**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, 2004





o
    TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
      1934


For the
transition period from __________ to_________





**Commission**
      **File
      Number**
    
    **Registrants;
      States of Incorporation;**
      **Address
      and Telephone Number**
    
    **I.R.S.
      Employer**
      **Identification
      Nos.**1-3525
    
    American
      Electric Power Company, Inc.
      (A New York Corporation)
    
    13-49226400-18135
    
    AEPGenerating
      Company(An
      Ohio Corporation)
    
    31-10338330-346
    
    AEPTexas
      Central Company(A
      Texas Corporation)
    
    74-05506000-340
    
    AEP
      Texas North Company(A
      Texas Corporation)
    
    75-06467901-3457
    
    Appalachian
      Power Company(A
      Virginia Corporation)
    
    54-01247901-2680
    
    Columbus
      Southern Power Company(An Ohio Corporation)
    
    31-41542031-3570
    
    Indiana
      Michigan Power Company(An
      Indiana Corporation)
    
    35-04104551-6858
    
    Kentucky
      Power Company(A
      Kentucky Corporation)
    
    61-02477751-6543
    
    Ohio
      Power Company(An Ohio Corporation)
    
    31-42710000-343
    
    Public
      Service Company of Oklahoma(An
      Oklahoma Corporation)
    
    73-04108951-3146
    
    Southwestern
      Electric Power Company(A
      Delaware Corporation)
      1
      Riverside Plaza, Columbus, Ohio 43215
      Telephone
      (614) 716-1000
    
    72-0323455





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. o





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. x





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 o





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 o 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:**





**Registrant**
    
    **Title
      of each class**
    
    **Name
      of each exchange**
      **on
      which registered**AEP
      Generating Company
    
    NoneAEP
      Texas Central Company
    
    NoneAEP
      Texas North Company
    
    NoneAmerican
      Electric Power Company, Inc.
    
    Common
      Stock, $6.50 par value
    
    New
      York Stock Exchange9.25%
      Equity Units
    
    New
      York Stock ExchangeAppalachian
      Power Company
    
    NoneColumbus
      Southern Power Company
    
    NoneIndiana
      Michigan Power Company
    
    6%
      Senior Notes, Series D, Due 2032
    
    New
      York Stock ExchangeKentucky
      Power Company
    
    NoneOhio
      Power Company
    
    NonePublic
      Service Company of Oklahoma
    
    6%
      Senior Notes, Series B, Due 2032
    
    New
      York Stock ExchangeSouthwestern
      Electric Power Company
    
    None











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





**Registrant**
    **Title
      of each class**AEP
      Generating Company
    NoneAEP
      Texas Central Company
    4.00%
      Cumulative Preferred Stock, Non-Voting, $100 par value4.20%
      Cumulative Preferred Stock, Non-Voting, $100 par valueAEP
      Texas North Company
    NoneAmerican
      Electric Power Company, Inc.
    NoneAppalachian
      Power Company
    4.50%
      Cumulative Preferred Stock, Voting, no par valueColumbus
      Southern Power Company
    NoneIndiana
      Michigan Power Company
    4.125%
      Cumulative Preferred Stock, Non-Voting, $100 par valueKentucky
      Power Company
    NoneOhio
      Power Company
    4.50%
      Cumulative Preferred Stock, Voting, $100 par valuePublic
      Service Company of Oklahoma
    NoneSouthwestern
      Electric Power Company
    4.28%
      Cumulative Preferred Stock, Non-Voting, $100 par value4.65%
      Cumulative Preferred Stock, Non-Voting, $100 par value5.00%
      Cumulative Preferred Stock, Non-Voting, $100 par
value





**Aggregate
      market value of voting and non-voting common equity held by non-affiliates
      of****the
      registrants at**
      **December
      31, 2004**
    
    **Number
      of shares of common stock outstanding of the registrants
      at**
      **December
      31, 2004**AEP
      Generating Company
    
    None
    
    1,000($1,000
      par value)AEP
      Texas Central Company
    
    None
    
    2,211,678($25
      par value)AEP
      Texas North Company
    
    None
    
    5,488,560($25
      par value)American
      Electric Power Company, Inc.
    
    $13,593,768,974
    
    395,858,153($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**




**Description**
    **Part
      of Form 10-K**
      **Into
      Which Document Is Incorporated**Portions
      of Annual Reports of the following companies for
      the
      fiscal year ended December 31, 2004:
    Part
      IIAEP
      Generating CompanyAEP
      Texas Central CompanyAEP
      Texas North CompanyAmerican
      Electric Power Company, Inc.Appalachian
      Power CompanyColumbus
      Southern Power CompanyIndiana
      Michigan Power CompanyKentucky
      Power CompanyOhio
      Power CompanyPublic
      Service Company of OklahomaSouthwestern
      Electric Power CompanyPortions
      of Proxy Statement of American Electric Power Company, Inc. for 2005
      Annual Meeting of Shareholders, to be filed within 120 days after December
      31, 2004
    Part
      IIIPortions
      of Information Statements of the following companies for 2005 Annual
      Meeting of Shareholders, to be filed within 120 days after December 31,
      2004:
    Part
      IIIAppalachian
      Power CompanyOhio
      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.**





















**TABLE OF
CONTENTS**
 **Item**
      **Number**
    
    **Page**
      **Number****Glossary of Terms**
    **i****Forward-Looking
      Information**
    **iii****PART I****1**
    
    **Business**General
    1Risk Factors
    4Utility Operations
    20Investments
    35**2**
    
    **Properties**Generation FacilitiesTransmission and Distribution
      FacilitiesTitlesSystem Transmission Lines and Facility
      SitingConstruction ProgramPotential Uninsured Losses**3**
    
    **Legal Proceedings****4**
    
    **Submission Of Matters To A Vote Of Security
      Holders**Executive Officers of the
      Registrant**PART II****5**
    
    **Market For Registrant’s Common Equity, Related
      Stockholder Matters**
      **And Issuer Purchases Of Equity
      Securities****6**
    
    **Selected Financial
    Data****7**
    
    **Management’s Discussion And Analysis Of Financial
      Condition And**
      **Results Of Operations****7**
    **A**
    **Quantitative And Qualitative Disclosures About Market
      Risk****8**
    
    **Financial Statements And Supplementary
      Data****9**
    
    **Changes In And Disagreements With Accountants
      On Accounting**
      **And Financial
      Disclosure****9**
    **A**
    **Controls And Procedures****9**
    **B**
    **Other Information****PART III****10**
    
    **Directors And Executive Officers Of The
      Registrant****11**
    
    **Executive Compensation****12**
    
    **Security Ownership Of Certain Beneficial Owners
      And Management**Equity Compensation Plan
Information**13**
    
    **Certain Relationships And Related
      Transactions****14**
    
    **Principal Accounting Fees And
      Services****PART IV****15**
    
    **Exhibits, Financial Statement
      Schedules**Financial
      StatementsSignaturesIndex to Financial Statement
      SchedulesReport of Independent Registered Public
      Accounting FirmExhibit Index







Table of Contents







**GLOSSARY OF TERMS**





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





**Abbreviation
      or Acronym**
    **Definition**AEGCo
    AEP
      Generating Company, an electric utility subsidiary of
  AEPAEP
    American
      Electric Power Company, Inc.AEPES
    AEP
      Energy Services, Inc., a subsidiary of AEPAEP
      Power Pool
    APCo,
      CSPCo, I&M, KPCo and OPCo, as parties to the Interconnection
      AgreementAEPR
    AEP
      Resources, Inc., a subsidiary of AEPAEPSC
      or Service Corporation
    American
      Electric Power Service Corporation, a service subsidiary of
      AEPAEP
      System or the System
    The
      American Electric Power System, an integrated electric utility system,
      owned and operated by AEP’s electric utility
  subsidiariesAEP
      Utilities
    AEP
      Utilities, Inc., subsidiary of AEP, formerly, Central and South West
      CorporationAFUDC
    Allowance
      for funds used during construction (the net cost of borrowed funds, and a
      reasonable rate of return on other funds, used for construction under
      regulatory accounting)ALJ
    Administrative
      law judgeAPCo
    Appalachian
      Power Company, an electric utility subsidiary of AEPBtu
    British
      thermal unitBuckeye
    Buckeye
      Power, Inc., an unaffiliated corporationCAA
    Clean
      Air ActCAAA
    Clean
      Air Act Amendments of 1990Cardinal
      Station
    Generating
      facility co-owned by Buckeye and OPCoCentrica
    Centrica
      U.S. Holdings, Inc., and its affiliates collectively, unaffiliated
      companiesCERCLA
    Comprehensive
      Environmental Response, Compensation and Liability Act of
    1980CG&E
    The
      Cincinnati Gas & Electric Company, an unaffiliated utility
      companyCook
      Plant
    The
      Donald C. Cook Nuclear Plant (2,143 MW), owned by I&M, and located
      near Bridgman, MichiganCSPCo
    Columbus
      Southern Power Company, a public utility subsidiary of
  AEPCSW
      Operating Agreement
    Agreement,
      dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing
      generating capacity allocationDOE
    United
      States Department of EnergyDP&L
    The
      Dayton Power and Light Company, an unaffiliated utility
      companyDow
    The
      Dow Chemical Company, and its affiliates collectively, unaffiliated
      companiesEast
      zone public utility subsidiaries
    APCo,
      CSPCo, I&M, KPCo and OPCoECOM
    Excess
      cost over marketEMF
    Electric
      and Magnetic FieldsEPA
    United
      States Environmental Protection AgencyERCOT
    Electric
      Reliability Council of TexasFERC
    Federal
      Energy Regulatory CommissionFitch
    Fitch
      Ratings, Inc.FPA
    Federal
      Power ActFUCO
    Foreign
      utility company as defined under PUHCAI&M
    Indiana
      Michigan Power Company, a public utility subsidiary of
  AEPI&M
      Power Agreement
    Unit
      Power Agreement Between AEGCo and I&M, dated March 31,
      1982Interconnection
      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 plantsIURC
    Indiana
      Utility Regulatory CommissionKPCo
    Kentucky
      Power Company, a public utility subsidiary of AEPKPSC
    Kentucky
      Public Service CommissionLLWPA
    Low-Level
      Waste Policy Act of 1980LPSC
    Louisiana
      Public Service CommissionMECPL
    Mutual
      Energy CPL, L.P., a Texas REP and former AEP affiliateMEWTU
    Mutual
      Energy WTU, L.P., a Texas REP and former AEP affiliateMISO
    Midwest
      Independent Transmission System OperatorMoody’s
    Moody’s
      Investors Service, Inc.MW
    MegawattNOx
    Nitrogen
      oxideNPC
    National
      Power Cooperatives, Inc., an unaffiliated corporationNRC
    Nuclear
      Regulatory CommissionOASIS
    Open
      Access Same-time Information SystemOATT
    Open
      Access Transmission Tariff, filed with FERCOCC
    Corporation
      Commission of the State of OklahomaOhio
      Act
    Ohio
      electric restructuring legislationOPCo
    Ohio
      Power Company, a public utility subsidiary of AEPOVEC
    Ohio
      Valley Electric Corporation, an electric utility company in which AEP and
      CSPCo together own a 44.2% equity interestPJM
    PJM
      Interconnection, L.L.C.; a regional transmission
    organizationPro
      Serv
    AEP
      Pro Serv, Inc., a subsidiary of AEPPSO
    Public
      Service Company of Oklahoma, a public utility subsidiary of
      AEPPTB
    Price
      to beat, as defined by the Texas ActPUCO
    The
      Public Utilities Commission of OhioPUCT
    Public
      Utility Commission of TexasPUHCA
    Public
      Utility Holding Company Act of 1935, as amendedRCRA
    Resource
      Conservation and Recovery Act of 1976, as amendedREP
    Retail
      electricity providerRockport
      Plant
    A
      generating plant owned and partly leased by AEGCo and I&M (1,300 MW,
      coal-fired) located near Rockport, IndianaRTO
    Regional
      Transmission OrganizationSEC
    Securities
      and Exchange CommissionS&P
    Standard
      & Poor’s Ratings ServiceSO2
    Sulfur
      dioxideSO2Allowance
    An
      allowance to emit one ton of sulfur dioxide granted under the Clean Air
      Act Amendments of 1990SPP
    Southwest
      Power PoolS&P
    Standard
      & Poor’s Ratings ServiceSTP
    South
      Texas Project Nuclear Generating Plant, of which TCC owns 25.2%STPNOC
    STP
      Nuclear Operating Company, a non-profit Texas corporation which operates
      STP on behalf of its joint owners, including TCCSWEPCo
    Southwestern
      Electric Power Company, a public utility subsidiary of
  AEPTCA
    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
      subsidiariesTCC
    AEP
      Texas Central Company, formerly Central Power and Light Company, a public
      utility subsidiary of AEPTEA
    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 assetsTexas
      Act
    Texas
      electric restructuring legislationTNC
    AEP
      Texas North Company, formerly West Texas Utilities Company, a public
      utility subsidiary of AEPTractebel
    Tractebel
      Energy Marketing, Inc.TVA
    Tennessee
      Valley AuthorityVirginia
      Act
    Virginia
      electric restructuring legislationVSCC
    Virginia
      State Corporation CommissionWVPSC
    West
      Virginia Public Service CommissionWest
      zone public utility subsidiaries
    PSO,
      SWEPCo, TCC and TNC
















**FORWARD-LOOKING INFORMATION**





This
report made by AEP and certain of its registrant 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:








·
    Electric
      load and customer growth.·
    Weather
      conditions, including storms.·
    Available
      sources and costs of and transportation for fuels and the creditworthiness
      of fuel suppliers and transporters.·
    Availability
      of generating capacity and the performance of our generating
      plants.·
    The
      ability to recover regulatory assets and stranded costs in connection with
      deregulation.·
    The
      ability to recover increases in fuel and other energy costs through
      regulated or competitive electric rates.·
    New
      legislation, litigation and government regulation including requirements
      for reduced emissions of sulfur, nitrogen, mercury, carbon and other
      substances.·
    Timing
      and resolution of pending and future rate cases, negotiations and other
      regulatory decisions (including rate or other recovery for new
      investments, transmission service and environmental
      compliance).·
    Oversight
      and/or investigation of the energy sector or its
    participants.·
    Resolution
      of litigation (including pending Clean Air Act enforcement actions and
      disputes arising from the bankruptcy of Enron Corp.).·
    Our
      ability to constrain its operation and maintenance
  costs.·
    Our
      ability to sell assets at acceptable prices and on other acceptable terms,
      including rights to share in earnings derived from the assets subsequent
      to their sale.·
    The
      economic climate and growth in our service territory and changes in market
      demand and demographic patterns.·
    Inflationary
      trends.·
    Our
      ability to develop and execute a strategy based on a view regarding prices
      of electricity, natural gas, and other energy-related
      commodities.·
    Changes
      in the creditworthiness and number of participants in the energy trading
      market.·
    Changes
      in the financial markets, particularly those affecting the availability of
      capital and our ability to refinance existing debt at attractive
      rates.·
    Actions
      of rating agencies, including changes in the ratings of
    debt.·
    Volatility
      and changes in markets for electricity, natural gas, and other
      energy-related commodities.·
    Changes
      in utility regulation, including membership and integration into regional
      transmission structures.·
    Accounting
      pronouncements periodically issued by accounting standard-setting
      bodies.·
    The
      performance of our pension and other postretirement benefit
      plans.·
    Prices
      for power that we generate and sell at wholesale.·
    Changes
      in technology and other risks and unforeseen events, including wars, the
      effects of terrorism (including increased security costs), embargoes and
      other catastrophic events.






















**PART I**





**ITEM
1.**  **BUSINESS**





**GENERAL**





***OVERVIEW
AND DESCRIPTION OF SUBSIDIARIES***





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





The
service areas of AEP’s public utility subsidiaries cover portions of the states
of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee,
Texas, Virginia and West Virginia. The generating and transmission facilities of
AEP’s public utility subsidiaries are interconnected, and their operations are
coordinated, as a single integrated electric utility system. Transmission
networks are interconnected with extensive distribution facilities in the
territories served. The public utility subsidiaries of AEP 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, 2004, the subsidiaries of AEP had a total of 19,893 employees.
Because it is a holding company rather than an operating company, AEP 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 934,000 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, 2004, APCo and its wholly owned
subsidiaries had 2,375 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. APCo integrated into PJM on October 1,
2004.





***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 707,000 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, 2004, CSPCo had
1,150 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. CSPCo integrated
into PJM on October 1, 2004.





***I&M*** ** (organized
in Indiana in 1925) is engaged in the generation, transmission and distribution
of electric power to approximately 579,000 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,
2004, 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. I&M integrated into PJM on October
1, 2004.





***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, 2004, KPCo had 424 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. KPCo integrated into PJM
on October 1, 2004.





***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 and
integrated into PJM on October 1, 2004. It purchases electric power from APCo
for distribution to its customers. At December 31, 2004, Kingsport Power Company
had 58 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 707,000 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, 2004, OPCo had 2,177 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. OPCo integrated into PJM on October 1,
2004.





***PSO*** ** (organized
in Oklahoma in 1913) is engaged in the generation, transmission and distribution
of electric power to approximately 509,000 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, 2004, PSO had 1,197
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. PSO is a member of SPP.





***SWEPCo*** ** (organized
in Delaware in 1912) is engaged in the generation, transmission and distribution
of electric power to approximately 444,000 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, 2004, SWEPCo had 1,378 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. SWEPCo is a member of
SPP.





***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 713,000 retail customers through REPs in southern Texas, and in
supplying and marketing electric power at wholesale to other electric utility
companies, a municipality, rural electric cooperatives and other market
participants. At December 31, 2004, TCC had 933 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 188,000 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, 2004, TNC had 415 employees. Among
the principal industries served by TNC are agriculture and the
manufacturing or processing of cotton seed products, oil products, precision and
consumer metal products, meat products and gypsum products. 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 and integrated into PJM on
October 1, 2004. It purchases electric power from OPCo for distribution to its
customers. At December 31, 2004, Wheeling Power Company had 61
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, 2004, AEPSC had 6,208 employees.








***RISK FACTORS***





**General
Risks Of Our Regulated Operations**





**Rate
regulation may delay or deny full recovery of costs.** *(Applies
to each registrant.)*





Our
public utility subsidiaries currently provide service at rates approved by one
or more regulatory commissions. These rates are generally regulated based on an
analysis of the applicable utility’s expenses incurred in a test year. Thus, the
rates a utility is allowed to charge may or may not match its expenses at any
given time. While rate regulation is premised on providing a reasonable
opportunity to earn a reasonable rate of return on invested capital, there can
be no assurance that the applicable regulatory commission will judge all of our
costs to have been prudently incurred or that the regulatory process in which
rates are determined will always result in rates that will produce full recovery
of our costs.





**The
rates that certain of our utilities may charge their customers may be
reduced.** *(Applies to AEP and PSO, SWEPCo and TCC, respectively.)*





In
February 2003, the OCC required PSO to file all documents necessary for a
general rate review. In October 2003 and June 2004, PSO filed financial
information and supporting testimony in response to the OCC’s requirements
indicating that its annual revenues were $41 million less than costs. The OCC
Staff and intervenors filed testimony regarding their recommendations of a
decrease in annual existing rates between $15 and $36 million. In addition, one
party recommended that $30 million of PSO’s natural gas costs not be recovered
from customers because it failed to implement a procurement strategy that this
party alleged would have resulted in lower natural gas costs. PSO filed rebuttal
testimony in February 2005which indicated a decrease of PSO’s revenue
deficiency from $41 million to $28 million, although much of that decrease
includes items that would be recovered through the fuel adjustment clause rather
than through base rates. Hearings are scheduled to begin in March 2005, and a
final decision is not expected any earlier than the second quarter of 2005.
Management is unable to predict the ultimate effect of these proceedings on
PSO’s revenues, results of operations, cash flows and financial
condition.





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 its order
approving the merger between AEP and Central and South West Corporation (“CSW”).
The LPSC’s merger order also provides that SWEPCo’s base rates are capped at the
present level through mid-2005. In April 2004, SWEPCo filed updated financial
information with a test year ending December 31, 2003 as required by the LPSC.
Both filings indicated that SWEPCo’s current rates should not be reduced. Subsequently,
direct testimony was filed on behalf of the LPSC recommending a $15 million
reduction in SWEPCo’s Louisiana jurisdictional base rates. At this time,
management is unable to predict the outcome of this proceeding. If a rate
reduction is ordered in the future, it would adversely impact SWEPCo’s future
results of operations and cash flows.





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. 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. In February 2004, eight
intervening parties and the PUCT Staff filed testimony recommending reductions
to TCC’s requested $67 million rate increase. The recommendations ranged from a
decrease in existing rates of approximately $100 million to an increase in TCC’s
current rates of approximately $27 million. The
ALJs issued recommendations in November 2004, which would reduce TCC’s
existing rates by $51 million to $78 million from existing levels. The PUCT will
hold additional hearings on two major issues in March 2005. The PUCT is expected
to issue a decision in the first half of 2005. If the
PUCT orders a rate reduction, it could adversely impact TCC’s future
results of operations and cash flows.





**The
amount that** **PSO** **seeks to recover for fuel costs is currently being
reviewed.** ** *(Applies
to PSO.)*





In 2002,
PSO experienced a $44 million under-recovery of fuel costs resulting from a
reallocation among AEP’s West zone public utility subsidiaries of purchased
power costs for periods prior to January 1, 2002. In September 2003, the OCC
expanded the case to include a full review of PSO’s 2001 fuel and purchased
power practices. PSO filed testimony in February 2004. An intervenor, the OCC
Staff filed testimony and the Attorney General of Oklahoma have
made filings indicating that recovery should be disallowed altogether or
reduced in the range of $18 million to $9 million.  These filings raised
certain issues of an allocation approved under FERC.  The ALJ recommended
that the OCC lacks authority to examine whether PSO deviated from the FERC
allocation methodology and that any such complaints should be addressed at the
FERC. The OCC conducted a hearing on the jurisdictional matter in January 2005
but has not issued a decision. 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 could be an adverse effect
on PSO’s results of operations, cash flows and possibly financial
condition.





**The
base rates that certain of our utilities charge are currently capped or
frozen.** *(Applies to AEP, CSPCo, I&M, OPCo and SWEPCo.)*





Base
rates charged to customers in Indiana, Michigan, Louisiana and Ohio are
currently either frozen or capped. To the extent our costs in these states
exceed the applicable cap or frozen rate, those costs are not recoverable from
customers.





**Certain
of our revenues and results of operations are subject to risks that are beyond
our control.** *(Applies
to each registrant.)*





Unless
mitigated by timely and adequate regulatory recovery, the cost of repairing
damage to our utility facilities due to storms, natural disasters, wars,
terrorist acts and other catastrophic events, in excess of reserves established
for such repairs, may adversely impact our revenues, operating and capital
expenses and results of operations.





**We
are exposed to nuclear generation risk.** *(Applies to AEP, I&M and TCC.)*





Through
I&M and TCC, we have interests in four nuclear generating units, which
interests equal 2,740 MW, or 7% of our generation capacity. (TCC has entered an
agreement to sell its interest in two nuclear generating units.) We are,
therefore, also subject to the risks of nuclear generation, which include the
following:





·
    the
      potential harmful effects on the environment and human health resulting
      from the operation of nuclear facilities and the storage, handling and
      disposal of radioactive materials;


·
    limitations
      on the amounts and types of insurance commercially available to cover
      losses that might arise in connection with our nuclear operations or those
      of others in the United States;


·
    uncertainties
      with respect to contingencies and assessment amounts if insurance coverage
      is inadequate; and,


·
    uncertainties
      with respect to the technological and financial aspects of decommissioning
      nuclear plants at the end of their licensed
lives.





The NRC
has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In the event of
non-compliance, the NRC has the authority to impose fines or shut down a unit,
or both, depending upon its assessment of the severity of the situation, until
compliance is achieved. Revised safety requirements promulgated by the NRC could
necessitate substantial capital expenditures at nuclear plants such as ours. In
addition, although we have no reason to anticipate a serious nuclear incident at
our plants, if an incident did occur, it could harm our results of operations or
financial condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit.





**The
different regional power markets in which we compete or will compete in the
future have changing transmission regulatory structures, which could affect our
performance in these regions.** *(Applies to each registrant.)*





Our
results are likely to be affected by differences in the market and transmission
regulatory structures in various regional power markets. Problems or delays that
may arise in the formation and operation of new regional transmission
organizations, or “RTOs”, may restrict our ability to sell power produced by our
generating capacity to certain markets if there is insufficient transmission
capacity otherwise available. The rules governing the various regional power
markets may also change from time to time which could affect our costs or
revenues. Because it remains unclear which companies will be participating in
the various regional power markets, or how RTOs will develop or what regions
they will cover, we are unable to assess fully the impact that these power
markets may have on our business.





AEP’s
East zone public utility subsidiaries joined PJM on October 1, 2004. Two of
AEP’s west zone
public utility subsidiaries are
members of SPP. In
February 2004, FERC granted RTO status to the SPP, subject to fulfilling
specified requirements. In October 2004, the FERC issued an order granting final
RTO status to SPP subject to certain filings.





The
Louisiana and Arkansas Commissions are concerned about the effect on retail
ratepayers of utilities in Louisiana and Arkansas joining RTOs. The Commissions
have ordered the utilities in those states, including us, to analyze and submit
to the Commissions the costs and benefits of RTO options available to the
utilities. The Louisiana Commission has also determined that certain RTO
structures that contemplate legally transferring transmission assets to it are
presumptively not in the public interest.





To the
extent we are faced with conflicting state and Federal requirements as to our
participation in RTOs, it could adversely affect our ability to operate and
recover transmission costs from retail customers. Management is unable to
predict the outcome of these transmission regulatory actions and proceedings or
their impact on the timing and operation of RTOs, our transmission operations or
future results of operations and cash flows.





**The
FERC may reduce the amount we may charge third parties for using our
transmission facilities.** ** *(Applies
to AEP and* *AEP’s
East zone public utility subsidiaries* *.)*





In July
2003, the FERC issued an order directing PJM and the MISO to make compliance
filings for their respective OATTs to eliminate 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
(Combined Footprint). 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.





AEP and
several other utilities in the Combined Footprint filed a proposal for new rates
to become effective December 1, 2004. In November 2004, FERC eliminated the
T&O rates and replaced the rates temporarily through March 2006
with seams elimination cost adjustment (SECA) fees. AEP’s East zone public
utility subsidiaries received approximately $1 96 million
of T&O rate revenues for the twelve months ended September 30, 2004, the
last twelve months prior to joining PJM. The
portion of those revenues associated with transactions for which the T&O
rate is being eliminated and replaced by SECA fees was $171 million. Effective
April 2006, all transmission costs that would otherwise have been defrayed by
T&O rates in the Combined Footprint will be subject to recovery from native
load customers of AEP’s East zone public utility subsidiaries. At this time,
management is unable to predict whether any resultant increase in rates
applicable to AEP’s internal load will be recoverable on a timely basis from
state retail customers. Unless new replacement rates compensate AEP for its lost
revenues, and unless any increase in AEP’s East zone public utility
subsidiaries’ transmission expenses from these new rates are fully recovered in
retail rates on a timely basis, future results of operations, cash flows and
financial condition will be adversely affected.





**We
are subject to regulation under the Public Utility Holding Company Act of
1935.** *(Applies to each registrant.)*





Our
system is subject to the jurisdiction of the SEC under PUHCA. The rules and
regulations under PUHCA impose a number of restrictions on the operations of
registered holding company systems. These restrictions include a requirement
that the SEC approve in advance securities issuances, sales and acquisitions of
utility assets, sales and acquisitions of securities of utility companies and
acquisitions of other businesses. PUHCA also generally limits the operations of
a registered holding company to a single integrated public utility system, plus
additional energy-related businesses. PUHCA rules limit the dividends that our
subsidiaries may pay from unearned surplus.





**Our
merger with CSW may ultimately be found to violate PUHCA.** *(Applies to AEP, PSO, SWEPCo, TCC and TNC.)*





We
acquired CSW in a merger completed on June 15, 2000. Among the more significant
assets we acquired as a result of the merger were four additional domestic
electric utility companies - PSO, SWEPCo, TCC and TNC. On January 18, 2002, the
U.S. Court of Appeals for the District of Columbia ruled that the SEC’s June 14,
2000 order approving the merger failed to properly find that the merger meets
the requirements of PUHCA and sent the case back to the SEC for further review.
Specifically, the court told the SEC to revisit its conclusion that the merger
met PUHCA’s requirement that the electric utilities be “physically
interconnected” and confined to a “single area or region.” In August 2004, the
SEC announced it would conduct hearings on this issue. A hearing
was held January 10, 2005 before an ALJ. An initial decision is expected from
the ALJ later this year. The SEC will have the opportunity to review the initial
decision.





We
believe that the merger meets the requirements of PUHCA and expect the matter to
be resolved favorably. We can give no assurance, however, that: (i) the SEC
or any applicable court review will find that the merger complies with PUHCA, or
(ii) the SEC or any applicable court review will not impose material adverse
conditions on us in order to find that the merger complies with PUHCA. If the
merger were ultimately found to violate PUHCA, we could be required to take
remedial actions or divest assets, which could harm our results of operations or
financial condition.





**We
operate in a non-uniform and fluid regulatory environment.** *(Applies to each registrant.)*





In most
instances and in varying degrees, the rates charged by the domestic utility
subsidiaries are approved by the FERC and the eleven state utility commissions.
FERC regulates wholesale electricity operations and transmission rates and the
state commissions regulate retail generation and distribution rates. Several of
the eleven state retail jurisdictions in which our domestic electric utilities
operate have enacted restructuring legislation. Restructuring legislation in
Texas requires the legal separation of generation and related assets from the
transmission and distribution assets of the electric utilities in that state. In
Ohio, we are complying with restructuring legislation through the continued
functional separation of the operations of our Ohio utility subsidiaries. As a
result of restructuring legislation in Texas and Ohio, a significant portion of
our domestic generation is no longer directly regulated by state utility
commissions as to rates. TCC has sold
some of its generation in Texas and is in the process of selling its remaining
generation. Our utility operations in the remaining state retail jurisdictions
that have not enacted any restructuring legislation currently plan to adhere to
the vertically-integrated utility model with cost recovery through regulated
rates.





Our
business plan is based on the regulatory framework as described. There can be no
assurance that the states that have pursued restructuring will not reverse such
policies; nor can there be assurance that the states that have not enacted
restructuring legislation will not do so in the future. In addition to the
multiple levels of regulation at the state level in which we operate, our
business is subject to extensive federal regulation. There can be no assurance
that the federal legislative and regulatory initiatives (which have occurred
over the past few years and which have generally facilitated competition in the
energy sector) will continue or will not be reversed.





Further
alteration of the regulatory landscape in which we operate will impact the
effectiveness of our business plan and may, because of the continued
uncertainty, harm our financial condition and results of
operations.





**Risks
Related to Market, Economic or International Financial
Volatility**





**Downgrades
in our credit ratings could negatively affect our ability to access capital
and/or to operate our power trading businesses.** *(Applies to each registrant other than AEGCo.)*





Following
the bankruptcy of Enron, the credit ratings agencies initiated a thorough review
of the capital structure and the quality and stability of earnings of energy
companies, including us. The agencies made ratings changes at that time. Further
negative ratings actions could constrain the capital available to our industry
and could limit our access to funding for our operations. Our
business is capital intensive, and we are dependent upon our ability to access
capital at rates and on terms we determine to be attractive. If our ability to
access capital becomes significantly constrained, our interest costs will likely increase and our financial condition
could be harmed and future results of operations could be adversely
affected.





Moody’s
has assigned an investment grade credit rating to the senior unsecured long-term
debt of each registrant other than AEGCo (collectively, the “Rated Issuers”).
Moody’s has further assigned an outlook of stable for each of the Rated Issuers
other than AEP, which Moody’s assigned an outlook of positive in 2004. S&P
has also assigned an investment grade credit rating to the senior unsecured
long-term debt of each of the Rated Issuers. S&P has assigned an outlook of
stable for each of the Rated Issuers. Fitch has also assigned an investment
grade credit rating (with stable outlook) to the senior unsecured long-term debt
of each of the Rated Issuers. Apart from Moody’s improving the outlook on AEP
noted above, none of these ratings was adjusted by any rating agency during
2004.





Moody’s
has assigned AEP a short-term debt rating of P-3. S&P has assigned AEP a
short-term debt rating of A-2. Fitch has assigned AEP a short-term debt rating
of F-2. As a result of the split rating, AEP’s access to the commercial paper
market may be limited and the short-term borrowing costs of each registrant may
increase (because AEP’s subsidiaries conduct short-term borrowing through AEP
and on the same terms available to AEP).





If
Moody’s or S&P were to
downgrade the long-term rating of any of the Rated
Issuers **,** particularly below investment grade, the borrowing costs of that Rated
Issuer would
increase, which would diminish its financial results. In addition, it would
likely be required to pay a higher interest rate in future financings, and its
potential pool of investors and funding sources could decrease.





Our power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt. Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions. If those ratings were to decline below investment
grade, our ability to operate our power trading business profitably would be
diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.





**The
underfunded condition of our retirement plans may require additional
significant contributions.** *(Applies to each registrant.)*





AEP
provides defined benefit pension plans (“Pension Plans”) for the employees of
our subsidiaries. In addition, AEP provides health care and life insurance
benefit plans for retired employees.





Low
prevailing interest rates have increased the pension plans’ liability. The
combined Pension Plans’ liabilities based on service and pay to date
(“Accumulated Benefit Obligation”) exceeded the value of the assets at December
31, 2004. As of December 31, 2004, the fair value of the Pension Plans assets
was $3.56 billion while the Accumulated Benefit Obligation was estimated at $4.0
billion, an underfunding of approximately $450 million. For the individual
pension plans that were underfunded based on the Accumulated Benefit Obligation,
underfunding totaled approximately $474 million. In order to fund the qualified
pension plans fully by the end of 2005, a discretionary contribution of $200
million was made in the fourth quarter of 2004 and discretionary contributions
of $100 million per quarter are expected in 2005.





AEP also
made contributions of $137 million to postretirement health care and life
insurance benefits trust funds in 2004, and expects to contribute significant
amounts in the future.





We cannot
predict the future performance of the investment markets. A downturn in the
investment markets could have a material negative impact on the net asset value
of the plans’ trust accounts and increase the underfunding of the Pension Plans,
net of benefit obligations. This may necessitate significant cash contributions
to the Pension Plans. Changes in interest rates may also materially affect the
pension and postretirement health care and life insurance benefit liabilities
and the cash contributions needed to fund those liabilities. Changes in the laws
and regulations governing the plans may increase or decrease the required
contributions.





**Our
operating results may fluctuate on a seasonal and quarterly
basis** **.** *(Applies to each registrant.)*





Electric
power generation 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. As a
result, our overall operating results in the future may fluctuate substantially
on a seasonal basis. The pattern of this fluctuation may change depending on the
terms of power sale contracts that we enter into. In addition, we have
historically sold less power, and consequently earned less income, when weather
conditions are milder. We expect that unusually mild weather in the future could
diminish our results of operations and harm our financial
condition.





**Changes
in technology may significantly affect our business by making our power plants
less competitive** **.** *(Applies to each registrant.)*





A key
element of our business model is that generating power at central power plants
achieves economies of scale and produces power at relatively low cost. There are
other technologies that produce power, most notably fuel cells, microturbines,
windmills and photovoltaic (solar) cells. It is possible that advances in
technology will reduce the cost of alternative methods of producing power to a
level that is competitive with that of most central power station electric
production. If this were to happen and if these technologies achieved economies
of scale, our market share could be eroded, and the value of our power plants
could be reduced. Changes in technology could also alter the channels through
which retail electric customers buy power, thereby harming our financial
results.





**Changes
in commodity prices may increase our cost of producing power or decrease the
amount we receive from selling power, harming our financial
performance** **.** *(Applies to each registrant.)*





We are
heavily exposed to changes in the price and availability of coal because most of
our generating capacity is coal-fired. We have contracts of varying durations
for the supply of coal for most of our existing generation capacity, but as
these contracts end or otherwise not honored, we may not be able to purchase
coal on terms as favorable as the current contracts.





We also
own natural gas-fired facilities, which increases our exposure to the more
volatile market prices of natural gas.





Changes
in the cost of coal or natural gas and changes in the relationship between such
costs and the market prices of power will affect our financial results. Since
the prices we obtain for power may not change at the same rate as the change in
coal or natural gas costs, we may be unable to pass on the changes in costs to
our customers. In addition, the prices we can charge our retail customers in
some jurisdictions are capped and our fuel recovery mechanisms in other states
are frozen for various periods of time.





In
addition, actual power prices and fuel costs will differ from those assumed in
financial projections used to value our trading and marketing transactions, and
those differences may be material. As a result, our financial results may be
diminished in the future as those transactions are marked to
market.





**At
times, demand for power could exceed our supply capacity** **.** *(Applies to each registrant other than TCC and TNC.)*





We are
currently obligated to supply power in parts of eleven states. From time to time
because of unforseen circumstances the demand for power required to meet these
obligations could exceed our available generation capacity. If this occurs, we
would have to buy power on the market. We may not always have the ability to
pass these costs on to our customers because some of the states we operate in do
not allow us to increase our rates in response to increased fuel cost charges.
Since these situations most often occur during periods of peak demand, it is
possible that the market price for power at that time would be very high. Even
if a supply shortage was brief, we could suffer substantial losses that could
diminish our results of operations.





**Risks
Relating To State Restructuring**





**We
have limited ability to pass our costs of production on to our
customers.** *(Applies to each registrant.)*





We are
exposed to risk from changes in the market prices of coal and natural gas used
to generate power where generation is no longer regulated or where existing fuel
clauses are suspended or frozen. Recently, the price of coal and natural gas has
increased materially. The protection afforded by retail fuel clause recovery
mechanisms has been eliminated by the implementation of customer choice in Ohio
and in the ERCOT area of Texas. There may be similar risks should customer
choice be similarly implemented in other states. Because the risk of generating
costs cannot be passed through to customers as a matter of right in Ohio and the
ERCOT area of Texas, we retain these risks.





A fuel
clause in West Virginia has been suspended per a settlement reached in a state
restructuring proceeding. However, as restructuring has not been implemented in
West Virginia, the fuel clause may be reactivated. An extension of the currently
pending fuel clause in Indiana is being negotiated.





**Our
default service obligations in Ohio do not restrict customers from switching
suppliers of power.** *(Applies to AEP, CSPCo and OPCo.)*





Those
default service customers that we serve in Ohio may choose to purchase power
from alternative suppliers. Should they choose to switch from us, our sales of
power may decrease. Customers originally choosing alternative suppliers may
switch to our default service obligations. This may increase demand above our
facilities’ available capacity. Thus, any such switching by customers could have
an adverse effect on our results of operations and financial position.
Conversely, to the extent the power sold to meet the default service obligations
could have been sold to third parties at more favorable wholesale prices, we
will have incurred potentially significant lost opportunity costs.





**If
CSPCo and OPCo are unable to remain functionally separated, they will need SEC
approval to legally separate their assets.** *(Applies
to CSPCo and OPCo.)*





Ohio has
enacted restructuring legislation in the Ohio Act. CSPCo and OPCo each currently
comply with the Ohio Act as a functionally separated electric utility. The PUCO
has approved the rate stabilization plan that does not contemplate legal
separation at least through 2008. However, we can give no assurance that we can
remain functionally separated following that. If CSPCo and OPCo are unable to
remain functionally separated and we are required to legally separate, they
would need SEC approval to legally separate.





**Some
laws and regulations governing restructuring of the wholesale generation market
in Michigan and Virginia have not yet been interpreted or adopted and could harm
our business, operating results and financial condition.** *(Applies to AEP and APCo and I&M, respectively.)*





While the
electric restructuring laws in Michigan and Virginia established the general
framework governing the retail electric market, the laws required the utility
commission in each state to issue rules and determinations implementing the
laws. Some of the regulations governing the retail electric market have not yet
been adopted by the utility commission in each state. These laws, when they are
interpreted and when the regulations are developed and adopted, may harm our
business, results of operations and financial condition. Virginia restructuring
legislation was enacted in 1999 providing for retail choice of generation
suppliers to be phased in over two years beginning January 1, 2002. It
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 with VSCC 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. Legislation in Virginia has been adopted which
extends a cap on electricity rates until 2010.





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,
2004, none of I&M’s Michigan customers have elected to change suppliers and
no alternative electric suppliers are registered to compete in I&M’s
Michigan service territory.





**There
is uncertainty as to our recovery of deferred fuel balances and stranded costs
resulting from industry restructuring in Texas.** *(Applies to AEP and TCC.)*





In 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 true-up proceeding
described below. This reconciliation covers the period from July 1998 through
December 2001. The PUCT will review an ALJ report addressing the reconciliation
and will likely issue a decision in the first quarter of 2005. The over-recovery
balance and the subsequent provisions for probable disallowances totaled $212
million, including interest, at December 31, 2004. The PUCT will net the final
amount against recoverable amounts determined by the true-up
proceeding.





Restructuring
legislation in Texas required utilities with stranded costs to use market-based
methods to value certain generating assets for determining stranded costs. We
have elected to use the sale of assets method to determine the market value of
all of the generation assets of TCC for stranded cost purposes. The amount of
stranded costs under this market valuation methodology will be the amount by
which the book value of TCC’s generating assets, including regulatory assets and
liabilities that were not securitized, exceeds the market value of the
generation assets as measured by the net proceeds from the sale of the assets.
TCC’s sale of its generating assets will be subject to a review in a true-up
proceeding conducted by the PUCT. TCC’s recorded net regulatory asset for
amounts subject to approval in the true-up proceeding, net of the deferred fuel
over-recovery described above, is approximately $1.6 billion. We estimate that
TCC’s true-up filing will exceed the total of its recorded net regulatory asset.
Management expects that the true-up proceeding will be contentious and could
possibly result in disallowances. If we are unable, after the true-up
proceeding, to recover all or a portion of our stranded plant costs,
generation-related net regulatory assets, wholesale capacity auction true-up
regulatory assets, other restructuring true-up items and costs, it could have a
material adverse effect on results of operations, cash flows and possibly
financial condition.





**Collection
of our revenues in Texas is concentrated in a limited number of
REPs.** ** *(Applies
to AEP, TCC and TNC.)*





Our
revenues from the distribution of electricity in the ERCOT
area of Texas are
collected from REPs that supply the electricity we distribute to their
customers. Currently, we do business with approximately forty three REPs.
Adverse economic conditions, structural problems in the new Texas market or
financial difficulties of one or more REPs could impair the ability of these
REPs to pay for our services or could cause them to delay such payments. We
depend on these REPs for timely remittance of payments. Any delay or default in
payment could adversely affect the timing and receipt of our cash flows thereby
have an adverse effect on our liquidity.





**We
may not be able to respond effectively to competition.** *(Applies to each registrant.)*





We may
not be able to respond in a timely or effective manner to the many changes in
the power industry that may occur as a result of regulatory initiatives to
increase competition. These regulatory initiatives may include deregulation of
the electric utility industry in some markets. To the extent that competition
increases, our profit margins may be negatively affected. Industry deregulation
may not only continue to facilitate the current trend toward consolidation in
the utility industry but may also encourage the disaggregation of other
vertically integrated utilities into separate generation, transmission and
distribution businesses. As a result, additional competitors in our industry may
be created, and we may not be able to maintain our revenues and earnings levels
or pursue our growth strategy.





While
demand for power is generally increasing throughout the United States, the rate
of construction and development of new, more efficient electric generation
facilities may exceed increases in demand in some regional electric markets. The
start-up of new facilities in the regional markets in which we have facilities
could increase competition in the wholesale power market in those regions, which
could harm our business, results of operations and financial condition. Also,
industry restructuring in regions in which we have substantial operations could
affect our operations in a manner that is difficult to predict, since the
effects will depend on the form and timing of the restructuring.





**Risks
Related to Environmental Regulation**





**Our
costs of compliance with environmental laws are significant, and the cost of
compliance with future environmental laws could harm our cash flow and
profitability.** *(Applies to each registrant other than TCC and TNC.)*





Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Compliance with these legal
requirements requires us to commit significant capital toward environmental
monitoring, installation of pollution control equipment, emission fees and
permits at all of our facilities. These expenditures have been significant in
the past and we expect that they will increase in the future. Costs of
compliance with environmental regulations could harm our industry, our business
and our results of operations and financial position, especially if emission
and/or discharge limits are tightened, more extensive permitting requirements
are imposed, additional substances become regulated and the number and types of
assets we operate increase. Additionally, in July 2004 attorneys general of
eight states and others sued AEP and other utilities alleging that carbon
dioxide emissions from power generating facilities constitute a public nuisance
under federal common law. The suits seek injunctive relief in the form of
specific emission reduction commitments from the defendants. While we believe
the claims are without merit, the costs associated with reducing carbon dioxide
emissions could harm our business and our results of operations and financial
position.





**We
anticipate that we will incur considerable capital costs for
compliance.** *(Applies to each registrant other than TCC and TNC.)*





Most of
our generating capacity is coal burning. We plan to install new emissions
control equipment and may be required to upgrade existing equipment, purchase
emissions allowances or reduce operations. We estimate that we will invest
approximately $600 million to comply with existing federal and state regulations
designed to limit nitrogen oxide (“NOx”) emissions and approximately $1.2
billion to comply with existing federal and state regulations designed to limit
sulfur dioxide (“SO 2 ”)
emissions. We estimate that we will invest approximately $1.8 billion (and an
additional $150 million in operation and maintenance expenses) to comply with
currently proposed, but as yet unadopted, federal regulations designed to limit
NOx, SO 2 and
mercury emissions through 2010, assuming certain contingencies. Between 2011 and
2020 we expect to incur additional costs for pollution control technology
retrofits and investment of $1.6 billion. However, post-2010 capital investment
estimates are quite uncertain. All of our estimates are subject to significant
uncertainties about the outcome of several interrelated assumptions and
variables, including timing of implementation, required levels of reductions,
allocation requirements of the new rules, and our selected compliance
alternatives. As a result, we cannot estimate our compliance costs with
certainty.  The actual costs to comply could differ significantly from the
estimates. All of the costs are incremental to our current investment base and
operating cost structure. These expenditures for pollution control technologies,
replacement generation and associated operating costs should be 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.





**Governmental
authorities may assess penalties on us for failures to comply with environmental
laws and regulations.** ** *(Applies
to each registrant.)*





If we
fail to comply with environmental laws and regulations, even if caused by
factors beyond our control, that failure may result in the assessment of civil
or criminal penalties and fines against us. Recent lawsuits by the EPA and
various states filed against us highlight the environmental risks faced by
generating facilities, in general, and coal-fired generating facilities, in
particular.





Since
1999, we have been involved in litigation regarding generating plant emissions
under the Clean Air Act. Federal EPA and a number of states alleged that we and
eleven unaffiliated utilities modified certain units at coal-fired generating
plants in violation of the Clean Air Act. Federal EPA filed complaints against
certain AEP subsidiaries in U.S. District Court for the Southern District of
Ohio. A separate lawsuit initiated by certain special interest groups was
consolidated with the Federal EPA case. The alleged modification of the
generating units occurred over a 20-year period.





If these
actions are resolved against us, substantial modifications of our existing
coal-fired power plants would be required. In addition, we could be required to
invest significantly in additional emission control equipment, accelerate the
timing of capital expenditures, pay penalties and/or halt operations. Moreover,
our results of operations and financial position could be reduced due to the
timing of recovery of these investments and the expense of ongoing
litigation.





Other
parties have settled similar lawsuits. An unaffiliated utility which operates
certain plants jointly owned by CSPCo reached a tentative agreement to settle
litigation regarding generating plant emissions under the Clean Air Act.
Negotiations are continuing and a settlement could impact the operation of
certain of the jointly owned plants. Until a final settlement is reached, CSPCo
will be unable to determine the settlement’s impact on its jointly owned
facilities and its future results of operations and cash flows.





**Risks
Related to Power Trading and Wholesale Businesses**





**Our
revenues and results of operations are subject to market risks that are beyond
our control.** *(Applies to each registrant.)*





We sell
power from our generation facilities into the spot market or other competitive
power markets or on a contractual basis. We also enter into contracts to
purchase and sell electricity, natural gas, emission allowances and coal as part
of our power marketing and energy trading operations. With respect to such
transactions, we are not guaranteed any rate of return on our capital
investments through mandated rates, and our revenues and results of operations
are likely to depend, in large part, upon prevailing market prices for power in
our regional markets and other competitive markets. These market prices may
fluctuate substantially over relatively short periods of time. It is reasonable
to expect that trading margins may erode as markets mature and that there may be
diminished opportunities for gain should volatility decline. In addition, FERC,
which has jurisdiction over wholesale power rates, as well as independent system
operators that oversee some of these markets, may impose price limitations,
bidding rules and other mechanisms to address some of the volatility in these
markets. Fuel prices may also be volatile, and the price we can obtain for power
sales may not change at the same rate as changes in fuel costs. These factors
could reduce our margins and therefore diminish our revenues and results of
operations.





Volatility
in market prices for fuel and power may result from:





·
    weather
      conditions;


·
    seasonality;


·
    power
      usage;


·
    illiquid
      markets;


·
    transmission
      or transportation constraints or
inefficiencies;


·
    availability
      of competitively priced alternative energy
sources;


·
    demand
      for energy commodities;


·
    natural
      gas, crude oil and refined products, and coal production
      levels;


·
    natural
      disasters, wars, embargoes and other catastrophic events;
    and


·
    federal,
      state and foreign energy and environmental regulation and
      legislation.





**Our
power trading (including coal, gas and e** **mission
allowances trading** **and power marketing) and risk management policies cannot eliminate the risk
associated with these activities.** *(Applies
to each registrant.)*





Our power
trading (including coal, gas
and emission
allowances trading and power marketing) activities expose us to risks of
commodity price movements. We attempt to manage our exposure through enforcement
of established risk limits and risk management procedures. These risk limits and
risk management procedures may not work as planned and cannot eliminate the
risks associated with these activities. As a result, we cannot predict the
impact that our energy trading and risk management decisions may have on our
business, operating results or financial position.





We
routinely have open trading positions in the market, within established
guidelines, resulting from the management of our trading portfolio. To the
extent open trading positions exist, fluctuating commodity prices can improve or
diminish our financial results and financial position.





Our power
trading and risk management activities, including our power sales agreements
with counterparties, rely on projections that depend heavily on judgments and
assumptions by management of factors such as the future market prices and demand
for power and other energy-related commodities. These factors become more
difficult to predict and the calculations become less reliable the further into
the future these estimates are made. Even when our policies and procedures are
followed and decisions are made based on these estimates, results of operations
may be diminished if the judgments and assumptions underlying those calculations
prove to be wrong or inaccurate.





**Our
financial performance may be adversely affected if we are unable to operate our
pooled electric generating facilities successfully.** *(Applies to each registrant.)*





Our
performance is highly dependent on the successful operation of our electric
generating facilities. Operating electric generating facilities involves many
risks, including:





·
    operator
      error and breakdown or failure of equipment or
  processes;


·
    operating
      limitations that may be imposed by environmental or other regulatory
      requirements;


·
    labor
      disputes;


·
    fuel
      supply interruptions; and


·
    catastrophic
      events such as fires, earthquakes, explosions, terrorism, floods or other
      similar occurrences.





A
decrease or elimination of revenues from power produced by our electric
generating facilities or an increase in the cost of operating the facilities
would adversely affect our results of operations.





**Parties
with whom we have contracts may fail to perform their obligations, which could
harm our results of operations.** *(Applies to each registrant.)*





We are
exposed to the risk that counterparties that owe us money or power could breach
their obligations. Should the counterparties to these arrangements fail to
perform, we may be forced to enter into alternative hedging arrangements or
honor underlying commitments at then-current market prices that may exceed our
contractual prices, which would cause our financial results to be diminished and
we might incur losses. Although our estimates take into account the expected
probability of default by a counterparty, our actual exposure to a default by a
counterparty may be greater than the estimates predict.





**We
are contractually required to operate a power generation facility that we have
agreed to lease but the energy sales market for the facility’s excess energy is
over-supplied.** *(Applies to AEP.)*




We have
agreed to lease from Juniper Capital L.P. a non-regulated merchant power
generation facility (“Facility”) near Plaquemine, Louisiana. We sublease the
Facility to Dow. We operate the Facility for Dow. Dow uses a portion of the
energy produced by the Facility and sells the excess power to us. We have agreed
to sell up to all of the excess 800 MW to a third party at a price that is
currently in excess of market. This agreement is now being litigated. If it is
unenforceable, we will be required to find new purchasers for up to 800 MW.
There can be no assurance that this power will be sold at prices that will
exceed our costs to produce it. If that were the case, as a result of our
obligations to Dow, we would be required to operate the Facility at a
loss. **





**We
rely on electric transmission facilities that we do not own or control. If these
facilities do not provide us with adequate transmission capacity, we may not be
able to deliver our wholesale electric power to the purchasers of our
power.** *(Applies to each registrant.)*





We depend
on transmission facilities owned and operated by other unaffiliated power
companies to deliver the power we sell at wholesale. This dependence exposes us
to a variety of risks. If transmission is disrupted, or transmission capacity is
inadequate, we may not be able to sell and deliver our wholesale power. If a
region’s power transmission infrastructure is inadequate, our recovery of
wholesale costs and profits may be limited. If restrictive transmission price
regulation is imposed, the transmission companies may not have sufficient
incentive to invest in expansion of transmission infrastructure.





The FERC
has issued electric transmission initiatives that require electric transmission
services to be offered unbundled from commodity sales. Although these
initiatives are designed to encourage wholesale market transactions for
electricity and gas, access to transmission systems may in fact not be available
if transmission capacity is insufficient because of physical constraints or
because it is contractually unavailable. We also cannot predict whether
transmission facilities will be expanded in specific markets to accommodate
competitive access to those markets.





**We
do not fully hedge against price changes in commodities.** *(Applies to each registrant.)*





We
routinely enter into contracts to purchase and sell electricity, natural gas,
coal and emission allowances as part of our power marketing and energy and
emission allowances trading operations. In connection with these trading
activities, we routinely enter into financial contracts, including futures and
options, over-the counter options, financially-settled swaps and other
derivative contracts. These activities expose us to risks from price movements.
If the values of the financial contracts change in a manner we do not
anticipate, it could harm our financial position or reduce the financial
contribution of our trading operations.





We manage
our exposure by establishing risk limits and entering into contracts to offset
some of our positions (i.e., to hedge our exposure to demand, market effects of
weather and other changes in commodity prices). However, we do not always hedge
the entire exposure of our operations from commodity price volatility. To the
extent we do not hedge against commodity price volatility, our results of
operations and financial position may be improved or diminished based upon our
success in the market.





**We
are exposed to losses resulting from the bankruptcy of Enron
Corp.** *(Applies to AEP, except for last paragraph, which applies to each
registrant.)*





In 2002,
certain of our subsidiaries filed claims against Enron Corp. (“Enron”) and its
subsidiaries in the Enron bankruptcy proceeding pending in the U.S. Bankruptcy
Court for the Southern District of New York. At the date of Enron’s bankruptcy,
certain of our subsidiaries 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.





*Cushion
gas use agreements* - In
connection with the 2001 acquisition of HPL, we also entered into an agreement
with BAM Lease Company, which grants HPL the exclusive right to use
approximately 65 BCF of cushion gas required for the normal operation of the
Bammel gas storage facility. At the time of our acquisition of HPL, Bank of
America (“BOA”) and certain other banks (together with BOA, “BOA Syndicate”) and
Enron entered into an agreement granting HPL the exclusive use of 65 BCF of
cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate
also 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 BOA Syndicate of a purported default
by Enron under the terms of the financing arrangement. We are currently
litigating the rights to the cushion gas.





In
February 2004, in connection with BOA’s dispute, 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.
In January 2005 we sold a 98% controlling interest in HPL, including the Bammel
gas storage facility. We indemnified the purchaser for damages, if any, arising
from the litigation with BOA.





*Commodity
trading settlement disputes* - 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. AEP has
asserted its right to offset trading payables owed to various Enron entities
against trading receivables due to several AEP subsidiaries. The parties are
currently in non-binding court-sponsored mediation.





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. The parties are currently in non-binding
court-sponsored mediation. 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.





**Potential
for disruption exists if the delay of a FERC market power mitigation order is
lifted.** *(Applies to each registrant.)*





In July
2004, the FERC issued an order directing AEP and two unaffiliated utilities to
file generation market power analyses within 30 days. We have presented evidence
to FERC to demonstrate that we do not possess market power in geographic areas
where we sell wholesale power. In a December 2004 order, FERC found that AEP
passed the screens in PJM and ERCOT, but not in the SPP area. Because AEP did
not pass the market share screen in SPP, FERC initiated a proceeding under
Section 206 of the FPA in which AEP is rebuttably presumed to possess market
power in SPP. Consequently, our revenues from sales in SPP at market based rates
after March 6, 2005 will be collected subject to refund to the extent that
prices are ultimately found not to be just and reasonable. In February 2005 AEP
filed with the FERC revisions to its market-based rate tariffs that cap the
rates of wholesale power that AEP delivers within its control area of the SPP.
We are unable to predict the timing or impact of any further action by the
FERC.





***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, 2004 are as follows:





**Description**
    
    
    **AEP**
      **System (a)**
    ****
    
    **APCo**
    
    
    **CSPCo**
    
    
    **I&M**
    
    
    **KPCo**(in
      thousands)Utility
      Operations:Retail
      SalesResidential
      Sales
    
    $
    3,249,000
    
    $
    635,905
    
    $
    522,871
    
    $
    367,015
    
    $
    128,982Commercial
      Sales
    
    
    2,326,000
    
    
    323,623
    
    
    467,628
    
    
    288,046
    
    
    75,584Industrial
      Sales
    
    
    2,051,000
    
    
    349,674
    
    
    131,129
    
    
    342,622
    
    
    109,767Total
      Other Retail Sales
    
    
    97,000
    
    
    41,735
    
    
    15,328
    
    
    6,482
    
    
    1,009Total
      Retail
    
    
    7,723,000
    
    
    1,350,937
    
    
    1,136,956
    
    
    1,004,165
    
    
    315,342WholesaleSystem
      Sales & Transmission
    
    
    2,330,000
    
    
    296,877
    
    
    168,757
    
    
    343,620
    
    
    69,023Risk
      Management Realized
    
    
    73,000
    
    
    18,120
    
    
    8,029
    
    
    14,473
    
    
    7,687Risk
      Management Mark-to-Market
    
    
    (48,000
    )
    
    192
    
    
    5,563
    
    
    -
    
    
    -Total
      Wholesale
    
    
    2,355,000
    
    
    315,189
    
    
    182,349
    
    
    358,093
    
    
    76,710Other
      Operating Revenues
    
    
    495,000
    
    
    65,493
    
    
    34,161
    
    
    38,148
    
    
    16,971Sales
      to Affiliates
    
    
    -
    
    
    216,563
    
    
    80,115
    
    
    261,174
    
    
    41,590Gross
      Utility Operating Revenues
    
    
    10,573,000
    
    
    1,948,182
    
    
    1,433,581
    
    
    1,661,580
    
    
    450,613Provision
      for Rate Refund
    
    
    (60,000
    )
    
    -
    
    
    -
    
    
    -
    
    
    -Net
      Utility Operations
    
    
    10,513,000
    
    
    1,948,182
    
    
    1,433,581
    
    
    1,661,580
    
    
    450,613Investments
      - Gas Operations
    
    
    3,064,000
    
    
    -
    
    
    -
    
    
    -
    
    
    -Investments
      - Other
    
    
    480,000
    
    
    -
    
    
    -
    
    
    -
    
    
    -Total
      Revenues
    
    $
    14,057,000
    
    $
    1,948,182
    
    $
    1,433,581
    
    $
    1,661,580
    
    $
    450,613





**Description**
    
    
    **OPCo**
    
    
    **PSO**
    
    
    **SWEPCo**
    
    
    **TCC 
      (b)**
    ****
    
    **TNC(b)**
    ****(in
      thousands)Utility
      Operations:Retail
      SalesResidential
      Sales
    
    $
    471,515
    
    $
    395,571
    
    $
    331,478
    
    $
    216,954
    
    $
    56,033Commercial
      Sales
    
    
    312,264
    
    
    272,583
    
    
    280,244
    
    
    162,487
    
    
    28,300Industrial
      Sales
    
    
    534,800
    
    
    256,944
    
    
    205,948
    
    
    35,129
    
    
    8,301Total
      Other Retail Sales
    
    
    8,559
    
    
    92,325
    
    
    6,220
    
    
    9,064
    
    
    11,386Total
      Retail
    
    
    1,327,138
    
    
    1,017,423
    
    
    823,890
    
    
    423,634
    
    
    104,020WholesaleSystem
      Sales & Transmission
    
    
    250,001
    
    
    (7,230
    )
    
    122,798
    
    
    636,621
    
    
    307,926Risk
      Management Realized
    
    
    10,289
    
    
    13
    
    
    (267
    )
    
    234
    
    
    503Risk
      Management Mark-to-Market
    
    
    9,002
    
    
    -
    
    
    571
    
    
    3,628
    
    
    1,528Total
      Wholesale
    
    
    269,292
    
    
    (7,217
    )
    
    123,102
    
    
    640,483
    
    
    309,957Other
      Operating Revenues
    
    
    58,451
    
    
    26,625
    
    
    76,124
    
    
    127,010
    
    
    37,664Sales
      to Affiliates
    
    
    581,515
    
    
    10,690
    
    
    71,190
    
    
    47,039
    
    
    51,680Gross
      Utility Operating Revenues
    
    
    2,236,396
    
    
    1,047,521
    
    
    1,094,306
    
    
    1,238,166
    
    
    503,321Provision
      for Rate Refund
    
    
    -
    
    
    -
    
    
    (6,960
    )
    
    (62,900
    )
    
    (11,176
    )Net
      Utility Operations
    
    
    2,236,396
    
    
    1,047,521
    
    
    1,087,346
    
    
    1,175,266
    
    
    492,145Investments
      - Gas Operations
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Investments
      - Other
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    -Total
      Revenues
    
    $
    2,236,396
    
    $
    1,047,521
    
    $
    1,087,346
    
    $
    1,175,266
    
    $
    492,145





(a)
    Includes
      revenues of other subsidiaries not shown. Intercompany transactions have
      been eliminated, including AEGCo’s total revenues of $241,788,000 for the
      year ended December 31, 2004, all of which resulted from its wholesale
      business, including its marketing and trading of
power.





(b)
    TCC
      and TNC wire sales to REPs moved to retail classes of
      customer.





***HOLDING
COMPANY REGULATION***





The
provisions of PUHCA, are administered by the SEC.  PUHCA regulates 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.





Legislation
has been introduced in numerous sessions of Congress that would repeal PUHCA,
but no such legislation has passed.





***AEP-CSW
MERGER***





On June
15, 2000, a wholly owned merger subsidiary of AEP merged with and into CSW (now
known as AEP Utilities, Inc.). 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.





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.” A hearing was
held January 10, 2005 before an ALJ. An initial decision is expected from the
ALJ later this year. The SEC will have the opportunity to review the initial
decision.





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. In recent history short-term debt has 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 2004, 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, 2004, 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 2004 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 2004,
AEP executives met with representatives of the rating agencies to review AEP and
its registrant subsidiaries’ historical and forecasted financial condition,
operations and other matters.





In August
2004, Moody’s placed AEP on positive outlook. In July 2004, S&P upgraded the
senior secured ratings of PSO and SWEPCo to A- from BBB. To date, S&P has
not changed the ratings of AEP or any other of its rated subsidiaries. Fitch did
not change the ratings of AEP or its rated subsidiaries during
2004.





The
senior secured ratings on certain of AEP’s rated subsidiaries will be removed
where secured debt no longer exists.





See *Management’s
Financial Discussion and Analysis of Results of Operations* ,
included in the 2004 Annual Reports, under the heading entitled *Financial
Condition* for
additional information with respect to the credit ratings of the registrants
other than AEGCo.





***ENVIRONMENTAL
AND OTHER MATTERS***





**General**





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





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





·
    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 7 to the consolidated financial statements entitled*Commitments
      and Contingencies*,
      included in the 2004 Annual Reports, for further
    information.





·
    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, SO**2**and Hg*and*Estimated
      Air Quality Investments*and
      Note 7 to the consolidated financial statements entitled*Commitments
      and Contingencies*,
      included in the 2004 Annual Reports under the heading entitled*NOx
      Reductions*for
      further information.





·
    CERCLA,
      which imposes upon owners and previous owners of sites, as well as
      transporters and generators of hazardous material disposed of at such
      sites, costs for environmental remediation. AEP does not, however,
      anticipate that any of its currently identified CERCLA-related issues will
      result in material costs or penalties to the AEP System. See*Management’s
      Financial Discussion and Analysis of Results of
      Operations*,
      included in the 2004 Annual Reports, under the heading entitled*Superfund
      and State Remediation*for
      further information*.*





·
    The
      Federal Clean Water Act, which prohibits the discharge of pollutants into
      waters of the United States except pursuant to appropriate permits. In
      July 2004, the EPA 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 2004 Annual Reports, under the heading entitled*Clean
      Water Act Regulation*for additional information.





·
    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 2004 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.





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 2004 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 2003 and 2004 and the current
estimate for 2005 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, SO* *2*  *and
Hg* and *Estimated
Air Quality Investments* ;
and ** Note 7 to
the consolidated financial statements, entitled *Commitments
and Contingencies,* included
in the 2004 Annual Reports, for more information regarding this litigation and
environmental expenditures in general.








**2003**
      **Actual**
    
    
    **2004**
      **Actual**
    
    
    **2005**
      **Estimate****(in
      thousands)**AEGCo
    
    $
    11,800
    
    $
    6,500
    
    $
    2,100APCo
    
    
    70,600
    
    
    165,800
    
    
    309,600CSPCo
    
    
    31,400
    
    
    26,600
    
    
    23,400I&M
    
    
    14,900
    
    
    11,900
    
    
    82,300KPCo
    
    
    40,500
    
    
    2,900
    
    
    8,500OPCo
    
    
    40,000
    
    
    136,400
    
    
    485,400PSO
    
    
    1,700
    
    
    100
    
    
    500SWEPCo
    
    
    3,200
    
    
    4,100
    
    
    24,400TCC
    
    
    500
    
    
    0
    
    
    0TNC
    
    
    2,600
    
    
    0
    
    
    400AEP
      System
    
    $
    217,200
    
    $
    354,300
    
    $
    936,600








**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.





**UTILITY OPERATIONS**





***GENERAL***





Utility
operations constitute most 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 34,500 MW of domestic generation.
See *Deactivation
and Disposition of Generating Facilities* for a
discussion of planned and completed 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, 2004, the member-load ratios were as
follows:




**Peak****Demand****(MW)**
    **Member-Load****Ratio
      (%)**APCo
    6,298
    30.7CSPCo
    3,623
    17.6I&M
    4,051
    19.8KPCo
    1,478
    7.2OPCo
    5,059
    24.7





Although
customer choice was adopted in Ohio in 2001, CSPCo and OPCo plan to remain
functionally separated through at least December 31, 2008 as authorized by their
rate stabilization plan approved by the PUCO. See *Management’s
Financial Discussion and Analysis and Financial Condition,* under
the heading entitled *Regulatory
Matters, Ohio* included
in the 2004 Annual Reports and Note 6 to the consolidated financial statements,
entitled *Customer
Choice and Industry Restructuring* ,
included in the 2004 Annual Reports, for more information.





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, 2002, 2003 and 2004:





**2002**
    
    
    **2003**
    
    
    **2004****(in
      thousands)**APCo
    
    $
    127,000
    
    $
    218,000
    
    $
    239,400CSPCo
    
    
    267,000
    
    
    276,800
    
    
    284,900I&M
    
    
    (113,600
    )
    
    (118,800
    )
    
    (141,500
    )KPCo
    
    
    46,500
    
    
    38,400
    
    
    31,600OPCo
    
    
    (326,900
    )
    
    (414,400
    )
    
    (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, 2002, 2003
and 2004:





**2002**
    
    
    **2003**
    
    
    **2004****(in
      thousands)**PSO
    
    $
    53,700
    
    $
    44,000
    
    $
    55,000SWEPCo
    
    
    (67,800
    )
    
    (46,600
    )
    
    (59,800
    )TCC
    
    
    (15,400
    )
    
    (29,500
    )
    
    1,100TNC
    
    
    29,500
    
    
    32,100
    
    
    3,700





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 and Virginia,
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 that is
not needed to serve the native load of our public utility subsidiaries is sold
in the wholesale market by AEPSC on behalf of those subsidiaries. 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**





As agent
for AEP’s public utility subsidiaries, AEP 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, 2004, counterparties have posted approximately $98 million in cash, cash
equivalents or letters of credit with AEPSC for the benefit of AEP’s public
utility subsidiaries (while, as of that date, AEP’s public utility subsidiaries
had posted approximately $2 million with counterparties). 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:




****
    **2002**
    **2003**
    **2004**Coal
    78%
    80%
    83%Natural
      Gas
    8%
    7%
    5%Nuclear
    11%
    9%
    12%Hydroelectric
      and other
    3%
    4%
    1%


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 or sale of certain gas-fired plants
owned by TCC and TNC. Price increases in one or more fuel sources relative to
other fuels generally result in increased use of other fuels.





***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.
The price for most coal fuels has increased resulting in a trend that may
continue. Management has responded to increases in the price of coal by
rebalancing the coal used in its generating facilities with products from
different coal regions and sources of differing heat rates and sulfur content.
This rebalancing is an ongoing process that is expected to continue. Management
believes, but cannot provide assurances that, AEP’s public utility subsidiaries
will be able to secure and transport 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:





****
    **2002**
    **2003**
    **2004**Total
      coal delivered to AEP operated plants (thousands of tons)
    76,442
    76,042
    71,778Average
      price per ton of spot-purchased coal
    $27.06
    $28.91
    $33.83





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, 2004, the System’s coal
inventory was approximately 31 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 reallocate coal and to require the
transportation thereof, for the use at power plants or major fuel-burning
installations experiencing fuel shortages.


***Natural
Gas****:*Through
its public utility subsidiaries, AEP consumed over 94 billion cubic feet of
natural gas during 2004 for generating power. A majority of the natural
gas-fired power plants are connected to at least two pipelines, which allows
greater access to competitive supplies and improves reliability. A portfolio of
long-term, monthly and seasonal firm 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 their current 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 2011 and (ii) 100% of the uranium concentrate
needed for STP through spring 2011. See *Deactivation
and 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 dispose of spent nuclear fuel and
decommission and decontaminate the plants safely. The ultimate cost of retiring
the Cook Plant and STP may be materially different from estimates and funding
targets as a result of the:





·
    Type
      of decommissioning plan selected;





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





·
    Further
      development of regulatory requirements governing
      decommissioning;





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





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





·
    Availability
      of nuclear waste disposal facilities;





·
    Availability
      of a Department of Energy facility for permanent storage of spent nuclear
      fuel; and





·
    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 *Deactivation
and Disposition of Generation Facilities* for more
information about TCC’s interest in STP.





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 2004 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. See *Deactivation
and Disposition of Generation Facilities* for more
information about TCC’s interest in STP.





**Deactivation
and Disposition of Generation Facilities**





Pursuant
to ERCOT’s approval, AEP deactivated 16 gas-fired power plants (8 TCC plants and
8 TNC plants). Separately, TCC conducted 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
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 had a generating capacity of 4,497 MW and included the eight deactivated
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
its 25.2% share in STP and sold the remaining generation assets in July 2004.
See Notes 6 and 10 to the consolidated financial statements entitled *Customer
Choice and Industry Restructuring* and *Acquisitions,
Dispositions, Discontinued Operations, Impairments, Assets Held For Sale and
Assets Held and Used* ,
included in the 2004 Annual Reports, for more information on the 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.  Whether or not power is available from AEGCo, I&M is
obligated 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). When added to
amounts received by AEGCo from any other sources, such amounts 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
last of the lease terms of Unit 2 of the Rockport Plant has expired (currently
December 2022) 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 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 was extended in November 2004 for an additional 18 years and now
expires in December 2022.





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%. In April 2004, AEP
agreed to sell a portion of its shares in OVEC (.73% of OVEC) to Louisville Gas
and Electric Company. The sale is expected to close in the first quarter of
2005. Following the sale, the aggregate equity participation of AEP and CSPCo in
OVEC will be 43.47%. 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
obligated to 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 (ICPA), which defines the rights of the owners and sets the
power participation ratio of each, will expire by its terms on March 12, 2006.
An Amended and Restated ICPA has been unanimously approved and executed by the
sponsoring companies and OVEC to extend the term of the ICPA for an additional
20 years to March 13, 2026. The aggregate power participation ratio of the AEP
entities in the Amended and Restated ICPA is 43.47%. The AEP-affiliated owners
of OVEC and the other owners are evaluating the need for environmental
investments related to their ownership interests, which may be
material.





***Buckeye:*** ** Transmission
service agreements between Buckeye, AEP and other transmission owners provide
for the transmission and delivery of power generated by Buckeye at the Cardinal
Station. These transmission agreements were made pursuant to the applicable open
access transmission tariffs (OATT) of AEP and others. On October 1, 2004, AEP
joined PJM, and the Buckeye transmission service over the AEP system was
transferred under the PJM OATT. Buckeye is entitled under the Cardinal Station


Agreement
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, 2004, the member-load ratios
were as follows:





**Peak
      Demand****(MW)**
    **Member-Load****Ratio
      (%)**APCo
    6,298
    30.7CSPCo
    3,623
    17.6I&M
    4,051
    19.8KPCo
    1,478
    7.2OPCo
    5,059
    24.7





The
following table shows the net (credits) or charges allocated among the parties
to the TEA during the years ended December 31, 2002, 2003 and 2004:





****
    
    
    **2002**
    
    
    **2003**
    
    
    **2004****(in
      thousands)**APCo
    
    $
    (13,400
    )
    $
    0
    
    $
    (500
    )CSPCo
    
    
    42,200
    
    
    38,200
    
    
    37,700I&M
    
    
    (36,100
    )
    
    (39,800
    )
    
    (40,800
    )KPCo
    
    
    (5,400
    )
    
    (5,600
    )
    
    (6,100
    )OPCo
    
    
    12,700
    
    
    7,200
    
    
    9,700





***Transmission
Coordination Agreement:*** ** PSO,
SWEPCo, TCC, TNC and AEPSC are parties to the 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, 2002, 2003 and 2004:





****
    
    
    **2002**
    
    
    **2003**
    
    
    **2004****(in
      thousands)**PSO
    
    $
    4,200
    
    $
    4,200
    
    $
    8,100SWEPCo
    
    
    5,000
    
    
    5,000
    
    
    13,800TCC
    
    
    (3,600
    )
    
    (3,600
    )
    
    (12,200
    )TNC
    
    
    (5,600
    )
    
    (5,600
    )
    
    (9,700
    )





***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.* Transmission
of electric power by AEP’s public utility subsidiaries is regulated by the FERC.





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





·
    The
      allocation of transmission costs and revenues and





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





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





**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 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.





As a
condition of FERC’s approval in 2000 of AEP’s merger with CSW, AEP was required
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. The AEP East Companies integrated into PJM on October 1, 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. In October 2004,
the FERC issued an order granting RTO status to SPP subject to certain filings.
The Arkansas Public Service Commission and LPSC have required filings related to
SWEPCo’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 2004 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**





In July
2003, the FERC issued an order directing PJM and the MISO to make compliance
filings for their respective OATTs to eliminate 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
(Combined Footprint). 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.





AEP and
several other utilities in the Combined Footprint filed a proposal for new rates
to become effective December 1, 2004. In November 2004, FERC eliminated the
T&O rates and replaced the rates temporarily through March 2006 with a seams
elimination cost adjustment (SECA) fees. AEP’s East zone public utility
subsidiaries received approximately $1 96 million
of T&O rate revenues for the twelve months ended September 30, 2004, the
last twelve months prior to joining PJM. The
portion of those revenues associated with transactions for which the T&O
rate is being eliminated and replaced by SECA fees was $171 million. Effective
April 2006, all transmission costs that would otherwise be defrayed by T&O
rates in the Combined Footprint will be subject to recovery from native load
customers of AEP’s East zone public utility subsidiaries. At this time,
management is unable to predict whether any resultant increase in rates
applicable to AEP’s internal load will be recoverable on a timely basis from
state retail customers. Unless new replacement rates compensate AEP for its lost
revenues and any increase in AEP’s East zone public utility subsidiaries’
transmission expenses from these new rates are fully recovered in retail rates
on a timely basis, future results of operations, cash flows and financial
condition will be adversely affected. 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. While still
regulated, retail sales in Michigan are now made at unbundled rates. 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.
In Ohio, the PUCO has approved the rate stabilization plans filed by OPCo and
CSPCo which, among other things, address retail generation service rates through
December 31, 2008. In Virginia, APCO’s base rates are capped, subject to certain
adjustments, at their mid-1999 levels until December 31, 2010, or sooner if the
VSCC finds that a competitive market for generation exists in
Virginia.





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 through a fuel adjustment clause 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 bundled rates 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 rates were
capped through December 31, 2004. Its fuel recovery rate was capped through
February 29, 2004. On September 22, 2004, the IURC issued an order extending the
interim fuel factor through March 2005, subject to true-up upon resolution of
the (previously filed but unexecuted) corporate separation plan. The status of
additional base and fuel clause rate caps, subject to certain conditions, is
presently under discussion with the parties to a proposed settlement agreement
relating to AEP’s corporate separation issues.





***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. The PUCO approved 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). 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 (with certain exceptions) from their levels as of December
31, 2005 through December 31, 2008. 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 2004 Annual Reports, for more information.





***Oklahoma*** *:* PSO
provides retail electric service in Oklahoma at bundled rates 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 are returned to or recovered
from customers when new quarterly factors are established. See Note 4 to the
consolidated financial statements, entitled *Rate
Matters* ,
included in the 2004 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 2004 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, which was amended in 2004, capped APCO’s base rates at their
mid-1999 levels until the end of the transition period (now December 31, 2010),
or sooner if the VSCC finds that a competitive market for generation exists in
Virginia. The Virginia Act permits APCo to seek two changes to its capped rates
as follows: one prior to July 1, 2007, and one between July 1, 2007 and December
31, 2010. In addition, as a result of the 2004 amendments, APCo is entitled to
annual rate changes to recover the incremental costs it incurs on and after July
1, 2004 for transmission and distribution reliability and compliance with state
or federal environmental laws or regulations. The Virginia Act also 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 for timely recovery of fuel costs, the most
recent rate proceeding for both APCo and WPCo resulted in the suspension of
their operative fuel clause mechanisms (though they continue to recover a fixed
level of fuel costs through 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
following table illustrates the current rate regulation status of the states in
which the public utility subsidiaries of AEP operate:





**Fuel
      Clause Rates(7)****System
      Sales Profits**
    
    ****Percentage**of AEP System****Status
      of Base Rates for**
    
    
    
    **Shared
      with**
    
    **Retail****Jurisdiction**
    
    **Power
      Supply**
    
    **Energy
      Delivery**
    
    **Status**
    
    **Ratepayers**
    
    **Revenues(1)**Ohio
    
    Frozen
      through 2005 (2)
    
    Distribution
      frozen through 2008 (2)
    
    None
    
    Not
      applicable
    
    32%Oklahoma
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    Yes
    
    13%Texas
      ERCOT
    
    See
      footnote 3
    
    Not
      capped or frozen
    
    Not
      applicable
    
    Not
      applicable
    
    8%(3)Texas
      SPP
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    Yes,
      above base levels
    
    4%(3)Indiana
    
    Extension
      of freeze is pending(4)
    
    Extension
      of freeze is pending (4)
    
    Extension
      of cap is pending (4)
    
    No
    
    11%Virginia
    
    Capped
      until as late as 12/31/10 (5)
    
    Capped
      until as late as 12/31/10 (5)
    
    Active
    
    No
    
    9%West
      Virginia
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Suspended
      (6)
    
    Yes,
      but suspended
    
    9%Louisiana
    
    Capped
      until 6/15/05
    
    Capped
      until 6/15/05
    
    Active
    
    Yes,
      above base levels
    
    4%Kentucky
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    Yes,
      above base levels
    
    4%Arkansas
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    Yes,
      above base levels
    
    3%Michigan
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    Yes,
      in some areas
    
    2%Tennessee
    
    Not
      capped or frozen
    
    Not
      capped or frozen
    
    Active
    
    No
    
    1%





(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,
      2004.





(2)
    The
      PUCO has approved the rate stabilization plan filed by CSPCo and OPCo that
      begins after the market development period and extends through December
      31, 2008 during which OPCo’s retail generation rates will increase 7%
      annually and CSPCo’s retail generation rates will increase 3% annually.
      Distribution rates are frozen, with certain exceptions, through December
      31, 2008.





(3)
    Retail
      electric service in the ERCOT area of Texas is provided to most customers
      through unaffiliated REPs with TCC and TNC providing only regulated
      delivery services. Retail electric service in the SPP area of Texas is
      provided by SWEPCo and an affiliated REP.





(4)
    Capped
      base rates pursuant to a 1999 settlement with base rate freeze extended
      pursuant to merger stipulation. The status of additional base and fuel
      clause rate caps, subject to certain conditions, is presently under
      discussion andthere is an issue as to whether the freeze and cap extend through 2007
      under an existing corporate separation stipulation agreement.
      The interim fuel clause rate cap expires in April
2005.





(5)
    Legislation
      passed in 2004 capped base rates until December 31, 2010 and expanded the
      rate change opportunities to one full rate case (including generation,
      transmission and distribution) between July 1, 2004 and June 30, 2007 and
      one additional full rate case between July 1, 2007 and December 31, 2010.
      The new law also permits APCo to recover, on a timely basis, incremental
      costs incurred on and after July 1, 2004 for transmission and distribution
      reliability purposes and to comply with state and federal environmental
      laws and regulations.





(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)
    Includes,
      where applicable, fuel and fuel portion of purchased
  power.








**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. 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
appealed that order, and the FERC 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 April
2004, the FERC issued two orders concerning utilities’ ability to sell wholesale
electricity at market-based rates. In the first order, the FERC adopted two new
interim screens for assessing potential generation market power of applicants
for wholesale market based rates, and described additional analyses and
mitigation measures that could be presented if an applicant does not pass one of
these interim screens. These two screening tests include a “pivotal supplier”
test which determines if the market load can be fully served by alternative
suppliers and a “market share” test which compares the amount of surplus
generation at the time of the applicant’s minimum load. In July 2004, the FERC
issued an order on rehearing affirming its conclusions in the April order and
directing AEP and two unaffiliated utilities to file generation market power
analyses within 30 days. In the second order, the FERC initiated a rulemaking to
consider whether the FERC’s current methodology for determining whether a public
utility should be allowed to sell wholesale electricity at market-based rates
should be modified in any way.





On August
9, 2004, as amended on September 16, 2004 and November 19, 2004, AEP submitted
its generation market power screens in compliance with the FERC’s orders. The
analysis focused on the three major areas in which AEP serves load and owns
generation resources -- ECAR, SPP and ERCOT, and the “first tier” control areas
for each of those areas.





The
pivotal supplier and market share screen analyses that AEP filed demonstrated
that AEP does not possess market power in any of the control areas to which it
is directly connected (first-tier markets). AEP passed both screening tests in
all of its “first tier” markets. In its three “home” control areas, AEP passed
the pivotal supplier test. As part of PJM, AEP also passes the market share
screen for the PJM destination market. AEP also passed the market share screen
for ERCOT. AEP did not pass the market share screen as designed by the FERC for
the SPP control area.





In a
December 17, 2004 Order, FERC affirmed our conclusions that we passed both
market power screen tests in all areas except SPP. Because AEP did not pass the
market share screen in SPP, FERC initiated a proceeding under Section 206 of the
FPA in which AEP is rebuttably presumed to possess market power in SPP.
Consequently, our revenues from sales within our control area of the SPP at
market based rates after March 6, 2005 will be collected subject to refund to
the extent that prices are ultimately found not to be just and reasonable. In
February 2005 AEP filed with the FERC revisions to its market-based rate tariffs
that cap the rates of wholesale power that AEP delivers within its control area
of the SPP. We are unable to predict the timing or impact of any further action
by the FERC.





***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 unlikely. In order for West Virginia’s choice plan
to become effective, tax legislation must be passed to preserve pre-legislation
levels of funding for state and local governments. Because such legislation has
not been passed and because legislation enacted in March 2003 clarified the
jurisdiction of the WVPSC over electric generation facilities, 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 2004 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* for
additional information.





**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,
2004, none of I&M’s Michigan customers have 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 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. The PUCO
approved the rate stabilization plan filed by CSPCo and OPCo, with certain
modifications. The Commission authorized CSPCo and OPCo to remain functionally
separated through the end of that three-year period.





**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
Act:





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


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


·
    required
      that REPs provide 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 Act 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.





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* and Note
6 to the consolidated financial statements entitled *Customer
Choice and Industry Restructuring.*





**Virginia
Restructuring**





In April
2004, the Governor of Virginia signed legislation that extends the transition
period for electricity restructuring, including capped rates, through December
31, 2010. The legislation provides specified cost recovery opportunities during
the capped rate period, including two optional general base rate changes and an
opportunity for timely recovery, through a separate rate mechanism, of certain
incremental environmental and reliability costs incurred on and after July 1,
2004.





**Texas
Regulatory Assets And Stranded Cost Recovery And Post-Restructuring Wires
Charges**





TCC 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 excess cost over market (ECOM) model. Carrying costs on
stranded costs are also allowed to be recovered beginning January 1,
2002.





TCC’s
true-up proceedings will determine the amount and recovery of:





·
    net
      stranded generation plant costs and net generation-related regulatory
      assets less any unrefunded excess earnings (net stranded generation
      costs),


·
    a
      true-up of actual market prices determined through legislatively-mandated
      capacity auctions to the projected power costs used in the PUCT’s ECOM
      model for 2002 and 2003 (wholesale capacity auction
    true-up),


·
    excess
      of price-to-beat revenues over market prices subject to certain conditions
      and limitations (retail clawback),


·
    final
      approved deferred fuel balance, and


·
    net
      carrying costs on the above true-up amounts.





The PUCT
adopted a rule in 2003 regarding the timing of the true-up proceedings
scheduling TCC’s filing 60 days after the completion of the sale of TCC’s
generation assets. Due to regulatory and contractual delays in the sale of its
generating assets, TCC has not yet filed its true-up request.





TCC’s net
true-up regulatory assets (liabilities) recorded at December 31, 2004 is set
forth in the following table.





**TCC’s
net true-up regulatory assets (liabilities)**


**(in
      millions)**Stranded
      Generation Plant Costs
    
    $
    897Net
      Generation-related Regulatory Asset
    
    
    249Unrefunded
      Excess Earnings
    
    
    (10
    )**Net
      Stranded Generation Costs**
    
    
    1,136Carrying
      Costs on Stranded Generation Plant Costs
    
    
    225**Net
      Stranded Generation Costs Designated for
      Securitization**
    
    
    1,361Wholesale
      Capacity Auction True-up
    
    
    483Carrying
      Costs on Wholesale Capacity Auction True-up
    
    
    77Retail
      Clawback
    
    
    (61
    )Deferred
      Over-recovered Fuel Balance
    
    
    (212
    )**Net
      Other Recoverable True-up Amounts**
    
    
    287**Total
      Recorded Net True-up Regulatory Asset (Liability)**
    
    $
    1,648


For a
more complete discussion of recovery of regulatory assets and stranded costs in
Texas, see Note 6 to the consolidated financial statements entitled *Customer
Choice and Industry Restructuring* ,
included in the 2004 Annual Reports.





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 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.





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 2004 Annual Reports.





***COMPETITION***





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***





During
2004 we sold our interests in Louisiana Intrastate Gas and Jefferson Island
Storage & Hub. In January 2005, we sold a 98% controlling interest in HPL
and related assets. We currently retain a 2% ownership interest in HPL and will
provide certain transitional services to the buyer. See Notes 10 and 19 to the
consolidated financial statements entitled *Acquisitions,
Dispositions, Discontinued Operations, Impairments, Assets Held for Sale and
Assets Held and Used* and *Subsequent
Events (unaudited)* ,
respectively, included in the 2004 Annual Reports for more information. Before
these sales, our gas marketing operations had been significantly curtailed. As a
result of these sales, management anticipates that our gas marketing operations
will be limited to managing our obligations with respect to the gas transactions
entered into before to these sales.





***UK
OPERATIONS***





Through
subsidiaries, AEP operated and owned 4,000 MW of power generation facilities in
the UK. These assets and related commodities contracts were sold to Scottish and
Southern Energy plc in the third quarter of 2004. AEP also sold its 50 percent
interest in South Coast Power Limited to co-owner Scottish Power Generation
Limited in the third quarter of 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 2004 Annual Reports.








***OTHER***





**General**





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





·
    791
      MW of domestic and 605 MW of international power generation facilities (of
      which its ownership is approximately 551 MW and 302 MW, respectively);





·
    Undeveloped
      and formerly operated coal properties and related facilities; and





·
    Barge,
      rail and other fuel transportation related assets.





These
operations include the following activities:





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





·
    Holding
      various properties, coal reserves and royalty interests and reclaiming
      formerly operated mining properties in Colorado, Indiana, Kentucky,
      Louisiana, Ohio, Texas, Utah and West Virginia;
and





·
    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. Through certain subsidiaries, AEP owns or
      leases 7,065 railcars, 2,230 barges, 53 towboats and a coal handling
      terminal with 20 million tons of annual
capacity.





AEP has
in the past three 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 2004 Annual Reports.





**Dow
Chemical Cogeneration Facility**





Pursuant
to an agreement with Dow, AEP constructed a 900 MW cogeneration facility at
Dow’s chemical facility in Plaquemine, Louisiana that achieved commercial
operation status on March 18, 2004. AEP’s subsidiary, OPCo, has been taking 100%
of the facility’s capacity and energy over Dow’s requirements and contracted to
sell the power from this facility for twenty years to Tractebel. The power
supply contract with Tractebel is in dispute and the power from this plant is
currently sold on the market. 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 2004 Annual Reports, for more
information.








**ITEM
2.** **PROPERTIES**





**GENERATION FACILITIES**





***GENERAL***





At
December 31, 2004, 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:





**Company**
    
    **Stations**
    
    **Coal**
      **MW**
    
    **Natural
      Gas**
      **MW**
    
    **Hydro**
      **MW**
    
    **Nuclear**
      **MW**
    
    **Lignite**
      **MW**
    
    **Oil**
      **MW**
    
    **Total**
      **MW**AEGCo
    
    1
    (a)
    
    1,300
    
    
    
    
    
    
    
    
    
    
    
    1,300APCo
    
    16
    (b)
    
    5,073
    
    
    
    798
    
    
    
    
    
    
    
    5,871CSPCo
    
    5
    (e)
    
    2,595
    
    
    
    
    
    
    
    
    
    
    
    2,595I&M
    
    9
    (a)
    
    2,295
    
    
    
    11
    
    2,143
    
    
    
    
    
    4,449KPCo
    
    1
    
    
    1,060
    
    
    
    
    
    
    
    
    
    
    
    1,060OPCo
    
    8
    (b)(f)
    
    8,472
    
    
    
    48
    
    
    
    
    
    
    
    8,520PSO
    
    8
    (c)
    
    1,018
    
    3,139
    
    
    
    
    
    
    
    25
    
    4,182SWEPCo
    
    9
    
    
    1,848
    
    1,797
    
    
    
    
    
    842
    
    
    
    4,487TCC
    
    2
    (c)(d)(g)
    
    54
    
    
    
    
    
    630
    
    
    
    
    
    684TNC
    
    11
    (c)
    
    377
    
    999
    (h)
    
    
    
    
    
    
    10
    
    1,386Totals:
    
    65
    
    
    24,092
    
    5,935
    
    857
    
    2,773
    
    842
    
    35
    
    34,534





(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, along with two unaffiliated companies, 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. OPCo
      may terminate the lease as early as 2010.





(g)
    See*Item
      1 — Utility Operations — Electric Generation — Deactivation and
      Disposition of Generation Facilities*for
      a discussion of TCC’s planned disposition of all its generation
      facilities.





(h)
    TNC’s
      gas fired generation is deactivated.





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, 2004 is listed
below.





**Facility**
    **Fuel**
    **Location**
    **Capacity**
      **Total
      MW**
    **Ownership**
      **Interest**
    **Status**Desert
      Sky Wind Farm
    Wind
    Texas
    161
    100%
    Exempt
      Wholesale Generator(1)Sweeney
    Natural
      gas
    Texas
    480
    50%
    Qualifying
      Facility(2)Trent
      Wind Farm
    Wind
    Texas
    150
    100%
    Exempt
      Wholesale Generator(1)**Total
      U.S.**
    
    
    791Bajio
    Natural
      gas
    Mexico
    605
    50%
    Foreign
      Utility Company(1)**Total**
    
    
    1,396





(1)
    As
      defined under PUHCA


(2)
    As
      defined under the Public Utility Regulatory Policies Act of
      1978





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 2004 Annual Reports, for a discussion of AEP’s planned use and/or
disposition of independent power producer and foreign generation assets.





***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 (e)****2004**
    97.0%
    
    81.6%
    
    100.8%
    
    93.7%**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. TCC has an ownership interest in STP of approximately 25.2%.
      TCC has entered into an agreement to sell this interest and the sale is
      expected to be completed in 2005.





(b)
    AEP
      has filed to extend the licenses at the Cook
Plant.





(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. The capacity
      factors for the STP units were reduced due to an unplanned outage for BMI
      repairs on Unit 1 and an unplanned outage for turbine repairs on Unit
      2.





(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.





(e)
    Cook
      Plant 2004 Net Capacity Factor values reflect Nominal Net Electrical
      Rating in Kilowatts of 1,036,000 (Unit 1) and 1,107,000 (Unit 2). However,
      Cook Plant 2003 and earlier Net Capacity Factor values reflect previous
      Nominal Net Electrical Rating in Kilowatts of 1,020,000 (Unit 1) and
      1,090,000 (Unit 2).





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 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.





**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 kV lines:





****
    **Total
      Overhead**
      **Circuit
      Miles of**
      **Transmission
      and**
      **Distribution
      Lines**
    
    **Circuit
      Miles of**
      **765
      kV Lines**AEP
      System (a)
    216,306
    (b)
    
    2,026APCo
    51,147
    
    
    644CSPCo
      (a)
    14,030
    
    
    —I&M
    21,980
    
    
    615Kingsport
      Power Company
    1,343
    
    
    —KPCo
    10,780
    
    
    258OPCo
    30,627
    
    
    509PSO
    21,100
    
    
    —SWEPCo
    20,455
    
    
    —TCC
    29,571
    
    
    —TNC
    13,578
    
    
    —Wheeling
      Power Company
    1,696
    
    
    —





(a)
    Includes
      766 miles of 345 kV 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 which permits them, if necessary, to acquire, perfect or secure titles to
or easements on privately held lands used or to be used in their utility
operations. Recent legislation in Ohio and Virginia has restricted the right of
eminent domain previously granted for power generation purposes.





Substantially
all the fixed physical properties and franchises of TNC, APCo, PSO, and SWEPCo,
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**





Laws in
the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas,
Tennessee, Virginia, and West Virginia require prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. We have
experienced delays and additional costs in constructing facilities as a result
of proceedings conducted pursuant to such statutes, and in proceedings in which
our operating companies have sought to acquire rights-of-way through
condemnation. These 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. AEP
forecasts $2.7 billion of construction expenditures for 2005. Estimated
construction expenditures are subject to periodic review and modification and
may vary based on the ongoing effects of regulatory constraints, environmental
regulations, business opportunities, market volatility, economic trends, and the
ability to access capital.





***PROPOSED
TRANSMISSION FACILITIES***





APCo is
proceeding with its plan to build the Jacksons
Ferry-Wyoming 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. On May 11, 2004, the decision of the Forest Service
was challenged by the Sierra Club in the United States District Court for the
Western District of Virginia. APCo has intervened in that litigation .
Construction of the line is underway and the project is scheduled to be
completed by June 2006.





***PROPOSED
GENERATION FACILITY***





In
conjunction with an environmental impact study issued in August 2004, in the
third quarter of 2004 we announced plans to construct a synthetic-gas-fired
plant or plants of approximately 1,000 MW of capacity in the next five
to six years utilizing integrated gasification combined cycle (IGCC) technology.
We estimate that this new plant or plants will cost in the range of
 $1.7 billion. We have not determined a location for the plant or
plants, but it or they will be in one of our eastern states, because of
ready access to coal. We are currently performing site analysis and evaluation
and at the same time working with state regulators and legislators to establish
a framework for expedient recovery of this significant investment in new clean
coal technology before final site selection.  We have filed with PJM for
transmission analysis of sites in Ohio, West Virginia and Kentucky.





Our
significant planned environmental investments in emission control installations
at existing coal-fired plants and our commitment to IGCC technology reinforce
our belief that coal will be a lower-emission domestic energy source of the
future and further signals our commitment to investing in clean, environmentally
safe technology. For additional information regarding anticipated environmental
expenditures, see *Management’s
Financial Discussion and Analysis of Results of Operations* under the
heading entitled *The
Current Air Quality Regulatory Framework* .





***CONSTRUCTION
EXPENDITURES***





The
following table shows construction expenditures (including environmental
expenditures) during 2002, 2003 and 2004 and current estimates of 2005
construction expenditures, in each case including AFUDC, but excluding assets
acquired under leases.








**2002**
      **Actual**
    
    
    **2003**
      **Actual**
    
    
    **2004**
      **Actual**
    
    
    **2005**
      **Estimate****(in
      thousands)**AEP
      System (a)
    
    $
    1,709,800
    
    $
    1,358,400
    
    $
    1,693,200
    
    $
    2,732,400AEGCo
    
    
    5,300
    
    
    22,200
    
    
    15,800
    
    
    19,900APCo
    
    
    276,500
    
    
    288,800
    
    
    452,200
    
    
    696,700CSPCo
    
    
    136,800
    
    
    136,300
    
    
    149,800
    
    
    193,900I&M
    
    
    159,400
    
    
    184,600
    
    
    176,800
    
    
    322,800KPCo
    
    
    178,700
    
    
    81,700
    
    
    38,500
    
    
    56,100OPCo
    
    
    354,800
    
    
    249,700
    
    
    345,500
    
    
    765,600PSO
    
    
    89,400
    
    
    86,800
    
    
    82,300
    
    
    126,200SWEPCo
    
    
    111,800
    
    
    121,100
    
    
    103,100
    
    
    200,900TCC
    
    
    151,600
    
    
    141,800
    
    
    121,300
    
    
    208,500TNC
    
    
    43,600
    
    
    46,700
    
    
    36,400
    
    
    73,900





(a)
    Includes
      expenditures of other subsidiaries not shown. Amounts in 2002 and 2003
      include construction expenditures related to entities classified in 2004
      as discontinued operations. These amounts were $186,500,000 and
      $24,900,000, respectively. The figures reflect construction expenditures,
      not investments in subsidiary companies.





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.





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 year.





**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.
Unless allowed to be recovered through rates, future losses or liabilities which
are not completely insured 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.








**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 MATTERSTO 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, 2005.





**Name**
    
    **Age**
    
    **Office
      (a)**Michael
      G. Morris
    
    58
    
    Chairman
      of the Board, President and Chief Executive Officer of AEP and of
      AEPSCCoulter
      R. Boyle III
    
    56
    
    Senior
      Vice President of AEP and Senior Vice President-Commercial Operations of
      AEPSCCarl
      L. English
    
    58
    
    President-Utility
      Group of AEP and of AEPSCThomas
      M. Hagan
    
    60
    
    Executive
      Vice President-AEP Utilities-West of AEPSCJohn
      B. Keane
    
    58
    
    Senior
      Vice President, General Counsel and Secretary of AEP and of
      AEPSCHolly
      K. Koeppel
    
    46
    
    Executive
      Vice President-AEP Utilities-East of AEPSCRobert
      P. Powers
    
    51
    
    Executive
      Vice President of AEP and Executive Vice President-Generation of
      AEPSCSusan
      Tomasky
    
    51
    
    Executive
      Vice President and Chief Financial Officer of AEP and of
    AEPSC





(a)
    Before
      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). Messrs. Boyle 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. Before joining AEPSC in June
      2000 as Senior Vice President-Governmental Affairs, Mr. Hagan was Senior
      Vice President-External Affairs of CSW (1996-2000). Before 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. As a result of AEP’s
      realignment of its executive management team in July 2004, Messrs. Boyle
      and Keane became executive officers of AEP. Before joining AEPSC in his
      current position in July 2004, Mr. Keane was President of Bainbridge
      Crossing Advisors. Prior to that, he was Vice President-Administration for
      Northeast Utilities (1998-2002). Mr. English joined AEP as
      President-Utility Group and became an executive officer of AEP on August
      1, 2004. Before joining AEPSC in his current position in August 2004, Mr.
      English was President and Chief Executive Officer of Consumers Energy gas
      division (1999-2004). 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, 2005, 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.





**Name**
    
    **Age**
    
    **Position**
    
    **Period**Michael
      G. Morris (a)(b)
    
    58
    
    Chairman
      of the Board, President, Chief Executive Officer and Director of
      AEP
    
    2004-PresentChairman
      of the Board, Chief Executive Officer and Director of AEPSC, APCo,
      I&M, OPCo, SWEPCo and TCC
    
    2004-PresentChairman
      of the Board, President and Chief Executive Officer of Northeast
      Utilities
    
    1997-2003Coulter
      R. Boyle III
    
    56
    
    Senior
      Vice President of AEP and Senior Vice President- Commercial Operations and
      Director of AEPSC
    
    2004-PresentVice
      President of APCo, I&M, OPCo, SWEPCo and TCC
    
    2004-PresentSenior
      Vice President of AEPSC
    
    2003-2004Vice
      President of AEPSC
    
    1999-2003Carl
      L. English (c)
    
    58
    
    President-Utility
      Group of AEP and President-Utility Group and Director of
    AEPSC
    
    2004-PresentDirector
      and Vice President of APCo, I&M, OPCo, SWEPCo and TCC
    
    2004-PresentPresident
      and Chief Executive Officer of Consumers Energy gas
    division
    
    1999-2004Thomas
      M. Hagan (d)
    
    60
    
    Executive
      Vice President-AEP Utilities-West and Director of AEPSC
    
    2004-PresentVice
      Chairman of the Board, Vice President and Director of TCC and
      SWEPCo
    
    2004-PresentVice
      President and Director of APCo, I&M and OPCo
    
    2002-2004Executive
      Vice President of AEP
    
    2004Executive
      Vice President-Shared Services of AEPSC
    
    2002-2004Senior
      Vice President-Governmental Affairs of AEPSC
    
    2000-2002Senior
      Vice President-External Affairs of CSW
    
    1996-2000John
      B. Keane (a)
    
    58
    
    Senior
      Vice President, General Counsel and Secretary of AEP and of
      AEPSC
    
    2004-PresentPresident
      of Bainbridge Crossing Advisors
    
    2003-2004Vice
      President-Administration-Northeast Utilities
    
    1998-2002Holly
      K. Koeppel (e)
    
    46
    
    Executive
      Vice President-AEP Utilities-East and Director of AEPSC
    
    2004-PresentVice
      Chairman of the Board, Vice President and Director of APCo, I&M and
      OPCo
    
    2004-PresentExecutive
      Vice President of AEP
    
    2004Executive
      Vice President-Commercial Operations of AEPSC
    
    2002-2004Vice
      President-New Ventures
    
    2000-2002Regional
      Vice President of Asia-Pacific Operations for Consolidated Natural Gas
      International
    
    1996-2000Robert
      P. Powers (a)
    
    51
    
    Executive
      Vice President of AEP
    
    2004-PresentDirector-AEPSC
    
    2001-PresentExecutive
      Vice President-Generation of AEPSC
    
    2003-2004Director
      and Vice President of APCo, OPCo, SWEPCo and TCC
    
    2001-PresentDirector
      of I&M
    
    2001-PresentVice
      President of I&M
    
    1998-PresentExecutive
      Vice President-Nuclear Generation and Technical Services of
      AEPSC
    
    2001-2003Senior
      Vice President-Nuclear Operations of AEPSC
    
    2000-2001Senior
      Vice President-Nuclear Generation and Director
      of AEPSC
    
    1998-2000Susan
      Tomasky (a)
    
    51
    
    Executive
      Vice President and Chief Financial Officer of AEP and of
    AEPSC
    
    2004-PresentChief
      Financial Officer of AEP
    
    2001-2004Director
      of AEPSC
    
    1998-PresentVice
      President and Director of APCo, I&M, OPCo, SWEPCo and
    TCC
    
    2000-PresentExecutive
      Vice President-Policy, Finance and Strategic Planning of
    AEPSC
    
    2001-2004Executive
      Vice President-Legal, Policy and Corporate Communications of
      AEPSC
    
    2000-2001Senior
      Vice President and General Counsel of AEPSC
    
    1998-2001





(a)
    Messrs.
      Keane, Morris and Powers and Ms. Tomasky are directors of AEGCo, CSPCo,
      KPCo, PSO and TNC.





(b)
    Mr.
      Morris is a director of Cincinnati Bell, Inc. and The Hartford Financial
      Services Group, Inc.





(c)
    Mr.
      English is a director of CSPCo, KPCo, PSO and
TNC.





(d)
    Mr.
      Hagan is a director of AEGCo, PSO and TNC.





(e)
    Ms.
      Koeppel is a director of CSPCo and KPCo.





****APCo:****Name**
    
    **Age**
    
    **Position**
    
    **Period**Dana
      E. Waldo
    
    53
    
    President
      and Chief Operating Officer of APCo and Kingsport Power
      Company
    
    2004-PresentPresident
      and Chief Executive Officer of West Virginia Roundtable
    
    1999-2004Vice
      President of APCo
    
    1995-1999**I&M:**Marsha
      P. Ryan
    
    54
    
    President
      and Chief Operating Officer of I&M
    
    2004-PresentSenior
      Vice President-Customer Operations of AEPSC
    
    2000-2004State
      President-Ohio
    
    1996-2000Vice
      President of APCo, I&M, SWEPCo and TCC
    
    2000-2004Vice
      President of CSPCo and OPCo
    
    1996-2004**OPCo:**Kevin
      E. Walker
    
    42
    
    President
      and Chief Operating Officer of CSPCo, OPCo and WPCo
    
    2004-PresentVice
      President of Consolidated Edison (New York)
    
    2001-2004Vice
      President of Public Service of New Hampshire
    
    2000-2001**SWEPCo:**Nicholas
      K. Akins
    
    44
    
    President
      and Chief Operating Officer of SWEPCo
    
    2004-PresentVice
      President of AEPSC
    
    2000-2004Director
      of CSW
    
    1999-2000**TCC:**Charles
      R. Patton
    
    45
    
    President
      and Chief Operating Officer of TCC
    
    2004-PresentVice
      President of Governmental and Environmental Affairs-Texas
    
    2002-2004Vice
      President of State Governmental Affairs of AEPSC
    
    2000-2002Director
      of Government Affairs
    
    1999-2000**







**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
2004 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 2004 and 2003
are incorporated by reference to the material under *Statement
of Retained Earnings* in the
2004 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
2004 Annual Reports.








**ITEM
7.**  **MANAGEMENT’S DISCUSSION AND ANALYSIS**


**OF
FINANCIAL CONDITION**


**AND
RESULTS OF OPERATION**





**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
2004 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
2004 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
2004 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 DISAGREEMENTSWITH**


**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
2004, management, including the principal executive officer and principal
financial officer of AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo
TCC and TNC (collectively, the “Registrants”), evaluated the Registrants’
disclosure controls and procedures relating to the recording, processing,
summarization and reporting of information in the Registrants’ periodic reports
filed with the SEC. These disclosure controls and procedures have been designed
to ensure that (a) material information relating to the Registrants is made
known to the Registrants’ management, including these officers, by other
employees of the Registrants 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. The Registrants’ disclosure controls and
procedures can only provide reasonable, not absolute, assurance that the above
objectives have been met.





As of
December 31, 2004, these officers concluded that the disclosure controls and
procedures in place are effective and provide reasonable assurance that the
disclosure controls and procedures accomplished their objectives. The
Registrants continually strive to improve their disclosure controls and
procedures to enhance the quality of their financial reporting and to maintain
dynamic systems that change as events warrant.





AEP’s
East zone public utility subsidiaries integrated into PJM on October 1, 2004. In
connection with this integration, AEP and these subsidiaries implemented or
modified a number of business processes and controls to facilitate participation
in, and resultant settlement within, the PJM market. Apart from this, there have
been no significant 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 2004 that have materially affected, or are
reasonably likely to materially affect, AEP’s internal controls over financial
reporting.





Additional
information required by this item of AEP, as an accelerated filer, is
incorporated by reference to *Management’s
Report on Internal Controls over Financial Reporting,* included
in the 2004 Annual Reports.





**ITEM
9B.**  **OTHER INFORMATION**





AEP’s
East zone public utility subsidiaries integrated into PJM on October 1, 2004
pursuant to various agreements filed herewith as exhibits. As a result, PJM has assumed
functional control of the transmission grid of AEP’s
East zone public utility subsidiaries.




The Human
Resources Committee of AEP’s Board of Directors (the “Committee”) has approved
the performance metrics that will be used to determine the amount of the awards
under AEP’s Senior Officer Incentive Plan (the “SOIP”) for 2005 for AEP’s
executive officers. The performance metrics are based on safety performance,
workforce development, strategic planning, and environmental stewardship. The
overall funding level for all of AEP's incentive plans, including the SOIP, will
be based on the extent to which AEP’s earnings per share improves over the prior
year and meets or exceeds the 2005 budget approved by AEP’s Board of Directors.
However, this overall funding level may be reduced at the discretion of the CEO
or adjusted, either positively or negatively, at the discretion of the
Committee.




The
Committee also set the 2005 annual incentive award targets, expressed as a
percentage of salary, under the SOIP for AEP’s executive officers. Payouts of
annual incentive awards are dependent on the level of achievement of the
corporate financial and operational goals approved by the Committee and
discussed above. Target
annual incentive awards were set at 100 percent of salary for the CEO, 65
percent of salary for the CFO, and either 50 or 60 percent of salary for the
remaining executive officers of AEP.




Individual
awards recommendations for executive officers, other than for Mr. Morris, are
determined on a discretionary basis by Mr. Morris and are subject to the
approval of the Committee. The individual award recommendation for Mr. Morris is
determined on a discretionary basis by the Committee and is subject to the
approval of the independent members of AEP’s Board of Directors.





On
January 25, 2005, the independent members of the AEP Board of Directors set the
2005 annual base salary for Michael G. Morris at $1,150,000. On January 25,
2005, the Committee set the 2005 annual base salaries for Susan Tomasky at
$500,000; Thomas M. Hagan at $440,000; Holly K. Koeppel at $440,000; and Robert
P. Powers at $450,000. Each of these individuals is an AEP named executive
officer for 2004. For further information regarding executive compensation, see
“Item 11. Executive Compensation” herein.








**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 2005 annual meeting of shareholders,
to be filed within 120 days after December 31, 2004. 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 2005 annual meeting of
stockholders, to be filed within 120 days after December 31, 2004. Reference
also is made to the information under the caption *Executive
Officers of the Registrants* in Part I
of this report.





**I&M,
SWEPCo and TCC** . The
names of the directors and executive officers of I&M, SWEPCo and TCC, the
positions they hold with I&M, SWEPCo and TCC, their ages as of March 1,
2005, and a brief account of their business experience during the past five
years appear below or under the caption *Executive
Officers of the Registrants* in Part I
of this report.







**I&M:****Name**
    
    **Age**
    
    **Position**
    
    **Period**K.
      G. Boyd
    
    53
    
    Director
    
    1997-PresentVice
      President-Fort Wayne Region
    
    2000-PresentDistribution
      OperationsIndiana
      Region Manager
    
    1997-2000John
      E. Ehler
    
    48
    
    Director
    
    2001-PresentManager
      of Distribution Systems-Fort Wayne District
    
    2000-PresentRegion
      Operations Manager
    
    1997-2000Patrick
      C. Hale
    
    50
    
    Director
    
    2003-PresentPlant
      Manager, Rockport Plant
    
    2003-PresentEnergy
      Production Manager, Rockport Plant
    
    2001-2003Energy
      Production Manager, Mountaineer Plant (APCo)
    
    1997-2001David
      L. Lahrman
    
    53
    
    Director
      and Manager, Region Support
    
    2001-PresentFort
      Wayne District Manager
    
    1997-2001Marc
      E. Lewis
    
    50
    
    Director
    
    2001-PresentAssistant
      General Counsel of AEPSC
    
    2001-PresentSenior
      Counsel of AEPSC
    
    2000-2001Senior
      Attorney of AEPSC
    
    1994-2000Susanne
      M. Moorman Rowe
    
    55
    
    Director
      and General Manager, Corporate Communications
    
    2004-PresentDirector
      and General Manager, Community Services
    
    2000-2004Manager,
      Customer Services Operations
    
    1997-2000Venita
      McCellon-Allen(a)
    
    45
    
    Director
      and Senior Vice President-Shared Services of AEPSC
    
    2004-PresentDirector
      of APCo, I&M, OPCo, SWEPCo and TCC
    
    2004-PresentSenior
      Vice President-Human Resources for Baylor Health Care
    System
    
    2000-2004Senior
      Vice President-Customer Services and Corporate Development of
      CSW
    
    1996-2000John
      R. Sampson
    
    52
    
    Director
      and Vice President
    
    1999-PresentIndiana
      State President
    
    2000-2004Indiana
      & Michigan State President
    
    1999-2000Site
      Vice President, Cook Nuclear Plant
    
    1998-1999








**SWEPCo
      and TCC:****Name**
    
    **Age**
    
    **Position**
    
    **Period**Venita
      McCellon-Allen (a)
    
    45
    
    Director
      and Senior Vice President-Shared Services of AEPSC
    
    2004-PresentDirector
      of APCo, I&M, OPCo, SWEPCo and TCC
    
    2004-PresentSenior
      Vice President-Human Resources for Baylor Health Care
    Systems
    
    2000-2004Senior
      Vice President-Customer Services and Corporate Development of
      CSW
    
    1996-2000Stephen
      P. Smith (b)
    
    44
    
    Senior
      Vice President and Treasurer of AEP
    
    2004-PresentSenior
      Vice President-Corporate Accounting, Planning & Strategy, Treasurer
      and Director of AEPSC
    
    2003-PresentTreasurer
      of APCo, I&M, OPCo, SWEPCo and TCC
    
    2003-PresentVice
      President and Director of APCo, I&M, OPCo, SWEPCo and
    TCC
    
    2004-PresentPresident
      and Chief Operating Officer-Corporate Services for
NiSource
    
    1999-2003





(a)  Ms.
McCellon-Allen is a director of CSPCo, KPCo, PSO and TNC.





(b)  Mr. Smith
is a director of AEGCo, CSPCo, KPCo, PSO and TNC.











**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 2005 annual
meeting of shareholders to be filed within 120 days after December 31,
2004.





**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 2005 annual meeting of
stockholders, to be filed within 120 days after December 31, 2004.





**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 2005 annual meeting of
stockholders, to be filed within 120 days after December 31, 2004.





**ITEM
12.**  **SECURITY OWNERSHIPOF CERTAIN**


**BENEFICIAL
OWNERS AND MANAGEMENT**





**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 2005 annual meeting of shareholders to
be filed within 120 days after December 31, 2004.





**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 2005 annual meeting of
stockholders, to be filed within 120 days after December 31, 2004.





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





The table
below shows the number of shares of AEP Common Stock and stock-based units that
were beneficially owned, directly or indirectly, as of January 1, 2005, 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.





**Name**
    
    **Shares
      (a)**
    
    **Stock**
      **Units
      (b)**
    
    **Total**Karl
      G. Boyd
    
    12,805
    
    
    253
    
    13,058John
      E. Ehler
    
    —
    
    
    —
    
    —Carl
      L. English
    
    —
    
    
    30,632
    
    30,632Patrick
      C. Hale
    
    3,342
    
    
    —
    
    3,342Holly
      K. Koeppel
    
    61,612
    
    
    380
    
    61,992David
      L. Lahrman
    
    276
    
    
    —
    
    276Marc
      E. Lewis
    
    9,859
    
    
    —
    
    9,859Venita
      McCellon-Allen
    
    —
    
    
    10,103
    
    10,103Suzanne
      M. Moorman Rowe
    
    42
    
    
    —
    
    42Michael
      G. Morris
    
    360,587
    (e)
    
    —
    
    360,587Robert
      P. Powers
    
    200,957
    (c)
    
    1,345
    
    202,302Marsha
      P. Ryan
    
    32,565
    
    
    1,047
    
    33,612John
      R. Sampson
    
    18,634
    
    
    —
    
    18,634Susan
      Tomasky
    
    240,334
    (c)
    
    6,744
    
    247,078**All Directors and**
      **Executive Officers**
    
    1,026,244
    (c)(d)
    
    50,504
    
    1,076,748






**AEP
      Retirement Savings Plan****Name**
    **(Share
      Equivalents)**Karl
      G. Boyd
    100John
      E. Ehler
    —Carl
      L. English
    —Patrick
      C. Hale
    76Holly
      K. Koeppel
    246David
      L. Lahrman
    276Marc
      E. Lewis
    1,410Venita
      McCellon-Allen
    —Marsha
      P. Ryan
    6,189Suzanne
      M. Moorman Rowe
    42Michael
      G. Morris
    —Robert
      P. Powers
    658John
      R. Sampson
    934Susan
      Tomasky
    2,668**All
      Directors and**
      **Executive
      Officers**
    12,598





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, 12,700; Mr. Hale,
3,266; Ms. Koeppel, 61,366; Mr. Lewis, 8,449; Mr. Powers, 200,299; Ms. Ryan,
26,366; Mr. Sampson, 17,700; and Ms. Tomasky, 237,666.







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


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


(c)
    Does
      not include, for Ms. Tomasky and Mr. Powers, 85,231 shares in the American
      Electric Power System Educational Trust Fund over which Ms. Tomasky and
      Mr. Powers 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.


(d)
    Represents
      less than 1.5% of the total number of shares
outstanding.


(e)  Consists
of restricted shares with different vesting schedules and accrued
dividends.





**SWEPCo.** All
7,536,640 outstanding shares of Common Stock, $18 par value, of SWEPCo are
directly and beneficially held by AEP. Holders of the Cumulative Preferred Stock
of SWEPCo generally have no voting rights, except with respect to certain
corporate actions and in the event of certain defaults in the payment of
dividends on such shares.





The table
below shows the number of shares of AEP Common Stock and stock-based units that
were beneficially owned, directly or indirectly, as of January 1, 2005, by each
director and nominee of SWEPCo and each of the executive officers of SWEPCo
named in the summary compensation table, and by all directors and executive
officers of SWEPCo as a group. It is based on information provided to SWEPCo by
such persons. No such person owns any shares of any series of the Cumulative
Preferred Stock of SWEPCo. 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.





**Name**
    
    **Shares
      (a)**
    
    **Stock**
      **Units
      (b)**
    
    **Total**Nicholas
      K. Akins
    
    13,877
    
    
    —
    
    13,877Carl
      L. English
    
    —
    
    
    30,632
    
    30,632Thomas
      M. Hagan
    
    144,529
    
    
    155
    
    144,684John
      B. Keane
    
    —
    
    
    15,316
    
    15,316Holly
      K. Koeppel
    
    61,612
    
    
    380
    
    61,992Venita
      McCellon-Allen
    
    —
    
    
    10,103
    
    10,103Michael
      G. Morris
    
    360,587
    (e)
    
    —
    
    360,587Robert
      P. Powers
    
    200,957
    (c)
    
    1,345
    
    202,302Stephen
      P. Smith
    
    16,500
    
    
    —
    
    16,500Susan
      Tomasky
    
    240,334
    (c)
    
    6,744
    
    247,078**All Directors and**
      **Executive Officers**
    
    1,123,
      627
    (c)(d)
    
    64,675
    
    1,188,302








**AEP
      Retirement Savings Plan****Name**
    **(Share
      Equivalents)**Nicholas K. Akins
    1,177Carl L. English
    —Thomas M. Hagan
    4,537John B. Keane
    —Holly K. Koeppel
    246Venita McCellon-Allen
    —Michael G. Morris
    —Robert P. Powers
    658Stephen P. Smith
    —Susan Tomasky
    2,668**All Directors and**
      **Executive Officers**
    9,286





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. Akins, 12,700; Mr.
Hagan, 129,499; Ms. Koeppel, 61,367; Mr. Morris, 49,666; Mr. Powers, 200,299;
Mr. Smith, 16,500; and Ms. Tomasky, 237,666.







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


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


(c)
    Does
      not include, for Ms. Tomasky and Mr. Powers, 85,231 shares in the American
      Electric Power System Educational Trust Fund over which Ms. Tomasky and
      Mr. Powers 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.


(d)
    Represents
      less than 1.5% of the total number of shares
outstanding.


(e)  Consists
of restricted shares with different vesting schedules and accrued
dividends.





**TCC.** All
2,211,678 outstanding shares of Common Stock, $25 par value, of TCC are directly
and beneficially held by AEP. Holders of the Cumulative Preferred Stock of TCC
generally have no voting rights, except with respect to certain corporate
actions and in the event of certain defaults in the payment of dividends on such
shares.





The table
below shows the number of shares of AEP Common Stock and stock-based units that
were beneficially owned, directly or indirectly, as of January 1, 2005, by each
director and nominee of TCC and each of the executive officers of TCC named in
the summary compensation table, and by all directors and executive officers of
TCC as a group. It is based on information provided to TCC by such persons. No
such person owns any shares of any series of the Cumulative Preferred Stock of
TCC. 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.








**Name**
    
    **Shares
      (a)**
    
    **Stock**
      **Units
      (b)**
    
    **Total**Carl
      L. English
    
    30,632
    
    
    —
    
    30,632Thomas
      M. Hagan
    
    144,529
    
    
    155
    
    144,684John
      B. Keane
    
    —
    
    
    15,316
    
    15,316Holly
      K. Koeppel
    
    61,612
    
    
    380
    
    61,992Venita
      McCellon-Allen
    
    —
    
    
    10,103
    
    10,103Michael
      G. Morris
    
    360,587
    (e)
    
    —
    
    360,587Charles
      R. Patton
    
    7,400
    
    
    —
    
    7,400Robert
      P. Powers
    
    200,957
    (c)
    
    1,345
    
    202,302Stephen
      P. Smith
    
    16,500
    
    
    —
    
    16,500Susan
      Tomasky
    
    240,334
    (c)
    
    6,744
    
    247,078**All Directors and**
      **Executive Officers**
    
    1,147,782
    (c)(d)
    
    34,043
    
    1,181,825








**AEP
      Retirement Savings Plan****Name**
    **(Share
      Equivalents)**Carl
      L. English
    —Thomas
      M. Hagan
    4,537John
      B. Keane
    —Holly
      K. Koeppel
    246Venita
      McCellon-Allen
    —Michael
      G. Morris
    —Charles
      R. Patton
    —Robert
      P. Powers
    658Stephen
      P. Smith
    —Susan
      Tomasky
    2,668**All
      Directors and**
      **Executive
      Officers**
    8,109





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. Hagan, 129,499; Ms.
Koeppel, 61,367; Mr. Morris, 49,666; Mr. Patton, 7,400; Mr. Powers, 200,299; Mr.
Smith, 16,500; and Ms. Tomasky, 237,666.







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


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


(c)
    Does
      not include, for Ms. Tomasky and Mr. Powers, 85,231 shares in the American
      Electric Power System Educational Trust Fund over which Ms. Tomasky and
      Mr. Powers 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.


(d)
    Represents
      less than 1.5% of the total number of shares
outstanding.


(e)
    Consists
      of restricted shares with different vesting schedules and accrued
      dividends.





**EQUITY COMPENSATION PLAN
INFORMATION**





Information
required by this item is incorporated by reference from the discussion under the
heading *Equity
Compensation Plan Information* in our
proxy statement for the 2005 Annual Meeting of Shareholders.








**ITEM
13.**  **CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS**





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








**ITEM
14.**  **PRINCIPAL ACCOUNTING FEES AND
SERVICES**





**AEP** . The
information required by this item is incorporated herein by reference to the
definitive proxy statement of AEP for the 2005 annual meeting of shareholders to
be filed within 120 days after December 31, 2004.





**APCo
and OPCo** . The
information required by this item is incorporated herein by reference to the
definitive information statement of each company for the 2005 annual meeting of
stockholders, to be filed within 120 days after December 31, 2004.





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





Each of
the above is 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 2005 annual meeting of shareholders to be filed within 120 days after
December 31, 2004. The following table presents directly billed fees for
professional services rendered by Deloitte & Touche LLP for the audit of
these companies’ annual financial statements for the years ended December 31,
2003 and 2004, and fees directly billed for other services rendered by Deloitte
& Touche LLP during those periods. Deloitte & Touche LLP also provides
additional professional and other services to the AEP System, the cost of which
may ultimately be allocated to these companies though not billed directly to
them. For a description of these fees and services, see the definitive proxy
statement of AEP for the 2005 annual meeting of shareholders to be filed within
120 days after December 31, 2004.


****
    
    **AEGCo**
    **CSPCo**
    **I&M**2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003**Audit
      Fees**Financial
      Statement Audits
    
    $
    164,303
    
    
    
    
    $
    608,935
    
    
    
    
    $
    679,061Sarbanes-Oxley
      404
    
    
    112,341
    
    
    
    
    
    518,610
    
    
    
    
    
    490,537Audit
      Fees - Other
    
    
    19,530
    
    
    
    
    
    57,660
    
    
    
    
    
    49,290***Audit
      Fees Subtotal***
    
    
    296,174
    
    $
    136,100
    
    
    1,185,205
    
    $
    385,000
    
    
    1,218,888
    
    $
    366,900**Audit-Related
      Fees**
    
    
    0
    
    
    0
    
    
    5,000
    
    
    0
    
    
    184,000
    
    
    0**Tax
      Fees**
    
    
    67,539
    
    
    1,000
    
    
    888,188
    
    
    349,000
    
    
    1,136,796
    
    
    26,000**TOTAL**
    
    $
    363,713
    
    $
    137,100
    
    $
    2,078,393
    
    $
    734,000
    
    $
    2,539,684
    
    $
    392,900
  
 **KPCo**
    **PSO**
    **SWEPCo**2004
    
    
    2003
    
    
    2004
    
    
    2003
    
    
    2004
    
    
    2003**Audit
      Fees**Financial
      Statement Audits
    
    $
    413,013
    
    
    
    
    $
    357,053
    
    
    
    
    $
    411,970Sarbanes-Oxley
      404
    
    
    284,581
    
    
    
    
    
    273,793
    
    
    
    
    
    318,007Audit
      Fees - Other
    
    
    36,270
    
    
    
    
    
    24,180
    
    
    
    
    
    27,900***Audit
      Fees Subtotal***
    
    
    733,864
    
    $
    289,000
    
    
    655,026
    
    $
    187,300
    
    
    757,877
    
    $
    212,900**Audit-Related
      Fees**
    
    
    0
    
    
    0
    
    
    
    
    
    
    
    
    10,000
    
    
    0**Tax
      Fees**
    
    
    81,412
    
    
    8,000
    
    
    438,845
    
    
    35,000
    
    
    567,665
    
    
    89,000**TOTAL**
    
    $
    815,276
    
    $
    297,000
    
    $
    1,093,871
    
    $
    222,300
    
    $
    1,335,542
    
    $
    301,900
   **TCC**
    **TNC**2004
    
    
    2003
    
    
    2004
    
    
    2003**Audit
      Fees**Financial
      Statement Audits
    
    $
    446,899
    
    
    
    
    $
    159,950Sarbanes-Oxley
      404
    
    
    357,257
    
    
    
    
    
    188,080Audit
      Fees - Other
    
    
    46,500
    
    
    
    
    
    26,040***Audit
      Fees Subtotal***
    
    
    850,656
    
    $
    511,000
    
    
    374,070
    
    $
    188,900**Audit-Related
      Fees**
    
    
    21,500
    
    
    
    
    
    8,325**Tax
      Fees**
    
    
    896,577
    
    
    89,000
    
    
    235,477
    
    
    54,000**TOTAL**
    
    $
    1,768,733
    
    $
    600,000
    
    $
    617,872
    
    $
    242,900








**PART IV**





ITEM 15.  EXHIBITS, FINANCIALSTATEMENT SCHEDULES.





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





**Page****1.****Financial
      Statements:**The
      following financial statements have been incorporated herein by reference
      pursuant to Item 8.**AEGCo:**Statements
      of Income for the years ended December 31, 2004, 2003 and 2002; Statements
      of Retained Earnings for the years ended December 31, 2004, 2003 and 2002;
      Balance Sheets as of December 31, 2004 and 2003; Statements of Cash Flows
      for the years ended December 31, 2004, 2003 and 2002; Schedule of
      Long-term Debt as of December 31, 2004 and 2003; Notes to Financial
      Statements of Registrant Subsidiaries; Report of Independent Registered
      Public Accounting Firm.**AEP
      and Subsidiary Companies:**Reports
      of Independent Registered Public Accounting Firm; Management’s Report on
      Internal Control over Financial Reporting; Consolidated Statements of
      Operations for the years ended December 31, 2004, 2003 and 2002;
      Consolidated Balance Sheets as of December 31, 2004 and 2003; Consolidated
      Statements of Cash Flows for the years ended December 31, 2004, 2003 and
      2002; Consolidated Statements of Common Shareholders’ Equity and
      Comprehensive Income (Loss) for the years ended December 31, 2004, 2003
      and 2002; Schedule of Consolidated Cumulative Preferred Stocks of
      Subsidiaries at December 31, 2004 and 2003; Schedule of Consolidated
      Long-term Debt of Subsidiaries at December 31, 2004 and 2003; Notes to
      Consolidated Financial Statements.**APCo,
      I&M, SWEPCo and TCC:**Consolidated
      Statements of Income for the years ended December 31, 2004, 2003 and 2002;
      Consolidated Statements of Changes in Common Shareholder’s Equity and
      Comprehensive Income (Loss) for the years ended December 31, 2004, 2003
      and 2002; Consolidated Balance Sheets as of December 31, 2004 and 2003;
      Consolidated Statements of Cash Flows for the years ended December 31,
      2004, 2003 and 2002; Schedule of Preferred Stock as of December 31, 2004
      and 2003; Schedule of Long-term Debt as of December 31, 2004 and 2003;
      Notes to Financial Statements of Registrant Subsidiaries; Report of
      Independent Registered Public Accounting Firm.**CSPCo:**Consolidated
      Statements of Income for the years ended December 31, 2004, 2003 and 2002;
      Consolidated Statements of Changes in Common Shareholder’s Equity and
      Comprehensive Income (Loss) for the years ended December 31, 2004, 2003
      and 2002; Consolidated Balance Sheets as of December 31, 2004 and 2003;
      Consolidated Statements of Cash Flows for the years ended December 31,
      2004, 2003 and 2002; Schedule of Long-term Debt as of December 31, 2004
      and 2003; notes to Financial Statements of Registrant Subsidiaries; Report
      of Independent Registered Public Accounting Firm.**KPCo:**Statements
      of Income for the years ended December 31, 2004, 2003 and 2002; Statements
      of Changes in Common Shareholder’s Equity and Comprehensive Income (Loss)
      for the years ended December 31, 2004, 2003 and 2002; Balance Sheets as of
      December 31, 2004 and 2003; Statements of Cash Flows for the years ended
      December 31, 2004, 2003 and 2002; Schedule of Long-term Debt as of
      December 31, 2004 and 2003; Notes to Financial Statements of Registrant
      Subsidiaries; Report of Independent Registered Public Accounting Firm.**PSO
      and TNC:**Statements
      of Income (or Statements of Operations) for the years ended December 31,
      2004, 2003 and 2002; Statements of Common Shareholder’s Equity and
      Comprehensive Income (Loss) for the years ended December 31, 2004, 2003
      and 2002; Balance Sheets as of December 31, 2004 and 2003; Statements of
      Cash Flows for the years ended December 31, 2004, 2003 and 2002; Schedules
      of Preferred Stock as of December 31, 2004 and 2003; Schedule of Long-term
      Debt as of December 31, 2004 and 2003; Notes to Financial Statements of
      Registrant Subsidiaries; Report of Independent Registered Public
      Accounting Firm.**2.****Financial
      Statement Schedules:**Financial
      Statement Schedules are listed in the Index to Financial Statement
      Schedules (Certain schedules have been omitted because the required
      information is contained in the notes to financial statements or because
      such schedules are not required or are not applicable). Report of
      Independent Registered Public Accounting Firm**3.****Exhibits:**Exhibits
      for AEGCo, AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are listed in the Exhibit Index beginning on page
      E-1 and are incorporated herein by reference














**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, Executive Vice President****and
      Chief Financial Officer)**





Date:
March 1, 2005





**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.**





**Signature**
    
    **Title**
    
    **Date****(i)****Principal
      Executive Officer:***Michael
      G. Morris
    
    Chairman
      of the Board, President,
    
    March
      1, 2005Chief
      Executive OfficerAnd
      Director**(ii)****Principal
      Financial Officer:**/s/Susan
      Tomasky
    
    Executive
      Vice President and
    
    March
      1, 2005**(Susan
      Tomasky)**
    
    Chief
      Financial Officer**(iii)****Principal
      Accounting Officer:**/s/Joseph
      M. Buonaiuto
    
    Senior
      Vice President, Controller and
    
    March
      1, 2005**(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*Lionel
      L. Nowell, III*Richard
      L. Sandor*Donald
      G. Smith*Kathryn
      D. Sullivan





*By:
    /s/Susan
      Tomasky
    
    
    
    March
      1, 2005**(Susan
      Tomasky, Attorney-in-Fact)**














**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








By:
    /s/Susan
      Tomasky(Susan
      Tomasky, Vice President
      and
      Chief Financial Officer)





Date:
March 1, 2005





**Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.**





**Signature**
    
    **Title**
    
    **Date****(i)****Principal
      Executive Officer:***Michael
      G. Morris
    
    Chairman
      of the Board,
    
    March
      1, 2005Chief
      Executive Officer and Director**(ii)****Principal
      Financial Officer:**/s/Susan
      Tomasky
    
    Vice
      President,
    
    March
      1, 2005**(Susan
      Tomasky)**
    
    Chief
      Financial Officer and Director**(iii)****Principal
      Accounting Officer:**/s/Joseph
      M. Buonaiuto
    
    Controller
      and
    
    March
      1, 2005**(Joseph
      M. Buonaiuto)**
    
    Chief
      Accounting Officer**(iv)****A
      Majority of the Directors:***
      THOMAS M. HAGAN*
      JOHN B. KEANE*ROBERT
      P. POWERS*STEPHEN
      P. SMITH





*By:
    /s/Susan
      Tomasky
    
    
    
    March
      1, 2005**(Susan
      Tomasky, Attorney-in-Fact)**














**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
      Texas Central CompanyAEP
      Texas North CompanyPublic
      Service Company of OklahomaSouthwestern
      Electric Power Company








By:
    /s/Susan
      Tomasky**(Susan
      Tomasky, Vice President**
      **and
      Chief Financial Officer)**





Date:
March 1, 2005





**Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.**





**Signature**
    
    **Title**
    
    **Date****(i)****Principal
      Executive Officer:***Michael
      G. Morris
    
    Chairman
      of the Board,
    
    March
      1, 2005Chief
      Executive Officer and Director**(ii)****Principal
      Financial Officer:**/s/Susan
      Tomasky
    
    Vice
      President,
    
    March
      1, 2005**(Susan
      Tomasky)**
    
    Chief
      Financial Officer and Director**(iii)****Principal
      Accounting Officer:**/s/Joseph
      M. Buonaiuto
    
    Controller
      and
    
    March
      1, 2005**(Joseph
      M. Buonaiuto)**
    
    Chief
      Accounting Officer**(iv)****A
      Majority of the Directors:***Carl
      L. English*thomas
      M. Hagan*John
      B. Keane*Venita
      McCellon-Allen*Robert
      P. Powers*Stephen
      P. Smith





*By:
    /s/Susan
      Tomasky
    
    
    
    March
      1, 2005**(Susan
      Tomasky, Attorney-in-Fact)**











**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.**





Appalachian
      Power CompanyColumbus
      Southern Power CompanyKentucky
      Power CompanyOhio
      Power Company








By:
    /s/Susan
      Tomasky**(Susan
      Tomasky, Vice President**
      **and
      Chief Financial Officer)**





Date:
March 1, 2005





**Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.**





**Signature**
    
    **Title**
    
    **Date****(i)****Principal
      Executive Officer:***Michael
      G. Morris
    
    Chairman
      of the Board,
    
    March
      1, 2005Chief
      Executive Officer and Director**(ii)****Principal
      Financial Officer:**/s/Susan
      Tomasky
    
    Vice
      President,
    
    March
      1, 2005**(Susan
      Tomasky)**
    
    Chief
      Financial Officer and Director**(iii)****Principal
      Accounting Officer:**/s/Joseph
      M. Buonaiuto
    
    Controller
      and
    
    March
      1, 2005**(Joseph
      M. Buonaiuto)**
    
    Chief
      Accounting Officer**(iv)****A
      Majority of the Directors:***Carl
      L. English*John
      B. Keane*Holly
      K. Koeppel*Venita
      McCellon-Allen*Robert
      P. Powers*Stephen
      P. Smith





*By:
    /s/Susan
      Tomasky
    
    
    
    March
      1, 2005**(Susan
      Tomasky, Attorney-in-Fact)**














**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
      and
      Chief Financial Officer)





Date:
March 1, 2005





**Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the above-named
company and any subsidiaries thereof.**





**Signature**
    
    **Title**
    
    **Date****(i)****Principal
      Executive Officer:***Michael
      G. Morris
    
    Chairman
      of the Board,
    
    March 1,
      2005Chief
      Executive Officer and Director**(ii)****Principal
      Financial Officer:**/s/Susan
      Tomasky
    
    Vice
      President,
    
    March
      1, 2005**(Susan
      Tomasky)**
    
    Chief
      Financial Officer and Director**(iii)****Principal
      Accounting Officer:**/s/Joseph
      M. Buonaiuto
    
    Controller
      and
    
    March
      1, 2005**(Joseph
      M. Buonaiuto)**
    
    Chief
      Accounting Officer**(iv)****A
      Majority of the Directors:***K.
      G. Boyd*John
      E. Ehler*Carl
      L. English*Patrick
      C. Hale*Holly
      Keller Koeppel*David
      L. Lahrman*Marc
      E. Lewis*Venita
      McCellon-Allen*Susanne
      M. Moorman Rowe*Robert
      P. Powers*John
      R. Sampson





*By:
    /s/Susan
      Tomasky
    
    
    
    March
      1, 2005**(Susan
      Tomasky, Attorney-in-Fact)**






















**INDEX TO FINANCIALSTATEMENT
SCHEDULES**








****
    ***Page***REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe
      following financial statement schedules are included in this report on the
      pages indicated:AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
      Schedule
      II — Valuation and Qualifying Accounts and ReservesAEP
      TEXAS CENTRAL COMPANY AND SUBSIDIARY
      Schedule
      II — Valuation and Qualifying Accounts and ReservesAEP
      TEXAS NORTH COMPANY
      Schedule
      II — Valuation and Qualifying Accounts and ReservesAPPALACHIAN
      POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and ReservesCOLUMBUS
      SOUTHERN POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and ReservesINDIANA
      MICHIGAN POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and ReservesKENTUCKY
      POWER COMPANY
      Schedule
      II — Valuation and Qualifying Accounts and ReservesOHIO
      POWER COMPANY CONSOLIDATED
      Schedule
      II — Valuation and Qualifying Accounts and ReservesPUBLIC
      SERVICE COMPANY OF OKLAHOMA
      Schedule
      II — Valuation and Qualifying Accounts and ReservesSOUTHWESTERN
      ELECTRIC POWER COMPANY CONSOLIDATED
      Schedule
      II — Valuation and Qualifying Accounts and Reserves


















**REPORT OF INDEPENDENTREGISTERED PUBLIC ACCOUNTING
FIRM**






We have
audited the consolidated financial statements of American Electric Power
Company, Inc. and subsidiary companies (the “Company”) as of December 31, 2004
and 2003, and for each of the three years in the period ended December 31, 2004,
management’s assessment of the effectiveness of the Company’s internal control
over financial reporting as of December 31, 2004, and the effectiveness of the
Company’s internal control over financial reporting as of December 31, 2004, and
have issued our reports thereon dated February 28, 2005 (which reports express
unqualified opinions and include an explanatory paragraph concerning the
adoption of new accounting pronouncements in 2002, 2003 and 2004); such
financial statements and reports are included in your 2004 Annual Report and are
incorporated herein by reference.  Our audits also included the financial
statement schedule of the Company listed in Item 15.  This consolidated
financial statement schedule is the responsibility of the Company’s
management.  Our responsibility is to express an opinion based on our
audits.  In our opinion, such consolidated financial statement schedule,
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


February
28, 2005








**REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**






We have
audited the financial statements of the AEP Texas Central Company and
subsidiary, AEP Texas North Company, Appalachian Power Company and subsidiaries,
Columbus Southern Power Company and subsidiaries, Indiana Michigan Power Company
and subsidiaries, Kentucky Power Company, Ohio Power Company Consolidated,
Public Service Company of Oklahoma and Southwestern Electric Power Company
Consolidated (collectively, the “Companies”) as of December 31, 2004 and 2003,
and for each of the three years in the period ended December 31, 2004, and have
issued our reports thereon dated February 28, 2005 (which reports express
unqualified opinions and include an explanatory paragraph concerning the
adoption of new accounting pronouncements in 2002, 2003 and 2004); such
financial statements and reports are included in your 2004 Annual Reports and
are incorporated herein by reference.  Our audits also included the
financial statement schedules of the ** Companies
listed in Item 15.  These financial statement schedules are the
responsibility of the Companies’ 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 basic financial
statements taken as a whole, present fairly, in all material respects, the
information set forth therein.




*/s/
Deloitte & Touche, LLP*




Columbus,
Ohio


February
28, 2005












**INDEX
TO FINANCIAL STATEMENT SCHEDULES**
 
 
 ****
    **Page**INDEPENDENT
      AUDITORS’ REPORT
    S-2The
      following financial statement schedules are included in this report on the
      pages indicated
      AMERICAN
      ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-3AEP
      TEXAS CENTRAL COMPANY AND SUBSIDIARY
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-3AEP
      TEXAS NORTH COMPANY
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-3APPALACHIAN
      POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-4COLUMBUS
      SOUTHERN POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-4INDIANA
      MICHIGAN POWER COMPANY AND SUBSIDIARIES
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-4KENTUCKY
      POWER COMPANY
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-5OHIO
      POWER COMPANY CONSOLIDATED
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-5PUBLIC
      SERVICE COMPANY OF OKLAHOMA
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-5SOUTHWESTERN
      ELECTRIC POWER COMPANY CONSOLIDATED
      Schedule
      II — Valuation and Qualifying Accounts and Reserves
    S-6
 
   
   **AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    123,685
    
    $
    39,766
    
    $
    7,989
    
    $
    94,265
    
    $
    77,175Year
      Ended December 31, 2003
    
    
    107,578
    
    
    55,087
    
    
    7,234
    
    
    46,214
    
    
    123,685Year
      Ended December 31, 2002
    
    
    68,429
    
    
    87,044
    
    
    11,767
    
    
    59,662
    
    
    107,578(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
 
 
 **AEP
TEXAS CENTRAL COMPANY AND SUBSIDIARY**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    1,710
    
    $
    3,493
    
    $
    -
    
    $
    1,710
    
    $
    3,493Year
      Ended December 31, 2003
    
    
    346
    
    
    1,712
    
    
    -
    
    
    348
    
    
    1,710Year
      Ended December 31, 2002
    
    
    186
    
    
    162
    
    
    1
    
    
    3
    
    
    346(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
 
 
 
 **AEP
TEXAS NORTH COMPANY**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    175
    
    $
    787
    
    $
    -
    
    $
    175
    
    $
    787Year
      Ended December 31, 2003
    
    
    5,041
    
    
    123
    
    
    -
    
    
    4,989
    
    
    175Year
      Ended December 31, 2002
    
    
    196
    
    
    4,846
    
    
    17
    
    
    18
    
    
    5,041(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
 
 
 **APPALACHIAN
POWER COMPANY AND SUBSIDIARIES**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    2,085
    
    $
    3,059
    
    $
    4,201
    
    $
    3,784
    
    $
    5,561Year
      Ended December 31, 2003
    
    
    13,439
    
    
    4,708
    
    
    433
    
    
    16,495
    
    
    2,085Year
      Ended December 31, 2002
    
    
    1,877
    
    
    3,937
    
    
    12,367
    
    
    4,742
    
    
    13,439(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**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    531
    
    $
    577
    
    $
    187
    
    $
    621
    
    $
    674Year
      Ended December 31, 2003
    
    
    634
    
    
    96
    
    
    -
    
    
    199
    
    
    531Year
      Ended December 31, 2002
    
    
    745
    
    
    (100
    )
    
    -
    
    
    11
    
    
    634(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**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    531
    
    $
    195
    
    $
    90
    
    $
    629
    
    $
    187Year
      Ended December 31, 2003
    
    
    578
    
    
    37
    
    
    -
    
    
    84
    
    
    531Year
      Ended December 31, 2002
    
    
    741
    
    
    (161
    )
    
    -
    
    
    2
    
    
    578(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
 
  **KENTUCKY
POWER COMPANY**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    736
    
    $
    43
    
    $
    27
    
    $
    772
    
    $
    34Year
      Ended December 31, 2003
    
    
    192
    
    
    8
    
    
    912
    
    
    376
    
    
    736Year
      Ended December 31, 2002
    
    
    264
    
    
    (68
    )
    
    -
    
    
    4
    
    
    192(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
 
 **OHIO
POWER COMPANY CONSOLIDATED**
 **SCHEDULE
II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    789
    
    $
    122
    
    $
    89
    
    $
    907
    
    $
    93Year
      Ended December 31, 2003
    
    
    909
    
    
    42
    
    
    18
    
    
    180
    
    
    789Year
      Ended December 31, 2002
    
    
    1,379
    
    
    (457
    )
    
    -
    
    
    13
    
    
    909(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**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    37
    
    $
    21
    
    $
    55
    
    $
    37
    
    $
    76Year
      Ended December 31, 2003
    
    
    84
    
    
    37
    
    
    -
    
    
    84
    
    
    37Year
      Ended December 31, 2002
    
    
    44
    
    
    7
    
    
    33
    
    
    -
    
    
    84(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**
 
 **Column
      A**
    
    **Column
      B**
    
    **Column
      C**
    
    **Column
      D**
    
    **Column
      E****Additions****Description**
    
    **Balance
      at Beginning of Period**
    
    **Charged
      to Costs and Expenses**
    
    **Charged
      to Other**
      **Accounts
      (a)**
    
    **Deductions
      (b)**
    
    **Balance
      at**
      **End
      of**
      **Period****(in
      thousands)****Deducted
      from Assets:**Accumulated
      Provision forUncollectible
      Accounts:Year
      Ended December 31, 2004
    
    $
    2,093
    
    $
    (2,079
    )
    $
    134
    
    $
    103
    
    $
    45Year
      Ended December 31, 2003
    
    
    2,128
    
    
    103
    
    
    -
    
    
    138
    
    
    2,093Year
      Ended December 31, 2002
    
    
    89
    
    
    2,036
    
    
    4
    
    
    1
    
    
    2,128(a)
      Recoveries on accounts previously written off.(b)
      Uncollectible accounts written off.
















**EXHIBIT INDEX**





The
documents listed below are being filed or have previously been filed on behalf
of the Registrants shown and are incorporated herein by reference to the
documents indicated and made a part hereof. Exhibits (“Ex”) not identified as
previously filed are filed herewith. 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**
      **Designation**
    **Nature
      of Exhibit**
    **Previously
      Filed as Exhibit to:****REGISTRANT:    AEGCo****File No.
      0-18135**3(a)
    Articles
      of Incorporation of AEGCo.
    Registration
      Statement on Form 10 for the Common Shares of AEGCo, Ex
    3(a).3(b)
    Copy
      of the Code of Regulations of AEGCo, amended as of June 15,
      2000.
    2000
      Form 10-K, Ex 3(b).10(a)
    Capital
      Funds Agreement dated as of December 30, 1988 between AEGCo and
      AEP.
    Registration
      Statement No. 33-32752, Ex 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, Ex 28(b)(1)(A)(B).10(b)(2)
    Unit
      Power Agreement, dated as of August 1, 1984, among AEGCo, I&M and
      KPCo.
    Registration
      Statement No. 33-32752, Ex 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, Ex 28(c)(1-6)(C);
      1993
      Form 10-K, Ex 10(c)(1-6)(B).*13
    Copy
      of those portions of the AEGCo 2004 Annual Report, 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.**REGISTRANT:    AEP‡**  **File No.
      1-3525**3(a)
    Composite
      of the Restated Certificate of Incorporation of AEP, dated January 13,
      1999.
    1998
      Form 10-K, Ex 3(c).3(b)
    By-Laws
      of AEP, as amended through December 15, 2003
    2003
      Form 10-K, Ex 3(d).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, Ex 4(a)(b)(c);
      Registration
      Statement No. 333-105532, Ex 4(d)(e)(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
    2002
      Form 10-K, Ex 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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      1990
      Form 10-K, Ex 10(a)(3).10(b)
    Restated
      and Amended Operating Agreement, dated as of January 1, 1998, among PSO,
      TCC, TNC, SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(b).10(c)
    Transmission
      Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
      with AEPSC as agent, as amended.
    1985
      Form 10-K; Ex 10(b)
      1988
      Form 10-K, Ex 10(b)(2).10(d)
    Transmission
      Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC,
      SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(d).*10(e)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(e)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(e)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.10(f)
    Lease
      Agreements, dated as of December 1, 1989, between AEGCo or I&M and
      Wilmington Trust Company, as amended.
    Registration
      Statement No. 33-32752, Ex 28(c)(1-6)(C);
      Registration
      Statement No. 33-32753, Ex 28(a)(1-6)(C);
      **AEGCO**1993 Form 10-K, Ex 10(c)(1-6)(B);
      **I&M**1993 Form 10-K, Ex 10(e)(1-6)(B).10(g)
    Lease
      Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited
      Partnership, and amendment thereto (confidential treatment requested)
    **OPCo**1994 Form 10-K, Ex 10(l)(2).10(h)
    Modification
      No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
      among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
    1996
      Form 10-K, Ex 10(l)10(i)(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
    1997
      Form 10-K, Ex 10(f).10(i)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger
    Form
      8-K, Ex 10, dated December 15, 1999.†10(j)
    AEP
      Accident Coverage Insurance Plan for directors.
    1985
      Form 10-K, Ex 10(g)†10(k)(1)
    AEP
      Deferred Compensation and Stock Plan for Non-Employee Directors, as
      amended December 10, 2003
    2003
      Form 10-K, Ex 10(k)(1)†10(k)(2)
    AEP
      Stock Unit Accumulation Plan for Non-Employee Directors, as amended
      December 10, 2003.
    2003
      Form 10-K, Ex 10(k)(2).†10(l)(1)(A)
    AEP
      System Excess Benefit Plan, Amended and Restated as of January 1,
      2001.
    2000
      Form 10-K, Ex 10(j)(1)(A)†10(l)(1)(B)
    Guaranty
      by AEP of AEPSC Excess Benefits Plan.
    1990
      Form 10-K, Ex 10(h)(1)(B)†10(l)(1)(C)
    First
      Amendment to AEP System Excess Benefit Plan, dated as of March 5,
      2003.
    2002
      Form 10-K; Ex 10(1)(1)(c)†10(l)(2)
    AEP
      System Supplemental Retirement Savings Plan, Amended and Restated as of
      September 1, 2004 (Non-Qualified).
    2003
      Form 10-K, Ex 10(l)(2).
      Form
      8-K, Ex 99.1, dated September 1, 2004,†10(l)(3)
    Service
      Corporation Umbrella Trust for Executives.
    1993
      Form 10-K, Ex 10(g)(3).†10(m)(1)
    Employment
      Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
      2003.
    2003
      Form 10-K, Ex 10(m)(1).†10(m)(2)
    Memorandum
      of agreement between Susan Tomasky and AEPSC dated January 3,
      2001.
    2000
      Form 10-K, Ex 10(s)†10(m)(3)
    Letter
      Agreement dated June 23, 2000 between AEPSC and Holly K.
      Koeppel.
    2002
      Form 10-K; Ex 10(m)(3)(A)†10(m)(4)
    Employment
      Agreement dated July 29, 1998 between AEPSC and Robert P.
      Powers.
    2002
      Form 10-K; Ex 10(m)(4)†10(m)(5)
    Letter
      Agreement dated June 4, 2004 between AEPSC and Carl
English
    Form
      10-Q, Ex 10(b), September 30, 2004†10(n)
    AEP
      System Senior Officer Annual Incentive Compensation Plan.
    1996
      Form 10-K, Ex 10(i)(1)†10(o)(1)
    AEP
      System Survivor Benefit Plan, effective January 27, 1998.
    Form
      10-Q, Ex 10, September 30, 1998†10(o)(2)
    First
      Amendment to AEP System Survivor Benefit Plan, as amended and restated
      effective January 31, 2000.
    2002
      Form 10-K; Ex 10(o)(2)†10(p)
    AEP
      System Incentive Compensation Deferral Plan Amended and Restated as of
      January 1, 2003.
    2003
      Form 10-K, Ex 10(q)(1).†10(q)
    AEP
      System Nuclear Performance Long Term Incentive Compensation Plan dated
      August 1, 1998.
    2002
      Form 10-K, Ex 10(r)†10(r)
    Nuclear
      Key Contributor Retention Plan dated May 1, 2000.
    2002
      Form 10-K; Ex 10(s)†10(s)
    AEP
      Change In Control Agreement effective January 1, 2005.
    Form
      8-K, Ex 10.1, dated January 10, 2005†10(t)(1)
    AEP
      System 2000 Long-Term Incentive Plan, as amended December 10,
      2003.
    2003
      Form 10-K, Ex 10(u).†10(t)(2)
    Form
      of Performance Share Award Agreement furnished to participants of the AEP
      System 2000 Long-Term Incentive Plan, as amended
    Form
      10-Q, Ex. 10(c), September 30, 2004†10(u)(1)
    Central
      and South West System Special Executive Retirement Plan as amended and
      restated effective July 1, 1997.
    **CSW**1998 Form 10-K, Ex 18, File No. 1-1443,†10(u)(2)
    Certified
      AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16,
      1996.
    2003
      Form 10-K, Ex 10(v)(3).†10(u)(3)
    Central
      and South West Corporation Executive Deferred Savings Plan as amended and
      restated effective as of January 1, 1997.
    **CSW**1998 Form 10-K, Ex 24, File No. 1-1443.*†10(v)
    Schedule
      of Non-Employee Directors’ Annual Compensation*†10(w)
    Base
      Salaries for Named Executive Officers*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the AEP 2004 Annual Report (for the fiscal year ended
      December 31, 2004) 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.****
    **REGISTRANT:    APCo‡** **File No.
      1-3457**3(a)
    Composite
      of the Restated Articles of Incorporation of APCo, amended as of March 7,
      1997.
    1996
      Form 10-K, Ex 3(d).3(b)
    By-Laws
      of APCo, amended as of October 24, 2001.
    2001
      Form 10-K, Ex 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, Ex 7(b);
      Registration
      Statement No. 2-19884, Ex 2(1)
      Registration
      Statement No. 2-24453, Ex 2(n);
      Registration
      Statement No. 2-60015, Ex 2(b)(2-10) (12)(14-28);
      Registration
      Statement No. 2-64102, Ex 2(b)(29);
      Registration
      Statement No. 2-66457, Ex (2)(b)(30-31);
      Registration
      Statement No. 2-69217, Ex 2(b)(32);
      Registration
      Statement No. 2-86237, Ex 4(b);
      Registration
      Statement No. 33-11723, Ex 4(b);
      Registration
      Statement No. 33-17003, Ex 4(a)(ii),
      Registration
      Statement No. 33-30964, Ex 4(b);
      Registration
      Statement No. 33-40720, Ex 4(b);
      Registration
      Statement No. 33-45219, Ex 4(b);
      Registration
      Statement No. 33-46128, Ex 4(b)(c);
      Registration
      Statement No. 33-53410, Ex 4(b);
      Registration
      Statement No. 33-59834, Ex 4(b);
      Registration
      Statement No. 33-50229, Ex 4(b)(c);
      Registration
      Statement No. 33-58431, Ex 4(b)(c)(d)(e);
      Registration
      Statement No. 333-01049, Ex 4(b)(c);
      Registration
      Statement No. 333-20305, Ex 4(b)(c);
      1996
      Form 10-K, Ex 4(b);
      1998
      Form 10-K, Ex 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, Ex 4(a);
      Registration
      Statement No. 333-49071, Ex 4(b);
      Registration
      Statement No. 333-84061, Ex 4(b)(c);
      1999 Form 10-K, Ex 4(c);
      Registration
      Statement No. 333-81402, Ex 4(b)(c)(d);
      Registration
      Statement No. 333-100451, Ex 4(b);
      2002 Form 10-K, Ex 4(c).4(c)
    Company
      Order and Officer’s Certificate to The Bank of New York, dated July 1,
      2004, establishing terms of Floating Rate Notes, Series C, due
      2007.
    Form
      8-K, Ex 4(a), dated July 1, 2004.10(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, Ex 5(a);
      Registration
      Statement No. 2-63234, Ex 5(a)(1)(B); Registration Statement No 2-66301,
      Ex 5(a)(1)(C); Registration Statement No. 2-67728, Ex
      5(a)(1)(D);
      1989
      Form 10-K, Ex 10(a)(1)(F);
      1992
      Form 10-K, Ex 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, Ex 5(c);
      Registration
      Statement No. 2-67728, Ex 5(a)(3)(B);
      1992
      Form 10-K, Ex 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, Ex 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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      **AEP**1990 Form 10-K, File No. 1-3525, Ex 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.
    **AEP**1985 Form 10-K, Ex 10(b);
      **AEP**1988 Form 10-K, Ex 10(b)(2).*10(d)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(d)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(d)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.10(e)
    Modification
      No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
      among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
    **AEP**1996 Form 10-K, Ex 10(l), File No. 1-3525.10(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.
    **AEP**1997 Form 10-K, Ex 10(f), File No. 1-3525.10(f)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of
      Merger.
    Form
      8-K, Ex 10, dated December 15, 1999.†10(g)
    AEP
      System Senior Officer Annual Incentive Compensation Plan
    **AEP**1996 Form 10-K, Ex 10(i)(1), File No. 1-3525.†10(h)(1)(A)
    AEP
      System Excess Benefit Plan, Amended and Restated as of January 1,
      2001.
    **AEP**2000 Form 10-K, Ex 10(j)(1)(A), File No. 1-3525.†10(h)(1)(B)
    First
      Amendment to AEP System Excess Benefit Plan, dated as of March 5,
      2003.
    2002
      Form 10-K; Ex 10(h)(1)(B).†10(h)(2)
    AEP
      System Supplemental Retirement Savings Plan, Amended and Restated as of
      September 1, 2004 (Non-Qualified).
    AEP
      Form 8-K, Ex 99.1, dated September 1, 2004†10(h)(3)
    Umbrella
      Trust for Executives.
    **AEP**1993 Form 10-K, Ex 10(g)(3), File No. 1-3525.†10(i)(1)
    Employment
      Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
      2003.
    2003
      Form 10-K, Ex 10(i)(1).†10(i)(2)
    Memorandum
      of Agreement between Susan Tomasky and AEPSC dated January 3,
      2001.
    **AEP**2000 Form 10-K, Ex 10(s), File No. 1-3525.†10(i)(3)
    Employment
      Agreement dated July 29, 1998 between AEPSC and Robert P.
      Powers.
    2002
      Form 10-K; Ex 10(i)(3).†10(i)(4)
    Letter
      Agreement dated June 4, 2004 between AEPSC and Carl
English
    **AEP**Form 10-Q, Ex 10(b), September 30, 2004†10(j)(1)
    AEP
      System Survivor Benefit Plan, effective January 27, 1998.
    **AEP**Form 10-Q, Ex 10, September 30, 1998,
      File
      No. 1-3525.†10(j)(2)
    First
      Amendment to AEP System Survivor Benefit Plan, as amended and restated
      effective January 31, 2000.
    2002
      Form 10-K; Ex 10(j)(2).†10(k)
    AEP
      Change In Control Agreement, effective January 1, 2005.
    **AEP**Form 8-K, Ex 10.1 dated January 10, 2005,
      File
      No. 1-3525.†10(l)(1)
    AEP
      System 2000 Long-Term Incentive Plan, as amended December 10,
      2003.
    2003
      Form 10-K, Ex 10(m).†10(l)(2)
    Form
      of Performance Share Award Agreement furnished to participants of the AEP
      System 2000 Long-Term Incentive Plan, as amended
    **AEP**Form 10-Q, Ex. 10(c), dated November 5, 2004.†10(m)(1)
    Central
      and South West System Special Executive Retirement Plan as amended and
      restated effective July 1, 1997.
    **CSW**1998 Form 10-K, Ex 18, File No. 1-1443.†10(m)(2)
    Certified
      AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16,
      1996.
    2003
      Form 10-K, Ex 10(n)(3).†10(n)
    AEP
      System Incentive Compensation Deferral Plan Amended and Restated as of
      January 1, 2003.
    2003
      Form 10-K, Ex 10(o)(1).†10(o)
    AEP
      System Nuclear Performance Long Term Incentive Compensation Plan dated
      August 1, 1998.
    2002
      Form 10-K; Ex 10(p).†10(p)
    Nuclear
      Key Contributor Retention Plan dated May 1, 2000.
    2002
      Form 10-K; Ex 10(q).*†10(q)
    Base
      Salaries for Named Executive Officers*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the APCo 2004 Annual Report (for the fiscal year
      ended December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of APCo
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    CSPCo‡** **File No.
      1-2680**3(a)
    Composite
      of Amended Articles of Incorporation of CSPCo, dated May 19,
      1994.
    1994
      Form 10-K, Ex 3(c).3(b)
    Code
      of Regulations and By-Laws of CSPCo.
    1987
      Form 10-K, Ex 3(d).4(a)
    Indenture
      (for unsecured debt securities), dated as of September 1, 1997, between
      CSPCo and Bankers Trust Company, as Trustee.
    Registration
      Statement No. 333-54025, Ex 4(a)(b)(c)(d);
      1998
      Form 10-K, Ex 4(c)(d).4(b)
    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.
    2003
      Form 10-K, Ex 4(c).4(c)
    Indenture
      (for unsecured debt securities), dated as of February 1, 2003, between
      CSPCo and Bank One, N.A., as Trustee.
    2003
      Form 10-K, Ex 4(d).4(d)
    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.
    2003
      Form 10-K, Ex 4(e).4(e)
    Second
      Supplemental Indenture, dated as of February 1, 2003, between CSPCo and
      Bank One establishing the terms of 6.60% Senior Notes, Series B, due 2033
      and 6.60% Senior Notes, Series D, due 2033.
    2003
      Form 10-K, Ex 4(f).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, Ex 5(a);
      Registration
      Statement No. 2-63234, Ex 5(a)(1)(B);
      Registration
      Statement No. 2-66301, Ex 5(a)(1)(C);
      Registration
      Statement No. 2-67728, Ex 5(a)(1)(B);
      **APCo**1989 Form 10-K, Ex 10(a)(1)(F), File No. 1-3457;
      **APCo**1992 Form 10-K, Ex 10(a)(1)(B), File No. 1-3457.10(a)(2)
    Inter-Company
      Power Agreement, dated July 10, 1953, among OVEC and the Sponsoring
      Companies, as amended.
    Registration
      Statement No. 2-60015, Ex 5(c);
      Registration
      Statement No. 2-67728, Ex 5(a)(3)(B);
      **APCo**1992 Form 10-K, Ex 10(a)(2)(B), File No. 1-3457.10(a)(3)
    Power
      Agreement, dated July 10, 1953, between OVEC and Indiana-Kentucky Electric
      Corporation, as amended.
    Registration
      Statement No. 2-60015, Ex 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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      **AEP**1990 Form 10-K, Ex 10(a)(3), File No. 1-3525.10(c)
    Transmission
      Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo,
      and with AEPSC as agent, as amended.
    **AEP**1985 Form 10-K, Ex 10(b), File No. 1-3525;
      **AEP**1988 Form 10-K, Ex 10(b)(2) File No. 1-3525.*10(d)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(d)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(d)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.10(e)
    Modification
      No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
      among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
    **AEP**1996 Form 10-K, Ex 10(l), File No. 1-3525.10(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.
    **AEP**1997 Form 10-K, Ex 10(f), File No. 1-3525.10(f)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of
      Merger.
    Form
      8-K, Ex 10, dated December 15, 1999.*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the CSPCo 2004 Annual Report (for the fiscal year
      ended December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of CSPCo
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    I&M‡**  **File No.
      1-3570**3(a)
    Composite
      of the Amended Articles of Acceptance of I&M, dated of March 7,
      1997
    1996
      Form 10-K, Ex 3(c).3(b)
    By-Laws
      of I&M, amended as of November 28, 2001.
    2001
      Form 10-K, Ex 3(d).4(a)
    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, Ex 4(a)(b)(c);
      Registration
      Statement No. 333-58656, Ex 4(b)(c);
      Registration
      Statement No. 333-108975, Ex 4(b)(c)(d)].4(b)
    Company
      Order and Officer’s Certificate, dated November 10, 2004, establishing
      terms of 5.05% Senior Notes, Series F, due 2014.
    Form
      8-K, Ex. 4(a), dated November 16, 200410(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, Ex 5(a);
      Registration
      Statement No. 2-63234, Ex 5(a)(1)(B);
      Registration
      Statement No. 2-66301, Ex 5(a)(1)(C);
      Registration
      Statement No. 2-67728, Ex 5(a)(1)(D);
      **APCo**1989 Form 10-K, File No. 1-3457, Ex 10(a)(1)(F);
      **APCo**1992 Form 10-K, File No. 1-3457, Ex 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, Ex 5(c);
      Registration
      Statement No. 2-67728, Ex 5(a)(3)(B);
      **APCo**Form 10-K, File No. 1-3457, Ex 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, Ex 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, Ex 5(c);
      Registration
      Statement No. 2-67728, Ex 5(a)(3)(B);
      **APCo**1992 Form 10-K, File No. 1-3457, Ex 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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      **AEP**1990 Form 10-K, File No. 1-3525, Ex 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.
    **AEP**1985 Form 10-K, File No. 1-3525, Ex 10(b);
      **AEP**1988 Form 10-K, File No. 1-3525, Ex 10(b)(2).*10(d)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(d)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(d)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.10(e)
    Modification
      No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
      among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
    **AEP**1996 Form 10-K, File No. 1-3525, Ex 10(l).10(f)
    Lease
      Agreements, dated as of December 1, 1989, between I&M and Wilmington
      Trust Company, as amended.
    Registration
      Statement No. 33-32753, Ex 28(a)(1-6)(C);
      1993
      Form 10-K, Ex 10(e)(1-6)(B).10(g)(1)
    Agreement
      and Plan of Merger, dated as of December 21, 1997, By and Among American
      Electric Power Company, Inc., Augusta Acquisition Corporation and Central
      and South West Corporation.
    **AEP**1997 Form 10-K, File No. 1-3525, Ex 10(f).10(g)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of
      Merger
    Form
      8-K, Ex 10, December 15, 1999.*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the I&M 2004 Annual Report (for the fiscal year
      ended December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of I&M.
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    KPCo‡** **File No.
      1-6858**3(a)
    Restated
      Articles of Incorporation of KPCo.
    1991
      Form 10-K, Ex 3(a).3(b)
    By-Laws
      of KPCo, amended as of June 15, 2000.
    2000
      Form 10-K, Ex 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, Ex 4(a)(b)(c)(d);Registration
      Statement No. 333-87216, Ex 4(e)(f);
      2002
      Form 10-K, Ex 4(c)(d)(e).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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      **AEP**1990 Form 10-K, File No. 1-3525, Ex 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.
    **AEP**1985 Form 10-K, File No. 1-3525, Ex 10(b);
      **AEP**1988 Form 10-K, File No. 1-3525, Ex 10(b)(2).*10(c)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(c)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(c)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.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.
    **AEP**1996 Form 10-K, File No. 1-3525, Ex 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
    **AEP**1997 Form 10-K, File No. 1-3525, Ex 10(f).10(e)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of
      Merger.
    Form
      8-K, Ex 10, dated December 15, 1999.*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the KPCo 2004 Annual Report (for the fiscal year
      ended December 31, 2004) 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.****
    **REGISTRANT:    OPCo‡** **File
      No.1-6543**3(a)
    Composite
      of the Amended Articles of Incorporation of OPCo, dated June 3, 2002.
    Form
      10-Q, Ex 3(e), June 30, 2002.3(b)
    Code
      of Regulations of OPCo.
    1990
      Form 10-K, Ex 3(d).4(a)
    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, Ex 4(a)(b)(c);
      Registration
      Statement No. 333-106242, Ex 4(b)(c)(d);
      Registration
      Statement No. 333-75783, Ex 4(b)(c).4(b)
    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.
    2003
      Form 10-K, Ex 4(c).4(c)
    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.
    2003
      Form 10-K, Ex 4(d).4(d)
    Indenture
      (for unsecured debt securities), dated as of February 1, 2003, between
      OPCo and Bank One, N.A., as Trustee.
    2003
      Form 10-K, Ex 4(e).4(e)
    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.
    2003
      Form 10-K, Ex 4(f).4(f)
    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.
    2003
      Form 10-K, Ex 4(g).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, Ex 5(a);
      Registration
      Statement No. 2-63234, Ex 5(a)(1)(B);
      Registration
      Statement No. 2-66301, Ex 5(a)(1)(C);
      Registration
      Statement No. 2-67728, Ex 5(a)(1)(D);
      **APCo**Form 10-K, File No. 1-3457, Ex 10(a)(1)(F);
      **APCo**Form 10-K, File No. 1-3457, Ex 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, Ex 5(c);
      Registration
      Statement No. 2-67728, Ex 5(a)(3)(B);
      **APCo**Form 10-K, File No. 1-3457, Ex 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, Ex 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, Ex 5(a);
      Registration
      Statement No. 2-61009, Ex 5(b);
      **AEP**1990 Form 10-K, File 1-3525, Ex 10(a)(3).10(c)
    Transmission
      Agreement, dated April 1, 1984, among APCo, CSPCo, I&M, KPCo, OPCo and
      with AEPSC as agent.
    **AEP**1985 Form 10-K, File No. 1-3525, Ex 10(b);
      **AEP**1988 Form 10-K, File No. 1-3525, Ex 10(b)(2).*10(d)(1)
    Amended
      and Restated Operating Agreement of PJM and AEPSC on behalf of APCo,
      CSPCo, I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.*10(d)(2)
    PJM
      West Reliability Assurance Agreement among Load Serving Entities in the
      PJM West service area.*10(d)(3)
    Master
      Setoff and Netting Agreement among PJM and AEPSC on behalf of APCo, CSPCo,
      I&M, KPCo, OPCo, Kingsport Power Company and Wheeling Power
      Company.10(e)
    Modification
      No. 1 to the AEP System Interim Allowance Agreement, dated July 28, 1994,
      among APCo, CSPCo, I&M, KPCo, OPCo and AEPSC.
    **AEP**1996 Form 10-K, File No. 1-3525, Ex 10(l).10(f)(1)
    Amendment
      No. 1, dated October 1, 1973, to Station Agreement dated January 1, 1968,
      among OPCo, Buckeye and Cardinal Operating Company, and amendments
      thereto.
    1993
      Form 10-K, Ex 10(f).
      2003
      Form 10-K, Ex 10(e)10(f)(2)
    Amendment
      No. 9, dated July 1, 2003, to Station Agreement dated January 1, 1968,
      among OPCo, Buckeye and Cardinal Operating Company, and amendments
      thereto.
    Form
      10-Q, Ex 10(a), September 30, 2004.10(g)
    Lease
      Agreement dated January 20, 1995 between OPCo and JMG Funding, Limited
      Partnership, and amendment thereto (confidential treatment
      requested).
    1994
      Form 10-K, Ex 10(l)(2).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.
    **AEP**1997 Form 10-K, File No. 1-3525, Ex 10(f).10(h)(2)
    Amendment
      No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger.
    Form
      8-K, Ex 10, dated December 15, 1999.†10(i)
    AEP
      System Senior Officer Annual Incentive Compensation Plan.
    **AEP**1996 Form 10-K, Ex 10(i)(1), File No. 1-3525.†10(j)(1)(A)
    AEP
      System Excess Benefit Plan, Amended and Restated as of January 1,
      2001.
    **AEP**2000 Form 10-K, Ex 10(j)(1)(A), File No. 1-3525.†10(j)(1)(B)
    First
      Amendment to AEP System Excess Benefit Plan, dated as of March 5,
      2003.
    2002
      Form 10-K; Ex 10(i)(1)(B)†10(j)(2)
    AEP
      System Supplemental Retirement Savings Plan, Amended and Restated as of
      September 1, 2004 (Non-Qualified).
    **AEP**Form 8-K, Ex 99.1, dated September 1, 2004.†10(j)(3)
    Umbrella
      Trust for Executives.
    **AEP**1993
      Form 10-K, Ex 10(g)(3), File No. 1-3525.†10(k)(1)
    Employment
      Agreement between AEP, AEPSC and Michael G. Morris dated December 15,
      2003.
    2003
      Form 10-K, Ex 10(j)(1).†10(k)(2)
    Memorandum
      of agreement between Susan Tomasky and AEPSC dated January 3,
      2001.
    **AEP**2000
      Form 10-K, Ex 10(s), File No. 1-3525.†10(k)(3)
    Employment
      Agreement dated July 29, 1998 between AEPSC and Robert P.
      Powers.
    2002
      Form 10-K, Ex 10(j)(3).†10(k)(4)
    Letter
      Agreement dated June 4, 2004 between AEPSC and Carl
English
    **AEP**Form 10-Q, Ex 10(b), September 30, 2004,
      File
      No. 1-3525,†10(l)(1)
    AEP
      System Survivor Benefit Plan, effective January 27, 1998.
    **AEP**Form
      10-Q, Ex 10, September 30, 1998,
      File
      No. 1-3525,.†10(l)(2)
    First
      Amendment to AEP System Survivor Benefit Plan, as amended and restated
      effective January 31, 2000.
    2002
      Form 10-K; Ex 10(k)(2).†10(m)
    AEP
      Change In Control Agreement, effective January 1, 2005.
    **AEP**Form
      8-K, Ex 10.1, dated January 10, 2005,
      File
      No. 1-3525.†10(n)(1)
    AEP
      System 2000 Long-Term Incentive Plan, as amended December 10,
      2003.
    2003
      Form 10-K, Ex 10(n).†10(n)(2)
    Form
      of Performance Share Award Agreement furnished to participants of the AEP
      System 2000 Long-Term Incentive Plan, as amended
    **AEP**Form 10-Q, Ex. 10(c), dated November 5, 2004.†10(o)(1)
    Central
      and South West System Special Executive Retirement Plan as amended and
      restated effective July 1, 1997.
    1998
      Form 10-K, File No. 1-1443, Ex 18.†10(o)(2)
    Certified
      AEP Utilities, Inc. (formerly CSW) Board Resolutions of July 16,
      1996.
    2003
      Form 10-K, Ex 10(o)(3).†10(p)
    AEP
      System Incentive Compensation Deferral Plan Amended and Restated as of
      January 1, 2003.
    2003
      Form 10-K, Ex 10(p)(1).†10(q)
    AEP
      System Nuclear Performance Long Term Incentive Compensation Plan dated
      August 1, 1998.
    2002
      Form 10-K, Ex 10(q).†10(r)
    Nuclear
      Key Contributor Retention Plan dated May 1, 2000.
    2002
      Form 10-K, Ex 10(r).*†10(s)
    Base
      Salaries for Named Executive Officers*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the OPCo 2004 Annual Report (for the fiscal year
      ended December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of OPCo.
    **AEP**2004 Form 10-K, File No. 1-3525, Ex 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.****
    **REGISTRANT:    PSO‡**  **File No.
      0-343**3(a)
    Restated
      Certificate of Incorporation of PSO.
    **CSW**1996 Form U5S, File No. 1-1443, Ex B-3.1.3(b)
    By-Laws
      of PSO (amended as of June 28, 2000).
    2002
      Form 10-K, Ex 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, Ex 5.03;
      Registration
      Statement No. 2-64432, Ex 2.02;
      Registration
      Statement No. 2-65871, Ex 2.02;
      Form
      U-1 No. 70-6822, Ex 2;
      Form
      U-1 No. 70-7234, Ex 3;
      Registration
      Statement No. 33-48650, Ex 4(b);
      Registration
      Statement No. 33-49143, Ex 4(c);
      Registration
      Statement No. 33-49575, Ex 4(b);
      1993
      Form 10-K, Ex 4(b);
      Form
      8-K, Ex 4.01; dated March 4, 1996.
      Form
      8-K, Ex 4.02, dated March 4, 1996;
      Form
      8-K, Ex 4.03, dated March 4, 1996.4(b)
    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, Exs 4(a)(b);
      2002
      Form 10-K; Ex 4(c).4(c)
    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.
    2003
      Form 10-K, Ex 4(d).4(d)
    Fourth
      Supplemental Indenture, dated as of June 7, 2004 between PSO and The Bank
      of New York, as Trustee, establishing terms of the 4.70% Senior Notes,
      Series D, due 2009
    Form
      8-K, Ex 4(a), dated June 7, 200410(a)
    Restated
      and Amended Operating Agreement, dated as of January 1, 1998, among PSO,
      TCC, TNC, SWEPCo and AEPSC.
    2002
      Form 10-K, Ex 10(a).10(b)
    Transmission
      Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC,
      SWEPCo and AEPSC.
    2002
      Form 10-K, Ex 10(b).*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the PSO 2004 Annual Report (for the fiscal year ended
      December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of PSO.
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    SWEPCo‡** **File No.
      1-3146**3(a)
    Restated
      Certificate of Incorporation, as amended through May 6, 1997, including
      Certificate of Amendment of Restated Certificate of
      Incorporation.
    Form
      10-Q, Ex 3.4, March 31, 1997.3(b)
    By-Laws
      of SWEPCo (amended as of April 27, 2000).
    Form
      10-Q, Ex 3.3, March 31, 2000.4(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, Ex 5.04;
      Registration
      Statement No. 2-61943, Ex 2.02;
      Registration
      Statement No. 2-66033, Ex 2.02;
      Registration
      Statement No. 2-71126, Ex 2.02;
      Registration
      Statement No. 2-77165, Ex 2.02;
      Form
      U-1 No. 70-7121, Ex 4;
      Form
      U-1 No. 70-7233, Ex 3;
      Form
      U-1 No. 70-7676, Ex 3;
      Form
      U-1 No. 70-7934, Ex 10;
      Form
      U-1 No. 72-8041, Ex 10(b);
      Form
      U-1 No. 70-8041, Ex 10(c);
      Form
      U-1 No. 70-8239, Ex 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 Ex
      4(f)(i)(A).
    2003
      Form 10-K, Ex 4(b).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, Ex 4(a)(b);
      Registration
      Statement No. 333-600632, Ex 4(b);
      Registration
      Statement No. 333-108045, Ex 4(b).4(d)
    Third
      Supplemental Indenture, between SWEPCo and The Bank of New York, as
      Trustees, dated April 11, 2003, establishing terms of 5.375% Senior Notes,
      Series C, due 2015.
    2003
      Form 10-K, Ex 4(d).10(a)
    Restated
      and Amended Operating Agreement, dated as of January 1, 1998, among PSO,
      TCC, TNC, SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(a).10(b)
    Transmission
      Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC,
      SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(b).*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the SWEPCo 2004 Annual Report (for the fiscal year
      ended December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of SWEPCo.
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    TCC‡**  **File No.
      0-346**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.
    Form
      10-Q, Ex 3.1, March 31, 1997.3(b)
    Articles
      of Amendment to Restated Articles of Incorporation of TCC dated December
      18, 2002.
    2002
      Form 10-K; Ex 3(b).3(c)
    By-Laws
      of TCC (amended as of April 19, 2000).
    2000
      Form 10-K, Ex 3(b).4(a)
    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.
    2000
      Form 10-K, Ex 4(c)(d)(e).4(b)
    Indenture
      (for unsecured debt securities), dated as of February 1, 2003, between TCC
      and Bank One, N.A., as Trustee.
    2003
      Form 10-K, Ex 4(d).4(c)
    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.
    2003
      Form 10-K, Ex 4(e).4(d)
    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.
    2003
      Form 10-K, Ex 4(f).4(e)
    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.
    2003
      Form 10-K, Ex 4(g).4(f)
    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.
    2003
      Form 10-K, Ex 4(h).10(a)
    Restated
      and Amended Operating Agreement, dated as of January 1, 1998, among PSO,
      TCC, TNC, SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(a).10(b)
    Transmission
      Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC,
      SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(b).10(c)
    Purchase
      and Sale Agreement, dated as of September 3, 2004, by and between TCC and
      City of San Antonio (acting by and through the City Public Service Board
      of San Antonio) and Texas Genco, L.P.
    Form
      10-Q, Ex. 10(a), September 30, 2004.*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the TCC 2004 Annual Report (for the fiscal year ended
      December 31, 2004) which are incorporated by reference in this
      filing.21
    List
      of subsidiaries of TCC.
    **AEP**2004 Form 10-K, Ex 21, File No. 1-3525.*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.****
    **REGISTRANT:    TNC‡** **File No.
      0-340**3(a)
    Restated
      Articles of Incorporation, as amended, and Articles of Amendment to the
      Articles of Incorporation.
    1996
      Form 10-K, Ex 3.5.3(b)
    Articles
      of Amendment to Restated Articles of Incorporation of TNC dated December
      17, 2002.
    2002
      Form 10-K; Ex 3(b).3(c)
    By-Laws
      of TNC (amended as of May 1, 2000).
    Form
      10-Q, Ex 3.4, March 31, 2000.4(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, Ex 5.05;
      Registration
      Statement No. 2-63931, Ex 2.02;
      Registration
      Statement No. 2-74408, Ex 4.02;
      Form
      U-1 No. 70-6820, Ex 12;
      Form
      U-1 No. 70-6925, Ex 13;
      Registration
      Statement No. 2-98843, Ex 4(b);
      Form
      U-1 No. 70-7237, Ex 4;
      Form
      U-1 No. 70-7719, Ex 3;
      Form
      U-1 No. 70-7936, Ex 10;
      Form
      U-1 No. 70-8057, Ex 10;
      Form
      U-1 No. 70-8265, Ex 10;
      Form
      U-1 No. 70-8057, Ex 10(b);
      Form
      U-1 No. 70-8057, Ex 10(c).4(b)
    Indenture
      (for unsecured debt securities), dated as of February 1, 2003, between TNC
      and Bank One, N.A., as Trustee.
    2003
      Form 10-K, Ex 4(b).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.
    2003
      Form 10-K, Ex 4(c).10(a)
    Restated
      and Amended Operating Agreement, dated as of January 1, 1998, among PSO,
      TCC, TNC, SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(a).10(b)
    Transmission
      Coordination Agreement, dated October 29, 1998, among PSO, TCC, TNC,
      SWEPCo and AEPSC.
    2002
      Form 10-K; Ex 10(b).*12
    Statement
      re: Computation of Ratios.*13
    Copy
      of those portions of the TNC 2004 Annual Report (for the fiscal year ended
      December 31, 2004) 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.