  certificate  or opinion has read such covenant or  condition;  (2) a brief
statement as to the nature and scope of the  examination or  investigation  upon
which the  statements or opinions  contained in such  certificate or opinion are
based;  (3) a statement that, in the opinion of such person,  he or she has made
such  examination  or  investigation  as is  necessary  to enable  him or her to
express an informed  opinion as to whether or not such covenant or condition has
been complied  with; and (4) a statement as to whether or not, in the opinion of
such person, such condition or covenant has been complied with.

SECTION 13.07. Except as provided pursuant to Section 2.01 pursuant to a Company
Order, or established in one or more indentures supplemental to this Indenture,
in any case where the date of maturity of principal or an Interest Payment Date
of any Security or the date of redemption, purchase or repayment of any Security
shall not be a Business Day then payment of interest or principal (and premium,
if any) may be made on the next succeeding Business Day with the same force and
effect as if made on the nominal date of maturity or redemption, and no interest
shall accrue for the period after such nominal date.

SECTION 13.08. If and to the extent that any provision of this Indenture limits,
qualifies or conflicts with the duties imposed by the Trust Indenture Act, such
imposed duties shall control.

SECTION 13.09. This Indenture may be executed in any number of counterparts,
each of which shall be an original; but such counterparts shall together
constitute but one and the same instrument.

SECTION 13.10. In case any one or more of the provisions contained in this
Indenture or in the Securities of any series shall for any reason be held to be
invalid, illegal or unenforceable in any respect, such invalidity, illegality or
unenforceability shall not affect any other provisions of this Indenture or of
such Securities, but this Indenture and such Securities shall be construed as if
such invalid or illegal or unenforceable provision had never been contained
herein or therein.

SECTION 13.11. The Company will have the right at all times to assign any of its
rights or obligations under the Indenture to a direct or indirect wholly owned
subsidiary of the Company; provided that, in the event of any such assignment,
the Company will remain liable for all such obligations. Subject to the
foregoing, this Indenture is binding upon and inures to the benefit of the
parties thereto and their respective successors and assigns. This Indenture may
not otherwise be assigned by the parties thereto.

SECTION 13.12. The Article and Section Headings in this Indenture and the Table
of Contents are for convenience only and shall not affect the construction
hereof.

SECTION 13.13. Whenever this Indenture provides for any action by, or the
determination of any rights of, holders of Securities of any series in which not
all of such Securities are denominated in the same currency, in the absence of
any provision to the contrary in the form of Security of any particular series,
any amount in respect of any Security denominated in a currency other than
Dollars shall be treated for any such action or determination of rights as that
amount of Dollars that could be obtained for such amount on such reasonable
basis of exchange and as of the record date with respect to Securities of such
series (if any) for such action or determination of rights (or, if there shall
be no applicable record date, such other date reasonably proximate to the date
of such action or determination of rights) as the Company may specify in a
written notice to the Trustee or, in the absence of such written notice, as the
Trustee may determine.


      Bank One, N.A., as Trustee,  hereby accepts the trusts in this Indenture  
declared and provided, upon the terms and conditions hereinabove set forth.

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

                                   AEP TEXAS NORTH COMPANY

                                   By /s/ Susan Tomasky
                                      Vice President
Attest:

By /s/ T. G. Berkemeyer
   Assistant Secretary
                                    BANK ONE, N. A.,
                                    as Trustee

                                    By /s/ Jeffery L. Eubank
                                       Vice President
Attest:

By /s/ David B. Knox
   Trust Officer






                                                                    EXHIBIT 4(c)




==============================================================================





                             AEP TEXAS NORTH COMPANY

                                       TO

                                 BANK ONE, N.A.

                                   AS TRUSTEE







                          FIRST SUPPLEMENTAL INDENTURE

                          DATED AS OF FEBRUARY 1, 2003







                                  $225,000,000

                      5.50% SENIOR NOTES, SERIES A DUE 2013

                      5.50% SENIOR NOTES, SERIES B DUE 2013






==============================================================================




<PAGE>


                               TABLE OF CONTENTS*

                                                                           Page


ARTICLE I Additional Definitions.............................................1

      SECTION 1.01.   Definitions............................................1

ARTICLE II 2013 Notes........................................................3

      SECTION 2.01.   Establishment..........................................3
      SECTION 2.02.   Aggregate Principal Amount.............................4
      SECTION 2.03.   Maturity and Interest..................................4
      SECTION 2.04.   Optional Redemption....................................4
      SECTION 2.05.   Limitation on Secured Debt.............................5
      SECTION 2.06.   Global Securities and Certificated Securities..........6
      SECTION 2.07.   Form of Securities.....................................8
      SECTION 2.08.   Transfer and Exchange..................................8

ARTICLE III Miscellaneous Provisions........................................13

      SECTION 3.01.   Recitals by Company...................................13
      SECTION 3.02.   Ratification and Incorporation of Original Indenture..13
      SECTION 3.03.   Executed in Counterparts..............................13
      SECTION 3.04.   Legends...............................................13
      SECTION 3.05.   Applicability of Section 4.05 and Article Ten of
                      Original Indenture....................................13


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



<PAGE>



     THIS FIRST SUPPLEMENTAL INDENTURE is made as of the 1st day of February,
2003, between AEP TEXAS NORTH COMPANY, a corporation duly organized
 and existing
under the laws of the state of Texas (herein called the "Company"), having its
principal office at 1 Riverside Plaza, Columbus, Ohio 43215 and Bank One, N.A.,
a national banking association, duly organized and existing under the laws of
the United States, having its principal corporate trust office at 1111 Polaris
Parkway, Columbus, Ohio 43240, as Trustee (herein called the "Trustee").

                             W I T N E S S E T H:

      WHEREAS, the Company has heretofore entered into an Indenture, dated as of
February 1, 2003 (the "Original Indenture"), with the Trustee;

      WHEREAS, the Original Indenture is incorporated herein by this reference
and the Original Indenture, as supplemented by this First Supplemental
Indenture, is herein called the "Indenture";

      WHEREAS, under the Original Indenture, a new series of unsecured notes
(the "Senior Notes") may at any time be established by the Board of Directors of
the Company in accordance with the provisions of the Original Indenture and the
terms of such series may be described by a supplemental indenture executed by
the Company and the Trustee;

      WHEREAS, the Company proposes to create under the Indenture a series of
Senior Notes to be designated the "5.50% Senior Notes, Series A due 2013" (the
"Series A Notes") and a series of Senior Notes to be designated the "5.50%
Senior Notes, Series B due 2013" (the "Series B Notes" and, together with the
Series A Notes, the "2013 Notes"), the form and substance of the 2013 Notes and
the terms, provisions and conditions thereof to be set forth as provided in the
Original Indenture and this First Supplemental Indenture;

      WHEREAS, additional Senior Notes of other series hereafter established,
except as may be limited in the Original Indenture as at the time supplemented
and modified, may be issued from time to time pursuant to the Indenture as at
the time supplemented and modified; and

      WHEREAS, all conditions necessary to authorize the execution and delivery
of this First Supplemental Indenture and to make it a valid and binding
obligation of the Company have been done or performed.

      NOW, THEREFORE, in consideration of the agreements and obligations set
forth herein and for other good and valuable consideration, the sufficiency of
which is hereby acknowledged, the parties hereto hereby agree as follows:

                                   ARTICLE I

                             Additional Definitions

SECTION 1.01.     Definitions

            The following defined terms used herein shall, unless the context
otherwise requires, have the meanings specified below. Capitalized terms used
herein for which no definition is provided herein shall have the meanings set
forth in the Original Indenture.

      "Clearstream" means Clearstream Banking, societe anonyme, or any successor
securities clearing agency.

      "Distribution Compliance Period," with respect to the 2013 Notes, means
the period of 40 consecutive days beginning on and including the later of (i)
the day on which such 2013 Notes are first offered to Persons other than
distributors (as defined in Regulation S under the Securities Act) in reliance
on Regulation S and (ii) the Original Issue Date.

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

      "Euroclear" means Euroclear Bank S.A./N.V., as operator of the Euroclear
System or any successor securities clearing agency.

      "Exchange Act" means the Securities Exchange Act of 1934, as amended.

      "Exchange Offer Registration Statement" shall have the meaning assigned to
it in the Registration Rights Agreement.

      "Generation-Related Business" has the meaning set forth in Section
3.05(a).

      "Global Securities" means global certificates representing the 2013 Notes
as described in Section 204.

      "Holder" means a registered holder of a 2013 Note.

      "Institutional Accredited Investor" has the meaning set forth in Section
2.04(a) hereof.

      "Original Issue Date" means February 18, 2003.

      "Owner" means each Person who is the beneficial owner of a Global Security
as reflected in the records of the Depository or, if a Depository participant is
not the Owner, then as reflected in the records of a Person maintaining an
account with such Depository (directly or indirectly, in accordance with the
rules of such Depository).

      "Permanent Regulation S Global Security" has the meaning set forth in
Section 2.04(b).

      "QIBs" means qualified institutional buyers as defined in Rule 144A.

      "Registered Exchange Offer" shall have the meaning assigned to Exchange
Offer in the Registration Rights Agreement

      "Registration Rights Agreement" means the Registration Rights Agreement,
dated as of February 1, 2003 among the Company and the Initial Purchasers named
therein, relating to the registration of the 2013 Notes under the Securities
Act.

      "Regulation S" means Regulation S under the Securities Act and any
successor regulation thereto.

      "Rule 144" means Rule 144 under the Securities Act, as such rule may be
amended from time to time, or any similar rule or regulation hereafter adopted
by the Securities and Exchange Commission.

      "Rule 144A" means Rule 144A under the Securities Act, as such rule may be
amended from time to time, or any similar rule or regulation hereafter adopted
by the Securities and Exchange Commission.

      "Rule 144A Global Security" means any Series A Note that is to be traded
pursuant to Rule 144A.

      "Securities Act" means the Securities Act of 1933, as amended from time to
time, or any successor legislation.

      "Securities Custodian" means the custodian with respect to a Global
Security (as appointed by the Depository), or any successor Person thereto and
shall initially be the Trustee.

      "Shelf Registration Statement" shall have the meaning assigned to it in
the Registration Rights Agreement.

      "Special Interest Premium" shall have the meaning assigned to it in the
Registration Rights Agreement.

      "Stated Maturity" means March 1, 2013.

      "Subsidiary" means any corporation or other entity of which sufficient
voting stock or other ownership or economic interests having ordinary voting
power to elect a majority of the board of directors (or equivalent body) are at
the time directly or indirectly held by the Company.

      "Temporary Regulation S Global Security" has the meaning set forth in
Section 2.04(b).

      "Transfer Restricted Security" shall have the meaning assigned to
Registrable Note in the Registration Rights Agreement.

                                   ARTICLE II

                                   2013 Notes

SECTION 2.01. Establishment. The Series A Notes shall be designated as the
Company's "5.50% Senior Notes, Series A due 2013" and the Series B Notes shall
be designated as the Company's "5.50% Senior Notes, Series B due 2013". The
Series A Notes and the Series B Notes shall be treated for all purposes under
the Indenture as a single class or series of Senior Notes.

SECTION 2.02. Aggregate Principal Amount. The Trustee shall authenticate and
deliver (i) Series A Notes for original issue on the Original Issue Date in the
aggregate principal amount of $225,000,000 and (ii) Series B Notes from time to
time thereafter for issue only in exchange for Series A Notes pursuant to the
Exchange Offer Registration Statement in accordance with the Registration Rights
Agreement or pursuant to the Shelf Registration Statement in accordance with the
Registration Rights Agreement, in each case upon a Company Order for
authentication and delivery thereof and satisfaction of Section 2.01 of the
Original Indenture. The aggregate principal amount of the 2013 Notes shall be
initially limited to $225,000,000 and shall be subject to Periodic Offerings
pursuant to Article Two of the Original Indenture. All 2013 Notes need not be
issued at the same time and such series may be reopened at any time, without the
consent of any Holder, for issuances of additional 2013 Notes. Any such
additional 2013 Notes will have the same interest rate, maturity and other terms
as those initially issued. The Series A Notes shall be issued in definitive
fully registered form.

SECTION 2.03. Maturity and Interest. 

(i)  The 2013 Notes shall mature on, and the date on which the  principal of the
     2013 Notes shall be payable  (unless  earlier  redeemed) shall be, March 1,
     2013;

(ii) the  interest  rate at which the 2013 Notes  shall bear  interest  shall be
     5.50% per annum; provided, however, that the Special Interest Premium shall
     accrue on the 2013 Notes under certain  circumstances as provided in clause
     (iii) below;  interest shall accrue from the date of  authentication of the
     2013 Notes;  the  Interest  Payment  Dates on which such  interest  will be
     payable shall be March 1 and  September 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 February 15 or August 15 preceding  the
     relevant  Interest  Payment Date;  provided that the first Interest Payment
     Date shall be September 1, 2003 and interest payable on the Stated Maturity
     or any redemption  date shall be paid to the Person to whom principal shall
     be paid;  each payment of interest shall include  interest  accrued through
     the day before the Interest Payment Date;

(iii)Special   Interest   Premium  shall  accrue  on  the  Transfer   Restricted
     Securities  over and above the interest rate set forth herein in accordance
     with Section 2(e) of the Registration Rights Agreement.

SECTION 2.04. Optional Redemption. The 2013 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 2013 Notes being redeemed and (ii)
the sum of the present values of the remaining scheduled payments of principal
and interest on the 2013 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 25 basis points, plus, 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 2013 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
            2013 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 as 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 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.

SECTION 2.05. Limitation on Secured Debt.. So long as any of the 2013 Notes are
outstanding, the Company shall not create or suffer to be created or to exist or
permit any of its Subsidiaries to create or suffer to be created or to exist any
additional mortgage, pledge, security interest, or other lien (collectively
"Liens") on any utility properties or tangible assets now owned or hereafter
acquired by the Company or its Subsidiaries to secure any indebtedness for
borrowed money ("Secured Debt"), without providing that such 2013 Notes will be
similarly secured. 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 indenture 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:

o    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;

o    Financing of the Company's accounts receivable for electric service;

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

o    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, energy trading contracts,
regulatory assets, deferred charges 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.

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

SECTION 2.06.     Global Securities and Certificated Securities.

(a)  General.  The Series A Notes will be resold  initially  only to (i) QIBs in
     reliance  on Rule  144A  under  the  Securities  Act  ("Rule  144A"),  (ii)
     institutional  "accredited  investors"  as  such  term is  defined  in rule
     501(a)(1),  (2),(3) and (7) of Regulation D under the Securities Act (each,
     an "Institutional  Accredited  Investor") and (iii) Persons other than U.S.
     Persons (as defined in  Regulation S) in reliance on Regulation S under the
     Securities  Act  ("Regulation   S").  Series  A  Notes  may  thereafter  be
     transferred to, among others, QIBs, purchasers in reliance on Regulation S,
     and  Institutional  Accredited  Investors  in  each  case,  subject  to the
     restrictions on transfer set forth herein.

(b)  Global Securities.

     (i)  Form.  Series A Notes initially  resold pursuant to Rule 144A shall be
          issued  initially  in  the  form  of  one  or  more  permanent  Global
          Securities in definitive,  fully  registered form  (collectively,  the
          "Rule  144A  Global  Security")  and Series A Notes  initially  resold
          pursuant to Regulation S and shall be issued  initially in the form of
          one  or  more  temporary  global   securities  in  definitive,   fully
          registered  form  (collectively,  the  "Temporary  Regulation S Global
          Security"),  in each case without interest coupons and with the global
          securities  legend  and  restricted  securities  legend  set  forth in
          Exhibit A hereto, which shall be deposited on behalf of the purchasers
          of  the  Series  A  Notes  represented  thereby  with  the  Securities
          Custodian,  and  registered in the name of the Depository or a nominee
          of the Depository,  duly executed by the Company and  authenticated by
          the Trustee as provided in the Indenture.  Except as set forth in this
          Section  2.06,   beneficial   ownership  interests  in  the  Temporary
          Regulation  S  Global  Security  (x)  will  not  be  exchangeable  for
          interests  in the Rule 144A  Global  Security,  the  permanent  global
          security (the "Permanent Regulation S Global Security"),  or any other
          security without a legend containing  restrictions on transfer of such
          security prior to the expiration of the Distribution Compliance Period
          and (y) then may be  exchanged  for  interests  in a Rule 144A  Global
          Security  or the  Permanent  Regulation  S Global  Security  only upon
          certification  that beneficial  ownership  interests in such Temporary
          Regulation S Global  Security are owned either by non-U.S.  persons or
          U.S.  persons who purchased such  interests in a transaction  that did
          not require registration under the Securities Act.

          The Rule 144A  Global  Security,  the  Temporary  Regulation  S Global
          Security  and  the   Permanent   Regulation  S  Global   Security  are
          collectively referred to herein as "Global Securities".  The aggregate
          principal  amount of the  Global  Securities  may from time to time be
          increased  or  decreased  by  adjustments  made on the  records of the
          Trustee and the Depository or its nominee as hereinafter provided.

     (ii) Book-Entry  Provisions.  This  Section  shall  apply  only to a Global
          Security  deposited with or on behalf of the  Depository.  The Company
          shall execute and the Trustee shall,  in accordance  with this Section
          2.06(b)(ii),  authenticate  and deliver  initially  one or more Global
          Securities  that (a) shall be registered in the name of the Depository
          for such Global  Security or Global  Securities or the nominee of such
          Depository  and  (b)  shall  be  delivered  by  the  Trustee  to  such
          Depository or pursuant to such  Depository's  instructions  or held by
          the Trustee as custodian for the Depository.

          Members of, or participants in, the Depository ("Agent Members") shall
          have no  rights  under  this  Indenture  with  respect  to any  Global
          Security  held on their behalf by the  Depository or by the Trustee as
          the custodian of the Depository or under such Global Security, and the
          Company, the Trustee and any agent of the Company or the Trustee shall
          be  entitled to treat the  Depository  as the  absolute  owner of such
          Global  Security  for all  purposes  whatsoever.  Notwithstanding  the
          foregoing,  nothing  herein shall prevent the Company,  the Trustee or
          any agent of the  Company or the  Trustee  from  giving  effect to any
          written certification,  proxy or other authorization  furnished by the
          Depository or impair, as between the Depository and its Agent Members,
          the operation of customary practices of such Depository  governing the
          exercise  of the rights of a holder of a  beneficial  interest  in any
          Global Security.

          To the extent a notice or other communication to the beneficial owners
          of the 2013 Notes is required  under the  Indenture,  unless and until
          Certificated  Securities  shall have been issued to such  owners,  the
          Trustee  shall  give all such  notices  and  communications  specified
          herein to be given to such owners to the Depository, and shall have no
          obligations to such Owners.

(c)  Certificated  Securities.  Series A Notes sold to Institutional  Accredited
     Investors  shall be  issued  initially  in the form of a fully  registered,
     certificated Series A Note ("Certificated Securities").  Except as provided
     in this Section 2.06,  owners of beneficial  interests in Global Securities
     shall  not  be  entitled  to  receive  physical  delivery  of  Certificated
     Securities.

      Global Securities shall be exchangeable for Certificated Securities if (i)
the Depository (x) notifies the Company that it is unwilling or unable to
continue as Depository for the Global Securities or (y) shall no longer be
registered or in good standing under the Exchange Act, or other applicable
statute or regulation, and a successor Depository for the Global Securities is
not appointed by the Company within 90 days after the Company receives such
notice or becomes aware of such condition. Upon surrender to the Trustee of the
typewritten certificate or certificates representing the Global Securities by
the Depository, accompanied by registration instructions, the Trustee shall
execute and authenticate the certificates in accordance with the instructions of
the Depository. Neither the Security Registrar nor the Trustee shall be liable
for any delay in delivery of such instructions and may conclusively rely on, and
shall be protected in relying on, such instructions. Upon the issuance of
Certificated Securities, the Trustee shall recognize the Holders of the
Certificated Securities as Holders. The Certificated Securities shall be
printed, lithographed or engraved or may be produced in any other manner as is
reasonably acceptable to the Company, as evidenced by the execution thereof by
the Company, and shall bear the legend set forth on Exhibit A hereto unless the
Company informs the Trustee that such legend is no longer required.

SECTION 2.07.     Form of Securities.  The Global Securities and Certificated
Securities shall be substantially in the form attached as Exhibit A thereto.

SECTION 2.08.     Transfer and Exchange.

(a)  General.  The 2013 Notes may not be transferred  except in compliance  with
     the  legend  contained  in  Exhibit A unless  otherwise  determined  by the
     Company in accordance  with  applicable law. No service charge will be made
     for any transfer or exchange of 2013 Notes, but payment will be required of
     a sum sufficient to cover any tax or other governmental  charge that may be
     imposed in connection therewith.

(b)  Transfer and Exchange of Global Securities.

     (i)  If a holder of a beneficial  interest in the Rule 144A Global Security
          wishes at any time to  exchange  its  interest in the Rule 144A Global
          Security  for  an  interest  in  the  Permanent  Regulation  S  Global
          Security, or to transfer its interest in the Rule 144A Global Security
          to a person  who  wishes to take  delivery  thereof  in the form of an
          interest in the Permanent  Regulation S Global  Security,  such holder
          may,  subject to the rules and procedures of the Depository and to the
          requirements  set forth in the following  sentence,  exchange or cause
          the exchange or transfer or cause the transfer of such interest for an
          equivalent  beneficial  interest in the Permanent  Regulation S Global
          Security.  Upon  receipt by the  Trustee,  as transfer  agent,  of (1)
          instructions given in accordance with the Depository's procedures from
          or on  behalf of a holder of a  beneficial  interest  in the Rule 144A
          Global Security,  directing the Trustee,  as transfer agent, to credit
          or  cause  to be  credited  a  beneficial  interest  in the  Permanent
          Regulation  S Global  Security  in an amount  equal to the  beneficial
          interest  in  the  Rule  144A  Global  Security  to  be  exchanged  or
          transferred,  (2)  a  written  order  given  in  accordance  with  the
          Depository's procedures containing information regarding the Euroclear
          or Clearstream  account to be credited with such increase and the name
          of such account, and (3) a certificate in the form of Exhibit C hereto
          given by the  holder  of such  beneficial  interest  stating  that the
          exchange or transfer of such interest has been made pursuant to and in
          accordance  with  Rule  903 or Rule  904 of  Regulation  S  under  the
          Securities Act, the Trustee, as transfer agent, shall promptly deliver
          appropriate  instructions  to  the  Depository,  its  nominee,  or the
          custodian for the Depository, as the case may be, to reduce or reflect
          on its  records a reduction  of the Rule 144A  Global  Security by the
          aggregate  principal  amount of the  beneficial  interest in such Rule
          144A  Global  Security  to be so  exchanged  or  transferred  from the
          relevant  participant,  and the  Trustee,  as  transfer  agent,  shall
          promptly  deliver  appropriate  instructions  to the  Depository,  its
          nominee,  or the  custodian  for the  Depository,  as the case may be,
          concurrently  with such  reduction,  to  increase  or  reflect  on its
          records  an  increase  of  the  principal  amount  of  such  Permanent
          Regulation S Global Security by the aggregate  principal amount of the
          beneficial  interest  in  such  Rule  144A  Global  Security  to be so
          exchanged or transferred, and to credit or cause to be credited to the
          account  of the  person  specified  in such  instructions  (who may be
          Euroclear  or  Clearstream  or another  agent  member of  Euroclear or
          Clearstream  or both,  as the case may be, acting for and on behalf of
          them) a  beneficial  interest in such  Permanent  Regulation  S Global
          Security  equal to the reduction in the principal  amount of such Rule
          144A Global Security.

     (ii) If a holder of a  beneficial  interest in the  Permanent  Regulation S
          Global  Security  wishes at any time to exchange  its  interest in the
          Permanent  Regulation  S Global  Security  for an interest in the Rule
          144A Global  Security,  or to transfer its  interest in the  Permanent
          Regulation S Global  Security to a person who wishes to take  delivery
          thereof in the form of an interest  in the Rule 144A Global  Security,
          such holder may,  subject to the rules and  procedures of Euroclear or
          Clearstream  and  the  Depository,  as the  case  may  be,  and to the
          requirements  set forth in the following  sentence,  exchange or cause
          the exchange or transfer or cause the transfer of such interest for an
          equivalent beneficial interest in such Rule 144A Global Security. Upon
          receipt by the Trustee,  as transfer agent, of (1) instructions  given
          in accordance  with the procedures of Euroclear or Clearstream and the
          Depository,  as the case may be,  from or on  behalf  of a  beneficial
          owner of an interest in the  Permanent  Regulation  S Global  Security
          directing  the Trustee,  as transfer  agent,  to credit or cause to be
          credited a beneficial  interest in the Rule 144A Global Security in an
          amount equal to the beneficial interest in the Permanent  Regulation S
          Global  Security to be exchanged or  transferred,  (2) a written order
          given in accordance  with the  procedures of Euroclear or  Clearstream
          and  the  Depository,  as the  case  may  be,  containing  information
          regarding  the account with the  Depository  to be credited  with such
          increase and the name of such account, and (3) prior to the expiration
          of the  Distribution  Compliance  Period, a certificate in the form of
          Exhibit C hereto given by the holder of such  beneficial  interest and
          stating that the person  transferring  such interest in such Permanent
          Regulation  S Global  Security  reasonably  believes  that the  person
          acquiring such interest in the Rule 144A Global  Security is a QIB and
          is  obtaining  such  beneficial  interest  for its own  account or the
          account of a QIB in a  transaction  meeting the  requirements  of Rule
          144A and any  applicable  securities  laws of any state of the  United
          States or any other  jurisdiction,  the  Trustee,  as transfer  agent,
          shall promptly deliver appropriate instructions to the Depository, its
          nominee,  or the custodian for the Depository,  as the case may be, to
          reduce  or  reflect  on its  records  a  reduction  of  the  Permanent
          Regulation S Global Security by the aggregate  principal amount of the
          beneficial interest in such Permanent  Regulation S Global Security to
          be exchanged or transferred, and the Trustee, as transfer agent, shall
          promptly  deliver  appropriate  instructions  to the  Depository,  its
          nominee,  or the  custodian  for the  Depository,  as the case may be,
          concurrently  with such  reduction,  to  increase  or  reflect  on its
          records an  increase of the  principal  amount of the Rule 144A Global
          Security by the aggregate  principal amount of the beneficial interest
          in the  Permanent  Regulation S Global  Security to be so exchanged or
          transferred,  and to credit or cause to be  credited to the account of
          the person specified in such instructions a beneficial interest in the
          Rule 144A Global  Security  equal to the  reduction  in the  principal
          amount  of the  Permanent  Regulation  S Global  Security.  After  the
          expiration of the Distribution  Compliance  Period,  the certification
          requirement  set forth in clause  (3) of the second  sentence  of this
          Section  2.08(b)(ii)  will  no  longer  apply  to such  exchanges  and
          transfers.

     (iii)Any  beneficial  interest  in one of the  Global  Securities  that  is
          transferred  to a person who takes delivery in the form of an interest
          in the other Global  Securities  will,  upon transfer,  cease to be an
          interest in such Global  Security  and become an interest in the other
          Global Securities and, accordingly,  will thereafter be subject to all
          transfer  restrictions and other  procedures  applicable to beneficial
          interests in such other Global Security Note for as long as it remains
          such an interest.

     (iv) Beneficial  interests in Temporary  Regulation S Global Securities may
          be exchanged for interests in Rule 144A Global Securities or Permanent
          Regulation  S  Global  Securities  if  (1)  such  exchange  occurs  in
          connection with a transfer of securities in compliance with Rule 144A,
          and (2) the  transferor  of the  beneficial  interest in the Temporary
          Regulation S Global  Security  first delivers to the Trustee a written
          certificate (in a form satisfactory to the Trustee) to the effect that
          the beneficial interest in the Temporary  Regulation S Global Security
          is being  transferred  to a Person (a) who the  transferor  reasonably
          believes to be a QIB (b) purchasing for its own account or the account
          of a QIB in a transaction  meeting the  requirements of Rule 144A, and
          (c) in accordance with all applicable securities laws of the states of
          the United States and other jurisdictions.

     (v)  During  the  Distribution  Compliance  Period,   beneficial  ownership
          interests in  Temporary  Regulation  S Global  Securities  may only be
          sold,  pledged or  transferred  through  Euroclear or  Clearstream  in
          accordance   with  the   applicable   procedures   relating   to  such
          institutions  and  only  (i) to the  Company,  (ii)  so  long  as such
          security is  eligible  for resale  pursuant to Rule 144A,  to a Person
          whom the selling  holder  reasonably  believes is a QIB that purchases
          for  its own  account  or for the  account  of a QIB in a  transaction
          meeting  the   requirements  of  Rule  144A,   (iii)  in  an  offshore
          transaction in accordance  with Regulation S (other than a transaction
          resulting  in an exchange  for  interest in a Permanent  Regulation  S
          Global  Security),  (iv)  pursuant to an exemption  from  registration
          under the  Securities Act provided by Rule 144 (if  applicable)  under
          the  Securities  Act  or (v)  pursuant  to an  effective  registration
          statement  under the Securities  Act, in each case in accordance  with
          any applicable securities laws of any state of the United States.

(c)  Transfer and Exchange of Global Securities and Certificated Securities.

     (i)  In the event that a Global  Security is exchanged  for a  Certificated
          Security as provided in Section 2.06(c),  such  Certificated  Security
          may be exchanged or  transferred  for one another,  subject to Section
          2.05  of  the  Original  Indenture,   only  in  accordance  with  such
          procedures  as are  substantially  consistent  with the  provisions of
          clauses   (b)(i)  and  (ii)   above   (including   the   certification
          requirements  intended  to ensure  that such  exchanges  or  transfers
          comply with Rule 144,  Rule 144A or  Regulation S, as the case may be)
          and as may be from time to time reasonably adopted by the Company.

     (ii) Upon receipt by the Trustee of a Certificated Security,  duly endorsed
          or  accompanied by  appropriate  instruments of transfer,  the Trustee
          shall  cancel  such  Certificated  Security  and cause,  or direct the
          Securities  Custodian  to  cause,  in  accordance  with  the  standing
          instructions  and  procedures  existing  of  the  Depository  and  the
          Securities  Custodian,  the aggregate  principal  amount of 2013 Notes
          represented by the Rule 144A Global Security or Permanent Regulation S
          Global  Security,  as  applicable,  to be increased  by the  aggregate
          principal  amount of the  Certificated  Security to be  exchanged  and
          shall  credit or cause to be  credited  to the  account  of the Person
          specified in such instructions a beneficial  interest in the Rule 144A
          Global  Security  or  Permanent  Regulation  S  Global  Security,   as
          applicable, equal to the principal amount of the Certificated Security
          so canceled. If no Rule 144A Global Securities or Permanent Regulation
          S Global Securities, as applicable, are then outstanding,  the Company
          shall issue and the Trustee shall authenticate,  upon written order of
          the Company in the form of an Officers'  Certificate,  a new Rule 144A
          Global  Security  or  Permanent  Regulation  S  Global  Security,   as
          applicable, in the appropriate principal amount.

(d)  Certificates.  In connection with any transfer  described in paragraphs (b)
     and (c) of this Section 2.08,  the Trustee  shall receive a certificate  of
     transfer in the form attached as Exhibit C hereto.  Additionally,  upon any
     transfer or exchange to an Institutional  Accredited Investor,  the Company
     and the Trustee shall receive a certificate in the form attached as Exhibit
     D hereto.

(e)  Transfer  Restricted  Security.  Upon any sale or  transfer  of a  Transfer
     Restricted Security (including any Transfer Restricted Security represented
     by a Global  Security)  pursuant to Rule 144 under the Securities Act or an
     effective  registration  statement under the Securities Act, which shall be
     certified  to the  Trustee  and  Security  Registrar  upon  which  each may
     conclusively rely:

     (i)  in the  case of any  Transfer  Restricted  Security  represented  by a
          Certificated  Security, the Security Registrar shall permit the Holder
          thereof  to  exchange   such  Transfer   Restricted   Security  for  a
          Certificated  Security  that  does not bear the  legend  set  forth in
          Exhibit A hereto and rescind any  restriction  on the transfer of such
          Transfer Restricted Security; and

     (ii) in the  case of any  Transfer  Restricted  Security  represented  by a
          Global  Security,  such  Transfer  Restricted  Security  shall  not be
          required to bear the legend set forth in Exhibit A hereto if all other
          interests in such Global Note have been or are concurrently being sold
          or  transferred  pursuant  to Rule 144  under  the  Securities  Act or
          pursuant to an effective  registration  statement under the Securities
          Act.

(f)  Registered Exchange Offer. Notwithstanding the foregoing, upon consummation
     of the Registered Exchange Offer, the Company shall issue and, upon receipt
     of a  Company  Order  in  accordance  with  Section  2.05  of the  Original
     Indenture,  the Trustee shall  authenticate  Series B Notes in exchange for
     Series A Notes  accepted for  exchange in the  Registered  Exchange  Offer,
     which  Series B Notes shall not bear the  transfer  restriction  legend set
     forth in  Exhibit A hereto  and  shall not  provide  for  Special  Interest
     Premium and the Security  Registrar  shall rescind any  restriction  on the
     transfer  of such  Series B Notes,  in each case  unless the Holder of such
     Series A Notes (A) is a  broker-dealer  tendering  Series A Notes  acquired
     directly from the Company or an  "affiliate"  (as defined in Rule 144 under
     the Securities Act) of the Company for its own account, (B) is a Person who
     has an arrangement or  understanding  with any Person to participate in the
     "distribution"  (within the meaning of the Securities  Act) of the Series B
     Notes,  (C) is a Person who is an "affiliate" (as defined in Rule 144 under
     the Securities  Act) of the Company or (D) will not be acquiring the Series
     B Notes in the ordinary course of such Holder's business. The Company shall
     identify to the Trustee such Holders in a written  certification  signed by
     an Officer of the Company  and,  absent  certification  from the Company to
     such effect, the Trustee shall assume that there are no such Holders.

                                  ARTICLE III

                            Miscellaneous Provisions

SECTION 3.01. Recitals by Company. The recitals in this First Supplemental
Indenture are made by the Company only and not by the Trustee, and all of the
provisions contained in the Original Indenture in respect of the rights,
privileges, immunities, powers and duties of the Trustee shall be applicable in
respect of 2013 Notes and of this First Supplemental Indenture as fully and with
like effect as if set forth herein in full.

SECTION 3.02. Ratification and Incorporation of Original Indenture. As
supplemented hereby, the Original Indenture is in all respects ratified and
confirmed, and the Original Indenture and this First Supplemental Indenture
shall be read, taken and construed as one and the same instrument.

SECTION 3.03. Executed in Counterparts. This First Supplemental Indenture may be
simultaneously executed in several counterparts, each of which shall be deemed
to be an original, and such counterparts shall together constitute but one and
the same instrument.

SECTION 3.04. Legends. Except as determined by the Company in accordance with
applicable law, each 2013 Note shall bear the applicable legends relating to
restrictions on transfer pursuant to the securities laws in substantially the
form set forth on Exhibit A hereto.

SECTION 3.05. Applicability of Section 4.05 and Article Ten of Original
Indenture. As long as the 2013 Notes are outstanding, Section 4.05 and Article
Ten of the Original Indenture shall be applicable thereto; provided, however,
that if the Company's generation-related assets ("Generation-Related Business")
are transferred or sold (whether or not the Generation-Related Business
constitutes "substantially all" of the Company's total assets), the 2013 Notes
will continue to be obligations of the Company.

            IN WITNESS WHEREOF, each party hereto has caused this instrument to
be signed in its name and behalf by its duly authorized signatories, all as of
the day and year first above written.

                                    AEP TEXAS NORTH COMPANY

                                    By /s/ Susan Tomasky
                                       Vice President
Attest:

By /s/ T. G. Berkemeyer
   Assistant Secretary
                                    BANK ONE, N. A.,
                                    as Trustee

                                    By /s/ Jeffery L. Eubank
                                       Vice President
Attest:

By /s/ David B. Knox
  Trust Officer




<PAGE>


                                    EXHIBIT A

                            FORM OF SERIES [A/B] NOTE



                                                   [Rule 144A Global Security]
                                                [Regulation S Global Security]
                                                       [Certificated Security]



                       [FORM OF FACE OF INITIAL SECURITY]

                           [Global Securities Legend]


            UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE
OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION, TO THE COMPANY OR ITS
AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT, AND ANY CERTIFICATE
ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR SUCH OTHER NAME AS IS
REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY (AND
ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN
AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY), ANY TRANSFER, PLEDGE
OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL SINCE
THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN.

            TRANSFERS OF THIS GLOBAL SECURITY SHALL BE LIMITED TO TRANSFERS IN
WHOLE, BUT NOT IN PART, TO NOMINEES OF DTC OR TO A SUCCESSOR THEREOF OR SUCH
SUCCESSOR'S NOMINEE AND TRANSFERS OR PORTIONS OF THIS GLOBAL SECURITY SHALL BE
LIMITED TO TRANSFERS MADE IN ACCORDANCE WITH THE RESTRICTIONS SET FORTH IN THE
INDENTURE REFERRED TO ON THE REVERSE HEREOF.

            [FOR REGULATION S GLOBAL NOTE ONLY] UNTIL 40 DAYS AFTER THE
COMMENCEMENT OF THE OFFERING, AN OFFER OR SALE OF NOTES WITHIN THE UNITED STATES
BY A DEALER (AS DEFINED IN THE U.S. SECURITIES ACT) MAY VIOLATE THE REGISTRATION
REQUIREMENTS OF THE U.S. SECURITIES ACT IF SUCH OFFER OR SALE IS MADE OTHERWISE
THAN IN ACCORDANCE WITH RULE 144A THEREUNDER.]

                         [Restricted Securities Legend]

            THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF
1933, AS AMENDED (THE "SECURITIES ACT"). THE HOLDER HEREOF, BY PURCHASING THIS
SECURITY, AGREES FOR THE BENEFIT OF THE COMPANY THAT THIS SECURITY MAY NOT BE
RESOLD, PLEDGED OR OTHERWISE TRANSFERRED OTHER THAN (A)(1) TO THE COMPANY, (2)
IN A TRANSACTION ENTITLED TO AN EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144
UNDER THE SECURITIES ACT, (3) SO LONG AS THIS SECURITY IS ELIGIBLE FOR RESALE
PURSUANT TO RULE 144A UNDER THE SECURITIES ACT ("RULE 144A"), TO A PERSON WHOM
THE SELLER REASONABLY BELIEVES IS A QUALIFIED INSTITUTIONAL BUYER WITHIN THE
MEANING OF RULE 144A PURCHASING FOR ITS OWN ACCOUNT OR FOR THE ACCOUNT OF A
QUALIFIED INSTITUTIONAL BUYER TO WHOM NOTICE IS GIVEN THAT THE RESALE, PLEDGE OR
OTHER TRANSFER IS BEING MADE IN RELIANCE ON RULE 144A, (4) OUTSIDE THE UNITED
STATES IN A TRANSACTION MEETING THE REQUIREMENTS OF REGULATION S UNDER THE
SECURITIES ACT, (5) IN ACCORDANCE WITH ANOTHER APPLICABLE EXEMPTION FROM THE
REGISTRATION REQUIREMENTS OF THE SECURITIES ACT (AND BASED UPON AN OPINION OF
COUNSEL ACCEPTABLE TO THE COMPANY) OR (6) PURSUANT TO A REGISTRATION STATEMENT
WHICH HAS BEEN DECLARED EFFECTIVE UNDER THE SECURITIES ACT AND (B) IN EACH CASE
IN ACCORDANCE WITH ANY APPLICABLE SECURITIES LAWS OF EACH STATE OF THE UNITED
STATES. AN INSTITUTIONAL ACCREDITED INVESTOR HOLDING THIS SECURITY AGREES IT
WILL FURNISH TO THE COMPANY AND THE TRUSTEE SUCH CERTIFICATES AND OTHER
INFORMATION AS THEY MAY REASONABLY REQUIRE TO CONFIRM THAT ANY TRANSFER BY IT OF
THIS SECURITY COMPLIES WITH THE FOREGOING RESTRICTIONS. THE HOLDER HEREOF, BY
PURCHASING THIS SECURITY, REPRESENTS AND AGREES FOR THE BENEFIT OF THE COMPANY
THAT IT IS (1) A QUALIFIED INSTITUTIONAL BUYER WITHIN THE MEANING OF RULE 144A
OR (2) AN INSTITUTION THAT IS AN "ACCREDITED INVESTOR" AS DEFINED IN RULE
501(A)(1), (2),(3) OR (7) UNDER THE SECURITIES ACT AND THAT IT IS HOLDING THIS
SECURITY FOR INVESTMENT PURPOSES AND NOT FOR DISTRIBUTION OR (3) A NON-U.S.
PERSON OUTSIDE THE UNITED STATES WITHIN THE MEANING OF REGULATION S UNDER THE
SECURITIES ACT.

               [Temporary Regulation S Global Security Legend]

            EXCEPT AS SET FORTH BELOW, BENEFICIAL OWNERSHIP INTEREST IN THIS
TEMPORARY REGULATION S GLOBAL SECURITY WILL NOT BE EXCHANGEABLE FOR INTERESTS IN
THE PERMANENT REGULATION S GLOBAL SECURITY OR ANY OTHER SECURITY REPRESENTING AN
INTEREST IN THE SECURITIES REPRESENTED HEREBY WHICH DO NOT CONTAIN A LEGEND
CONTAINING RESTRICTIONS ON TRANSFER, UNTIL THE EXPIRATION OF THE "40-DAY
DISTRIBUTION COMPLIANCE PERIOD" (WITHIN THE MEANING OF RULE 903(d)(3) OF
REGULATION S UNDER THE SECURITIES ACT) AND THEN ONLY UPON CERTIFICATION IN FORM
REASONABLY SATISFACTORY TO THE TRUSTEE THAT SUCH BENEFICIAL INTERESTS ARE OWNED
EITHER BY NON-U.S. PERSONS OR U.S. PERSONS WHO PURCHASED SUCH INTERESTS IN A
TRANSACTION THAT DID NOT REQUIRE REGISTRATION UNDER THE SECURITIES ACT. DURING
SUCH 40-DAY DISTRIBUTION COMPLIANCE PERIOD, BENEFICIAL OWNERSHIP INTEREST IN
THIS TEMPORARY REGULATION S GLOBAL SECURITY MAY ONLY BE SOLD, PLEDGED OR
TRANSFERRED THROUGH EUROCLEAR BANK S.A./N.A., AS OPERATOR OF THE EUROCLEAR
SYSTEM OR CLEARSTREAM BANKING, SOCIETE ANONYME AND ONLY (I) TO THE COMPANY, (II)
IN THE UNITED STATES TO A PERSON WHOM THE SELLER REASONABLY BELIEVES IS A
QUALIFIED INSTITUTIONAL BUYER (AS DEFINED IN RULE 144A UNDER THE SECURITIES ACT)
IN A TRANSACTION MEETING THE REQUIREMENTS OF RULE 144A , (III) OUTSIDE THE
UNITED STATES IN A TRANSACTION IN ACCORDANCE WITH RULE 904 UNDER THE SECURITIES
ACT, OR (IV) PURSUANT TO AN EFFECTIVE REGISTRATION STATEMENT UNDER THE
SECURITIES ACT, IN EACH OF CASE (I) THROUGH (IV) IN ACCORDANCE WITH ANY
APPLICABLE SECURITIES LAWS OF ANY STATE OF THE UNITED STATES. HOLDERS OF
INTERESTS IN THIS TEMPORARY REGULATION S GLOBAL SECURITY WILL NOTIFY ANY
PURCHASER OF THIS SECURITY OF THE RESALE RESTRICTIONS REFERRED TO ABOVE, IF THEN
APPLICABLE.

            BENEFICIAL INTERESTS IN THIS TEMPORARY REGULATIONS S GLOBAL SECURITY
MAY BE EXCHANGED FOR INTEREST IN A RULE 144A GLOBAL SECURITY ONLY IF (1) SUCH
EXCHANGE OCCURS IN CONNECTION WITH A TRANSFER OF THE NOTES IN COMPLIANCE WITH
RULE 144A, AND (2) THE TRANSFEROR OF THE REGULATION S GLOBAL SECURITY FIRST
DELIVERS TO THE TRUSTEE A WRITTEN CERTIFICATE (IN THE FORM ATTACHED TO THIS
CERTIFICATE) TO THE EFFECT THAT THE REGULATION S GLOBAL SECURITY BEING
TRANSFERRED TO A PERSON (A) WHO THE TRANSFEROR REASONABLY BELIEVES TO BE A
QUALIFIED INSTITUTIONAL BUYER WHEN THE MEANING OF RULE 144A (B) PURCHASING FOR
ITS OWN ACCOUNT OR THE ACCOUNT OF A QUALIFIED INSTITUTIONAL BUYER IN A
TRANSACTION MEETING THE REQUIREMENTS OF RULE 144A, AND (C) IN ACCORDANCE WITH
ALL APPLICABLE SECURITIES LAWS OF THE STATES OF THE UNITED STATES AND OTHER
JURISDICTIONS.

            BENEFICIAL INTEREST IN A RULE 144A GLOBAL SECURITY MAY BE
TRANSFERRED TO A PERSON WHO TAKES DELIVERY IN THE FORM OF AN INTEREST IN THE
REGULATION S GLOBAL SECURITY, WHETHER BEFORE OR AFTER THE EXPIRATION OF THE
40-DAY DISTRIBUTION COMPLIANCE PERIOD, ONLY IF THE TRANSFEROR FIRST DELIVERS TO
THE TRUSTEE A WRITTEN CERTIFICATE (IN THE FORM ATTACHED TO THIS CERTIFICATE) TO
THE EFFECT THAT IF SUCH TRANSFER IS BEING MADE IN ACCORDANCE WITH RULE 903 OR
904 OF REGULATION S OR RULE 144 (IF AVAILABLE) AND THAT, IF SUCH TRANSFER OCCURS
PRIOR TO THE EXPIRATION OF THE 40-DAY DISTRIBUTION COMPLIANCE PERIOD, THE
INTEREST TRANSFERRED WILL BE HELD IMMEDIATELY THEREAFTER THROUGH EUROCLEAR BANK
S.A./N.A. OR CLEARSTREAM BANKING SOCIETE ANONYME.

                        [Certificated Securities Legend]

            IN CONNECTION WITH ANY TRANSFER, THE HOLDER WILL DELIVER TO THE
REGISTRAR AND TRANSFER AGENT SUCH CERTIFICATES AND OTHER INFORMATION AS SUCH
TRANSFER AGENT MAY REASONABLY REQUIRE TO CONFIRM THAT THE TRANSFER COMPLIES WITH
THE FOREGOING RESTRICTIONS.



<PAGE>
                             AEP TEXAS NORTH COMPANY
                               5.50% Senior Notes,
                                Series [A/B] due
                                      2013

CUSIP:[0010EQAA4/144A][U0080FAA4/Reg S] Original Issue Date: February 18, 2003

Stated Maturity:  March 1, 2013            Interest Rate:   5.50%

Principal Amount: $225,000,000 (or such other amount as is indicated on
Schedule A)

Redeemable:       Yes   X           No
In Whole:         Yes   X           No
In Part:          Yes   X           No

            AEP TEXAS NORTH COMPANY, a corporation duly organized and existing
under the laws of the State of Texas (herein referred to as the "Company", which
term includes any successor corporation under the Indenture hereinafter referred
to), for value received, hereby promises to pay to [________]; or registered
assigns, the principal sum of _____ DOLLARS ($_____) [or such other amount as is
indicated on Schedule A hereto]* on the Stated Maturity specified above (or upon
earlier redemption); and to pay interest on said Principal Amount from the
Original Issue Date specified above or from the most recent interest payment
date (each such date, an "Interest Payment Date") to which interest has been
paid or duly provided for, semi-annually in arrears on March 1 and September 1
in each year, commencing on September 1, 2003, at the Interest Rate per annum
specified above, until the Principal Amount shall have been paid or duly
provided for. Interest shall be computed on the basis of a 360-day year of
twelve 30-day months.

            The interest so payable, and punctually paid or duly provided for,
on any Interest Payment Date, as provided in the Indenture, as hereinafter
defined, shall be paid to the Person in whose name this Note (or one or more
Predecessor Securities) shall have been registered at the close of business on
the Regular Record Date with respect to such Interest Payment Date, which shall
be the February 15 or August 15 (whether or not a Business Day), as the case may
be, immediately preceding such Interest Payment Date, provided that interest
payable on the Stated Maturity or any redemption date shall be paid to the
Person to whom principal is paid. Any such interest not so punctually paid or
duly provided for shall forthwith cease to be payable to the Holder on such
Regular Record Date and shall be paid as provided in said Indenture.

            If any Interest Payment Date, any redemption date or Stated Maturity
is not a Business Day, then payment of the amounts due on this Note on such date
will be made on the next succeeding Business Day, and no interest shall accrue
on such amounts for the period from and after such Interest Payment Date,
redemption date or Stated Maturity, as the case may be, except that, if such
Business Day is in the next succeeding calendar year, such payment shall be made
on the immediately preceding Business Day, with the same force and effect as if
made on such date. The principal of (and premium, if any) and the interest on
this Note shall be payable at the office or agency of the Company maintained for
that purpose in the Borough of Manhattan, the City of New York, New York, in any
coin or currency of the United States of America which at the time of payment is
legal tender for payment of public and private debts; provided, however, that
payment of interest (other than interest payable on Stated Maturity or any
redemption date) may be made at the option of the Company by check mailed to the
registered holder at such address as shall appear in the Security Register.

            This Note is one of a duly authorized series of Notes of the Company
(herein sometimes referred to as the "Notes"), specified in the Indenture
(defined below), all issued or to be issued in one or more series under and
pursuant to an Indenture dated as of February 1, 2003 duly executed and
delivered between the Company and Bank One, N. A., a national banking
association organized and existing under the laws of the United States, as
Trustee (herein referred to as the "Trustee") (such Indenture, as originally
executed and delivered and as thereafter supplemented and amended being
hereinafter referred to as the "Indenture"), to which Indenture and all
indentures supplemental thereto reference is hereby made for a description of
the rights, limitations of rights, obligations, duties and immunities thereunder
of the Trustee, the Company and the holders of the Notes. By the terms of the
Indenture, the Notes are issuable in series which may vary as to amount, date of
maturity, rate of interest and in other respects as in the Indenture provided.
This Note is one of the series of Notes designated on the face hereof as 5.50%
Senior Notes, Series [A/B] due 2013 initially issued in the aggregate principal
amount of $225,000,000.

            This Note may be redeemed by the Company at its option, 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
Note at a redemption price equal to the greater of (i) 100% of the principal of
the Note being redeemed and (ii) the sum of the present values of the remaining
scheduled payments of principal and interest on the Note 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 25 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,
      (1) the average of the bid and asked prices for the Comparable Treasury
      Issue (expressed in each case as 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 (2) 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 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 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.

            The Company shall not be required to (i) issue, exchange or register
the transfer of any Notes during a period beginning at the opening of business
15 days before the day of the mailing of a notice of redemption of less than all
the outstanding Notes of the same series and ending at the close of business on
the day of such mailing, nor (ii) register the transfer of or exchange of any
Notes of any series or portions thereof called for redemption. This Global Note
is exchangeable for Notes in definitive registered form only under certain
limited circumstances set forth in the Indenture.

            In the event of redemption of this Note in part only, a new Note or
Notes of this series, of like tenor, for the unredeemed portion hereof will be
issued in the name of the Holder hereof upon the surrender of this Note.

            In case an Event of Default, as defined in the Indenture, shall have
occurred and be continuing, the principal of all of the Notes may be declared,
and upon such declaration shall become, due and payable, in the manner, with the
effect and subject to the conditions provided in the Indenture.

            The Indenture contains provisions for defeasance at any time of the
entire indebtedness of this Note upon compliance by the Company with certain
conditions set forth therein. This Note will not have a sinking fund.

            As described in the supplemental indenture relating to the Notes, so
long as this Note is outstanding, the Company is subject to a limitation on
issuance of Secured Debt as described therein.

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

            No reference herein to the Indenture and no provision of this Note
or of the Indenture shall alter or impair the obligation of the Company, which
is absolute and unconditional, to pay the principal of and premium, if any, and
interest on this Note at the time and place and at the rate and in the money
herein prescribed.

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

            Prior to due presentment for registration of transfer of this Note,
the Company, the Trustee, any paying agent and any Security Registrar may deem
and treat the registered Holder hereof as the absolute owner hereof (whether or
not this Note shall be overdue and notwithstanding any notice of ownership or
writing hereon made by anyone other than the Note Registrar) for the purpose of
receiving payment of or on account of the principal hereof and premium, if any,
and interest due hereon and for all other purposes, and neither the Company nor
the Trustee nor any paying agent nor any Security Registrar shall be affected by
any notice to the contrary.

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

            The Notes of this series are issuable only in registered form
without coupons in denominations of $1,000 and any integral multiple thereof
except that a Note issued to an Institutional Accredited Investor will be in
denominations of at $250,000. As provided in the Indenture and subject to
certain limitations, Notes of this series are exchangeable for a like aggregate
principal amount of Notes of this series of a different authorized denomination,
as requested by the Holder surrendering the same.

            All terms used in this Note which are defined in the Indenture shall
have the meanings assigned to them in the Indenture.

            This Note shall not be entitled to any benefit under the Indenture
hereinafter referred to, be valid or become obligatory for any purpose until the
Certificate of Authentication hereon shall have been signed by or on behalf of
the Trustee.

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

                                       AEP TEXAS NORTH COMPANY


                                       By:----------------------------


Attest:

By:  ____________________________

----------------
*     Insert in the Rule 144A Global Security and the Regulation S Global
      Security only.




<PAGE>


                                   ABBREVIATIONS

      The following abbreviations, when used in the inscription on the face of
this instrument, shall be construed as though they were written out in full
according to applicable laws or regulations:

TEN COM-as tenants in     UNIF GIFT MIN ACT-_______    Custodian ________
        common                                           (Cust)      (Minor)
TEN ENT-as tenants by                          under Uniform Gifts to
        the entireties                         Minors Act
JT TEN-As joint tenants
       with right of                            -------------------------
       survivorship and                                 (State)
       not as tenants
       in common

                  Additional abbreviations may also be used though not on the
                        above list.

      FOR VALUE RECEIVED, the undersigned hereby sell(s) and transfer(s) unto
___________________ (please insert Social Security or other identifying number
of assignee)

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

                                                                              

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

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

Dated: ___________



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




<PAGE>


      In connection with any transfer of any of the Series A Notes evidenced by
this certificate, the undersigned confirms that such Series A Notes are being:

CHECK ONE BOX BELOW

      (1)          exchanged for the undersigned's own account without
                   transfer; or

      (2)          transferred to a person whom the undersigned reasonably
                   believes to be a "qualified institutional buyer" as defined
                   in Rule 144A under the Securities Act of 1933 who is
                   purchasing such Series A Notes for such buyer's own account
                   or the account of a "qualified institutional buyer" in a
                   transaction meeting the requirements of Rule 144A under the
                   Securities Act of 1933 and any applicable securities laws of
                   any state of the United States or any other jurisdiction; or

      (3)          exchanged or transferred pursuant to and in compliance with
                   Rule 903 or 904 of Regulation S under the Securities Act of
                   1933; or

      (4)          exchanged or transferred to an institutional "accredited
                   investor" within the meaning of Rule 501(a)(1), (2), (3) or
                   (7) of Regulation D under the Securities Act pursuant to Rule
                   144A (and based upon an opinion of counsel if the Company or
                   the Trustee so requests) and, to the knowledge of the
                   transferor of the Series A Notes, such institutional
                   accredited investor to whom such Note is to be transferred is
                   not an "affiliate" (as defined in Rule 144 under the
                   Securities Act) of the Company; or

      (5)          transferred pursuant to another available exemption from the
                   registration requirements of the Securities Act of 1933.

      Unless one of the boxes is checked, the Trustee will refuse to register
any of the Series A Notes evidenced by this certificate in the name of any
person other than the registered Holder thereof; provided, however, that if box
(3), (4) or (5) is checked, the Company may require, prior to registering any
such transfer of the Series A Notes, such legal opinions, certifications and
other information as the Company has reasonably requested to confirm that such
transfer is being made pursuant to an exemption from, or in a transaction not
subject to, the registration requirements of the Securities Act of 1933, such as
the exemption provided by Rule 144 under such Act; provided, further, that if
box (2) is checked, the transferee must also certify that it is a qualified
institutional buyer as defined in Rule 144A.

                                    ----------------------------------------
                                                   Signature


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




<PAGE>


            TO BE COMPLETED BY PURCHASER IF (2) ABOVE IS CHECKED.

      The undersigned represents and warrants that it is purchasing this Series
A Note for its own account or an account with respect to which it exercises sole
investment discretion and that it and any such account is a "qualified
institutional buyer" within the meaning of Rule 144A under the Securities Act of
1933, and is aware that the sale to it is being made in reliance on Rule 144A
and acknowledges that it has received such information regarding the Company as
the undersigned has requested pursuant to Rule 144A or has determined not to
request such information and that it is aware that the transferor is relying
upon the undersigned's foregoing representations in order to claim the exemption
from registration provided by Rule 144A.

Date: _________________

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



               NOTICE: To be executed by an executive officer.




<PAGE>


                                   SCHEDULE A

      The initial aggregate principal amount of Series A Notes evidenced by the
Certificate to which this Schedule is attached is $___________. The notations on
the following table evidence decreases and increases in the aggregate principal
amount of Series A Notes evidenced by such Certificate.

                                         Principal Amount
                                         of Series A Notes
    Decrease in         Increase in       Remaining After
Principal Amount of   Principal Amount   Such Decrease or      Notation by
   Series A Notes    of Series A Notes       Increase       Security Registrar









<PAGE>

                                   EXHIBIT B

                          CERTIFICATE OF AUTHENTICATION

      This is one of the Notes referred to in the within-mentioned Indenture.

                                    BANK ONE, N. A.,
                                   as Trustee


                                    By:                                       
                                       ---------------------------------------
                                                Authorized Signatory


<PAGE>



                                    EXHIBIT C

                          FORM OF TRANSFER CERTIFICATE

      In connection with any transfer of any of the Series A Notes evidenced by
this certificate, the undersigned confirms that such Series A Notes are being:

CHECK ONE BOX BELOW

   (1)             exchanged for the undersigned's own account without
                   transfer; or

   (2)             transferred to a person whom the undersigned reasonably
                   believes to be a "qualified institutional buyer" as defined
                   in Rule 144A under the Securities Act of 1933 who is
                   purchasing such Series A Notes for such buyer's own account
                   or the account of a "qualified institutional buyer" in a
                   transaction meeting the requirements of Rule 144A under the
                   Securities Act of 1933 and any applicable securities laws of
                   any state of the United States or any other jurisdiction; or

   (3)             exchanged or transferred pursuant to and in compliance with
                   Rule 903 or 904 of Regulation S under the Securities Act of
                   1933; or

   (4)             exchanged or transferred to an institutional "accredited
                   investor" within the meaning of Rule 501(a)(1), (2), (3) or
                   (7) of Regulation D under the Securities Act pursuant to Rule
                   144A (and based upon an opinion of counsel if the Company or
                   the Trustee so requests) and, to the knowledge of the
                   transferor of the Series A Notes, such institutional
                   accredited investor to whom such Note is to be transferred is
                   not an "affiliate" (as defined in Rule 144 under the
                   Securities Act) of the Company; or

   (5)             transferred pursuant to another available exemption from the
                   registration requirements of the Securities Act of 1933.

      Unless one of the boxes is checked, the Trustee will refuse to register
any of the Series A Notes evidenced by this certificate in the name of any
person other than the registered Holder thereof; provided, however, that if box
(3) or (4) is checked, the Company may require, prior to registering any such
transfer of the Series A Notes, such legal opinions, certifications and other
information as the Company has reasonably requested to confirm that such
transfer is being made pursuant to an exemption from, or in a transaction not
subject to, the registration requirements of the Securities Act of 1933, such as
the exemption provided by Rule 144 under such Act; provided, further, that if
box (2) is checked, the transferee must also certify that it is a qualified
institutional buyer as defined in Rule 144A.

                                                                              
                                                    Signature





<PAGE>


            TO BE COMPLETED BY PURCHASER IF (2) ABOVE IS CHECKED.

      The undersigned represents and warrants that it is purchasing this Series
A Note for its own account or an account with respect to which it exercises sole
investment discretion and that it and any such account is a "qualified
institutional buyer" within the meaning of Rule 144A under the Securities Act of
1933, and is aware that the sale to it is being made in reliance on Rule 144A
and acknowledges that it has received such information regarding the Company as
the undersigned has requested pursuant to Rule 144A or has determined not to
request such information and that it is aware that the transferor is relying
upon the undersigned's foregoing representations in order to claim the exemption
from registration provided by Rule 144A.



Date: _______________

      ______________
--------------------



               NOTICE: To be executed by an executive officer.




<PAGE>

                                    EXHIBIT D

                        FORM OF LETTER TO BE DELIVERED BY
                       INSTITUTIONAL ACCREDITED INVESTORS



Ladies and Gentlemen:

      In connection with our proposed purchase of the 5.50% Senior Notes, Series
A due 2013 (the Notes) issued by AEP Texas North Company, a Texas corporation
(Issuer), we confirm that:

      1.    We are purchasing the Notes for our own account, or for one or
            more investor accounts for which we are acting as a fiduciary or
            agent, in each case for investment, and not with a view to, or
            for offer or sale in connection with, any distribution in
            violation of the Securities Act, subject to any requirement of
            law that the disposition of our property or the property of such
            investor account or accounts be at all times within our or their
            control and subject to our or their ability to resell the Notes
            pursuant to Rule 144A, Regulation S or any exemption from
            registration available under the Securities Act.

      2.    We are an institutional "accredited investor" within the meaning
            of Rule 50l(a)(l), (2), (3) or (7) under the Securities Act who
            is purchasing Notes with a principal amount of at least $250,000
            and, if the Notes are to be purchased for one or more accounts
            (the "investor accounts") for which we are acting as fiduciary or
            agent, each such account is an institutional accredited investor
            who is purchasing Notes with a principal amount of at least
            $250,000.  In the normal course of business or our investing
            activities, we invest in or purchase securities similar to the
            Notes and we have such knowledge and experience in financial
            business matters that we are capable of evaluating the merits and
            risks of purchasing the Notes.  We are aware that we (or any
            investor account) may be required to bear the economic risk of an
            investment in the Notes for an indefinite period of time and we
            (or such investor account) are able to bear such risk for an
            indefinite period.

      3.    We acknowledge that none of the Issuer, the initial purchasers or
            any persons representing any of them has made any representation
            to us with respect to any such entity or the offering or sale of
            any Notes, other than the information contained in the Issuer's
            offering memorandum dated February 12, 2003, related to the
            Notes, which offering memorandum has been delivered to it and
            upon which it is relying in making its investment decision with
            respect to the Notes.  Accordingly, we acknowledge that no
            representation or warranty is made by the initial purchasers as
            to the accuracy or completeness of such materials.  We have had
            access to such financial and other information concerning the
            Issuer and the Notes as we have deemed necessary in connection
            with our decision to purchase any of the Notes including an
            opportunity to ask questions of, and request information from,
            the Issuer and the initial purchasers.

      4.    We understand and agree that the offer and sale of the Notes have
            not been registered under the Securities Act and that such Notes
            are being offered only in a transaction not involving any public
            offering within the meaning of the Securities Act, and that (A)
            if we decide to resell, pledge or otherwise transfer such Notes
            on which a legend setting forth these restrictions appears, such
            Notes may be resold, pledged or otherwise transferred only (i) to
            the Issuer, (ii) in a transaction entitled to an exemption from
            registration provided by Rule 144 under the Securities Act, (iii)
            so long as such Notes are eligible for resale pursuant to Rule
            144A, to a person whom we reasonably believe is a qualified
            institutional buyer that purchases for its own account or for the
            account of a qualified institutional buyer to whom notice is
            given that the resale, pledge or other transfer is being made in
            reliance on Rule 144A, (iv) outside the United States in a
            transaction meeting the requirements of Regulation S, (v) in
            accordance with another exemption from the registration
            requirements of the Securities Act (and based upon an opinion of
            counsel acceptable to the Issuer), in each case in accordance
            with any applicable securities laws of any state of the United
            States or (vi) pursuant to a registration statement which has
            been declared effective under the Securities Act and (B) we will,
            and each subsequent holder is required to, notify any purchaser
            of Notes from us or it of the resale restrictions referred to in
            (A) above, if then applicable.  We acknowledge that the foregoing
            restrictions apply to holders of beneficial interest in the
            Notes, as well as to holders of the Notes.

      5.    We understand that, on any proposed resale of any Notes, we will be
            required to furnish to the trustee and the Issuer such
            certifications, legal opinions and other information as the trustee
            and the Issuer may reasonably require to confirm that the proposed
            sale complies with the foregoing restrictions. We further understand
            that the Notes purchased by us will bear a legend to the foregoing
            effect.

      6.    We acknowledge that the Issuer, the trustee, the initial
            purchasers and others will rely upon the truth and accuracy of
            the foregoing acknowledgements, representations and agreements
            and agree that if any of the foregoing acknowledgements,
            representations or agreements are no longer accurate, we shall
            promptly notify the Issuer, the trustee and the initial
            purchasers.  If we are acquiring the Notes as a fiduciary or
            agent for one or more investor accounts, we represent that we
            have sole investment discretion with respect to each such account
            and we have full power to make the foregoing acknowledgements,
            representations and agreements on behalf of each account and that
            each such investor account is eligible to purchase the Notes.

      7.    The Issuer, the trustee and the initial purchasers are entitled to
            rely upon this letter and are irrevocably authorized to produce this
            letter or a copy hereof to any interested party in any
            administrative or legal proceeding or official inquiry with respect
            to the matters covered hereby.

                                    Very truly yours,


                                       By:
                                      Name:
                                     Title:




EXHIBIT 12

AEP TEXAS NORTH COMPANY
Computation of Ratios of Earnings to Fixed Charges
(in thousands except ratio data)

Year Ended December 31,
1999
2000
2001
2002
2003
Earnings:            
  Net Income Before Extraordinary Item and  
   Cumulative Effect of Accounting Change   $31,867   $27,450   $12,310   $(13,677 ) $55,663  
  Plus Federal Income Taxes   4,187   5,315   16,760   2,806   31,425  
  Plus State Income Taxes   --   --   1,973   (1,363 ) 3,851  
  Plus Provision for Deferred Income Taxes   12,025   9,401   (11,891 ) (12,275 ) (3,493 )
  Plus Deferred Investment Tax Credits   (1,274 ) (1,271 ) (1,271 ) (1,271 ) (1,520 )
  Plus Fixed Charges (as below)   25,083   24,923   24,916   21,885   23,136  





     Total Earnings   $71,888   $65,818   $42,797   $(3,895 ) $109,062  





Fixed Charges:  
  Interest on Long-term Debt   $20,352   $18,017   $16,842   $17,174   $21,627  
  Interest on Short-term Debt   4,731   6,503   7,563   4,051   790  
  Estimated Interest Element in Lease Rentals   -- 403 511   660   719  





     Total Fixed Charges   $25,083   $24,923   $24,916   $21,885   $23,136  





Ratio of Earnings to Fixed Charges   2.86   2.64   1.71   (0.17 ) 4.71  





Certain amounts have been reclassified between interest on short-term and long-term debt compared to periods prior to January 1, 2002. This reclassification had no affect on the ratio.

For the year ended December 31, 2002, the Earnings to cover Fixed Charges was deficient by $25,780,000.






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>