2003 Annual Reports

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



Audited Financial Statements and
Management's Discussion and Analysis






<PAGE>
<TABLE>
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                                  AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                                                   INDEX TO ANNUAL REPORTS

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

   Forward-Looking Information

   AEP Common Stock and Dividend Information

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

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

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

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

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

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

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

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

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

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

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



                         Notes to Respective Financial Statements




                         Registrants' Combined Management's Discussion and Analysis
</TABLE>




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

               Term                                Meaning
               ----                                -------
<C>                                <C>
2004 True-up Proceeding            A filing to be made after January 10, 2004 under the Texas  Legislation to finalize the amount
                                            of stranded costs and other true-up items and the recovery of such amounts.
AEGCo                              AEP Generating Company, an electric utility subsidiary of AEP.
AEP                                American Electric Power Company, Inc.
AEP Consolidated                   AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit                         AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated domestic electric utility companies.
AEP East companies                 APCo, CSPCo, I&M, KPCo and OPCo.
AEPES                              AEP Energy Services, Inc., a subsidiary of AEPR.
AEPR                               AEP Resources, Inc.
AEP System or the System           The American Electric Power System, an integrated electric utility system, owned and operated by
                                            AEP's electric utility subsidiaries.
AEPSC                              American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP System Power Pool or           Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of Pool
AEP Power Pool                              generation and resultant wholesale system sales of the member companies.
AEP West companies                 PSO, SWEPCo, TCC and TNC.
AFUDC                              Allowance for funds used during construction, a noncash nonoperating income item that is
                                            capitalized and recovered through depreciation over the service life of domestic
                                            regulated electric utility plant.
ALJ                                Administrative Law Judge.
Alliance RTO                       Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
                                            utilities (the FERC overturned earlier approvals of this RTO in December 2001).
Amos Plant                         John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APB 18                             Accounting   Principles  Board  Opinion  Number  18:  The  Equity  Method  of  Accounting  for
                                            Investments in Common Stock.
APCo                               Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission                Arkansas Public Service Commission.
Buckeye                            Buckeye Power, Inc., an unaffiliated corporation.
COLI                               Corporate owned life insurance program.
Cook Plant                         The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo                              Columbus Southern Power Company, an AEP electric utility subsidiary.  Central and South West
                                            Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of
                                            Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Energy                         CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International                  CSW  International,  Inc., an AEP  subsidiary  which  invests in energy  projects and entities
                                            outside the United States.
D.C. Circuit Court                 The United States Court of Appeals for the District of Columbia Circuit.
DETM                               Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
DOE                                United States Department of Energy.
ECOM                               Excess Cost Over Market.
EITF                               The Financial Accounting Standards Board's Emerging Issues Task Force.
EITF 02-3                          Emerging  Issues Task Force Issue No.  02-3:  Issues  Involved in  Accounting  for  Derivative
                                            Contracts  Held For Trading  Purposes and  Contracts  Involved in Energy  Trading and
                                            Risk Management Activities.
ERCOT                              The Electric Reliability Council of Texas.
EWGs                               Exempt Wholesale Generators.
FASB                               Financial Accounting Standards Board.
Federal EPA                        United States Environmental Protection Agency.
FERC                               Federal Energy Regulatory Commission.
FIN 45                             FASB  Interpretation  No.  45,  "Guarantor's   Accounting  and  Disclosure   Requirements  for
                                            Guarantees, Including Indirect Guarantees of Indebtedness of Others."
FIN 46                             FASB Interpretation No. 46, "Consolidation of Variable Interest Entities."
FUCOs                              Foreign Utility Companies.
GAAP                               Generally Accepted Accounting Principles.
I&M                                Indiana Michigan Power Company, an AEP electric utility subsidiary.
ICR                                Interchange Cost Reconstruction.
IRS                                Internal Revenue Service.
IURC                               Indiana Utility Regulatory Commission.
ISO                                Independent System Operator.
JMG                                JMG Funding LP.
KPCo                               Kentucky Power Company, an AEP electric utility subsidiary.
KPSC                               Kentucky Public Service Commission.
KV                                 Kilovolt.
KWH                                Kilowatthour.
LIG                                Louisiana Intrastate Gas, an AEP subsidiary.
LPSC                               Louisiana Public Service Commission.
Michigan Legislation               The Customer Choice and Electricity Reliability Act, a Michigan law which provides for customer
                                            choice of electricity supplier.
MISO                               Midwest Independent System Operator (an independent operator of transmission assets in the
                                            Midwest).
MLR                                Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool                         AEP System's Money Pool.
MPSC                               Michigan Public Service Commission.
MTM                                Mark-to-Market.
MW                                 Megawatt.
MWH                                Megawatthour.
NOx                                Nitrogen oxide.
NOx Rule                           A final  rule  issued by Federal  EPA which  requires  NOx  reductions  in 22  eastern  states
                                            including seven of the states in which AEP companies operate.
NRC                                Nuclear Regulatory Commission.
OCC                                The Corporation Commission of the State of Oklahoma.
Ohio Act                           The Ohio Electric Restructuring Act of 1999.
Ohio EPA                           Ohio Environmental Protection Agency.
OPCo                               Ohio Power Company, an AEP electric utility subsidiary.
OVEC                               Ohio Valley  Electric  Corporation,  an electric  utility company in which AEP and CSPCo own a
                                            44.2% equity interest.
PCBs                               Polychlorinated Biphenyls.
PJM                                Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP                                Potentially Responsible Party.
PSO                                Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB                                Price-to-Beat.
PUCO                               The Public Utilities Commission of Ohio.
PUCT                               The Public Utility Commission of Texas.
PUHCA                              Public Utility Holding Company Act of 1935, as amended.
PURPA                              The Public Utility Regulatory Policies Act of 1978.
RCRA                               Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries            AEP subsidiaries who are SEC registrants;  AEGCo,  APCo,  CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
                                            TCC and TNC.
REP                                Retail Electric Provider.
Risk Management Contracts          Trading and non-trading derivatives, including those derivatives designated as cash flow and
                                            fair value hedges, and non-derivative contracts held for trading purposes that were
                                            subject to mark-to-market accounting prior to January 1, 2003.
Rockport Plant                     A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO                                Regional Transmission Organization.
SEC                                Securities and Exchange Commission.
SFAS                               Statement of Financial  Accounting  Standards  issued by the  Financial  Accounting  Standards
                                            Board.
SFAS 71                            Statement of Financial  Accounting  Standards No. 71,
                                            Accounting  for the Effects of Certain Types of Regulation.
                                            ----------------------------------------------------------
SFAS 101                           Statement   of   Financial    Accounting    Standards   No.   101,
                                            Accounting   for   the Discontinuance of Application of Statement 71.
                                            --------------------------------------------------------------------
SFAS 133                           Statement of Financial  Accounting  Standards No. 133,
                                            Accounting for Derivative  Instruments and Hedging Activities.
                                            -------------------------------------------------------------
SFAS 143                           Statement  of  Financial  Accounting  Standards  No.  143,
                                            Accounting  for Asset  Retirement Obligations.
                                            ---------------------------------------------
SFAS 149                           Statement of Financial Accounting Standards No. 149,
                                            Amendment of Statement 133 on Derivative Instruments and Hedging Activities.
                                            ---------------------------------------------------------------------------
SFAS 150                           Statement  of  Financial  Accounting  Standards  No. 150,
                                            Accounting  for Certain  Financial Instruments with Characteristics of both Liabilities
                                            ---------------------------------------------------------------------------------------
                                            and Equity.
                                            ----------
SNF                                Spent Nuclear Fuel.
SPP                                Southwest Power Pool.
STP                                South Texas Project Nuclear  Generating  Plant,  owned 25.2% by AEP Texas Central Company,  an
                                            AEP electric utility subsidiary.
STPNOC                             STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf of
                                            its joint owners including TCC.
Superfund                          The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo                             Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC                                AEP Texas Central Company, an AEP electric utility subsidiary.
Tenor                              Maturity of a contract.
Texas Legislation                  Legislation enacted in 1999 to restructure the electric utility industry in Texas. TNC AEP
                                            Texas North Company, an AEP electric utility subsidiary.
TVA                                Tennessee Valley Authority.
U.K.                               The United Kingdom.
VaR                                Value at Risk, a method to quantify risk exposure.
Virginia SCC                       Virginia State Corporation Commission.
WVPSC                              Public Service Commission of West Virginia.
WPCo                               Wheeling Power Company, an AEP electric distribution subsidiary.
Zimmer Plant                       William H.  Zimmer  Generating  Station,  a 1,300 MW  coal-fired  unit owned 25.4% by Columbus
                                            Southern Power Company, an AEP subsidiary.
</TABLE>


<PAGE>




                           FORWARD-LOOKING INFORMATION

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

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


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

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


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

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

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

</TABLE>

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



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




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


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

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

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

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

Trust Preferred Securities (b)                                  -             321             321             334            335

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

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


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

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

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

Year-end Market Price                                       30.51           27.33           43.53           46.50          32.13

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

</TABLE>

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


<PAGE>


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

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

We have a vast portfolio of assets including:
  o     38,000 megawatts of generating capacity, the largest complement of
        generation in the U.S., the majority of which has a significant cost
        advantage in many of our market areas. Utility generating capacity of
        4,500 megawatts located in Texas and approximately 280 megawatts of
        independent power generation located in Colorado and Florida are
        expected to be sold during 2004
  o     39,000 miles of transmission lines, the backbone of the electric
        interconnection grid in the Eastern U.S.
  o     210,000 miles of distribution lines that deliver electricity to
        customers
  o     Substantial coal  transportation  assets (7,000  railcars,
        1,800 barges,  37 towboats and two coal handling  terminals with 20
        million tons of annual capacity)
  o     6,400 miles of gas pipelines in Louisiana and Texas with 127 Bcf of
        gas storage facilities. We have entered into an agreement to sell
        2,000 miles of pipeline and plan to sell 9 Bcf of storage located in
        Louisiana related to our disposal of LIG
  o     4,000 megawatts of generating capacity in the U.K., a market which
        we plan to exit by the end of 2004

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

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

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

In summary our business strategy calls for us to:

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

<TABLE>
<CAPTION>

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

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

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

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

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

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

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

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

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

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


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

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

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

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

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

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



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

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

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

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

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

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

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

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

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

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

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

Utility operating expenses decreased as follows:

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

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

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

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

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

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

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

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

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

Utility operating expenses increased as follows:

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

All Other
---------

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

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

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

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

<TABLE>
<CAPTION>

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

Our capital was affected by the following, during 2003:

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

Liquidity
---------

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

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

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

      Net Available Liquidity                 $3,492
                                              ======

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

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

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

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

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

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

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

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

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

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


Cash Flow
---------

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

<TABLE>
<CAPTION>

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

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

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

<TABLE>
<CAPTION>


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

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

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

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


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

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

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

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

<TABLE>
<CAPTION>


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


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

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

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

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

<TABLE>
<CAPTION>

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


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

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

The following financing activities occurred during 2003 and 2002:

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

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

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

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

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

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

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

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

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

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

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

Minority Interest in Finance Subsidiary
---------------------------------------
We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was convertible into our common stock at market
price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash
and a subscription agreement that represents an unconditional obligation to fund
$83 million from SubOne for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. SubOne is the managing member of Caddis. As a result SubOne and all of
its subsidiaries, including Caddis, HPL and LIG, are included in our
Consolidated financial statements.

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

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

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

The credit agreement between Caddis and SubOne contains covenants that restrict
certain incremental liens and indebtedness, asset sales, investments,
acquisitions, and distributions. The credit agreement also contains covenants
that impose minimum financial ratios. Non-performance of these covenants may
result in an event of default under the credit agreement. Through December 31,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of our outstanding debt in excess of $50 million
would be an event of default under the credit agreement.

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

Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events, including a default in the payment of the
preferred return, Steelhead's rights include forcing a liquidation of Caddis and
acting as the liquidator. Liquidation of Caddis could negatively impact our
liquidity.

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

AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, AEP Credit sells an interest
in the receivables it acquires to the commercial paper conduits and banks and
receives cash. This transaction constitutes a sale of receivables in accordance
with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance
sheet and allowing AEP Credit to repay any debt obligations. AEP has no
ownership interest in the commercial paper conduits and does not consolidate
these entities in accordance with GAAP. We continue to service the receivables.
This off-balance sheet transaction was entered into to allow AEP Credit to repay
its outstanding debt obligations, continue to purchase the AEP operating
companies' receivables, and accelerate its cash collections.

AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 million was outstanding. As collections from receivables sold
occur and are remitted, the outstanding balance for sold receivables is reduced
and as new receivables are sold, the outstanding balance of sold receivables
increases. All of the receivables sold represented affiliate receivables. AEP
Credit maintains a retained interest in the receivables sold and this interest
is pledged as collateral for the collection of the receivables sold. The fair
value of the retained interest is based on book value due to the short-term
nature of the accounts receivables less an allowance for anticipated
uncollectible accounts.

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

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

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

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. Neither
AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of
these entities guarantee its debt.

Railcars
--------

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

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

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

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

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

<TABLE>
<CAPTION>

                                                                         Payments Due by Period
                                                                             (in millions)

Contractual Cash Obligations                 Less Than 1 year    2-3 years      4-5 years      After 5 years    Total
----------------------------                 ----------------    ---------      ---------      -------------    -----

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

</TABLE>

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

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

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

<TABLE>
<CAPTION>

                                                          Amount of Commitment Expiration Per Period
                                                                        (in millions)

Other Commercial Commitments                Less Than 1 year    2-3 years     4-5 years     After 5 years     Total
----------------------------                ----------------    ---------     ---------     -------------     -----

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

</TABLE>

(a)   We have issued standby letters of credit to third parties. These letters
      of credit cover gas and electricity risk management contracts,
      construction contracts, insurance programs, security deposits, debt
      service reserves and credit enhancements for issued bonds. All of these
      letters of credit were issued in the ordinary course of business. The
      maximum future payments of these letters of credit are $227 million with
      maturities ranging from January 2004 to January 2011. As the parent of all
      of these subsidiaries, we hold all assets of the subsidiaries as
      collateral. There is no recourse to third parties in the event these
      letters of credit are drawn.
(b)   These amounts are the balances drawn, not the maximum guarantee disclosed
      in Note 8.
(c)   As construction agent for third party owners of transmission facilities,
      we have committed by contract terms to complete construction by dates
      specified in the contracts. Should we default on these obligations,
      financial payments could be required including liquidating damages of up
      to $8 million and other remedies required by contract terms.
(d)   OPCo has entered into a 30-year power purchase agreement for electricity
      produced by an unaffiliated entity's three-unit natural gas fired plant.
      The plant was completed in 2002 and the agreement will terminate in 2032.
      Under the terms of the agreement, OPCo has the option to run the plant
      until December 31, 2005, taking 100% of the power generated and making
      monthly capacity payments. The capacity payments are fixed through
      December 2005 at $1.2 million per month. For the remainder of the 30-year
      contract term, OPCo will pay the variable costs to generate the
      electricity it purchases which could be up to 20% of the plant's capacity.

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

Other
-----

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We maintain qualified, defined benefit pension plans (Qualified Plans), which
cover a substantial majority of non-union and certain union associates, and
unfunded excess plans to provide benefits in excess of amounts permitted to be
paid under the provisions of the tax law to participants in the Qualified Plans.
Additionally, we have entered into individual retirement agreements with certain
current and retired executives that provide additional retirement benefits.

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

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


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

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

</TABLE>

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

We base our determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded. As of December 31, 2003, we had
cumulative losses of approximately $325 million which remain to be recognized in
the calculation of the market-related value of assets. These unrecognized net
actuarial losses result in increases in the future pension costs depending on
several factors, including whether such losses at each measurement date exceed
the corridor in accordance with SFAS No. 87, "Employers' Accounting for
Pensions."

The discount rate that we utilize for determining future pension obligations is
based on a review of long-term bonds that receive one of the two highest ratings
given by a recognized rating agency. The discount rate determined on this basis
has decreased from 6.75% at December 31, 2002, to 6.25% at December 31, 2003.
Due to the effect of the unrecognized actuarial losses and based on an expected
rate of return on the Qualified Plans' assets of 8.75%, a discount rate of 6.25%
and various other assumptions, we estimate that the pension expense for all
pension plans will approximate $41 million, $78 million and $103 million in
2004, 2005 and 2006, respectively. Future actual pension cost will depend on
future investment performance, changes in future discount rates and various
other factors related to the populations participating in the pension plans.

Lowering the expected long-term rate of return on the Qualified Plans' assets by
0.5% (from 9.0% to 8.5%) would have increased pension cost for 2003 by
approximately $18 million (income of $3 million would have become $15 million in
pension expense). Lowering the discount rate by 0.5% would have reduced pension
income for 2003 by approximately $0.5 million.

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

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

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

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

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

Litigation
----------

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

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

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

On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and
its subsidiaries in the bankruptcy proceeding filed by the Enron entities which
are pending in the U.S. Bankruptcy Court for the Southern District of New York.
At the date of Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In addition,
on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron.
Various HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron's bankruptcy. The timing of the resolution of the claims by
the Bankruptcy Court is not certain.

In connection with the 2001 acquisition of HPL, we acquired exclusive rights to
use and operate the underground Bammel gas storage facility pursuant to an
agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
exclusive right to use the referenced facility is for a term of 30 years, with a
renewal right for another 20 years and includes the use of the Bammel storage
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.

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

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

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

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

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

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

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit against BOM claiming BOM had acted contrary to the appropriate trading
contract and industry practice in terminating the contract and calculating
termination and liquidation amounts and that BOM had acknowledged just prior to
the termination and liquidation that it owed us approximately $68 million. We
are claiming that BOM owes us at least $45 million. Although management is
unable to predict the outcome of this matter, it is not expected to have a
material impact on results of operations, cash flows or financial condition.

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

In 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
AEP and Williams settled the dispute with AEP paying $90 million to Williams in
June 2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter had an immaterial
impact on results of operations and financial condition. See Note 7 for further
discussion.

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

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

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

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

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

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

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

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

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

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

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

In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP has been dismissed
from the case. See Note 7 for further discussion.

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

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

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

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

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

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

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

A decision by the U.S. District Court for the Southern District of Ohio in
February 2001 that denied AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to a COLI program resulted in a
$319 million reduction in AEP's Net Income for 2000. We filed an appeal of the
U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit. In April 2003, the Appeals Court ruled against AEP. The U.S. Supreme
Court has declined to hear this issue.

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

In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract and paid $59 million to us. The settlement amount was
less than the amount receivable that, in the ordinary course of business, we
recorded using MTM accounting. As a result, we incurred a $10 million pre-tax
loss.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Superfund addresses clean-up of hazardous substances at disposal sites and
authorized the Federal EPA to administer the clean-up programs. As of year-end
2003, subsidiaries of AEP are named by the Federal EPA as a PRP for five sites.
There are six additional sites for which our subsidiaries have received
information requests which could lead to PRP designation. Our subsidiaries have
also been named potentially liable at six sites under state law. Liability has
been resolved for a number of sites with no significant effect on results of
operations. In those instances where we have been named a PRP or defendant, our
disposal or recycling activities were in accordance with the then-applicable
laws and regulations. Unfortunately, Superfund does not recognize compliance as
a defense, but imposes strict liability on parties who fall within its broad
statutory categories.

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

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

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

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

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

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

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

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP, have a
significant future financial commitment to safely dispose of SNF and to
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law I&M and TCC participate in the DOE's
SNF disposal program which is described in Note 7. Since 1983 I&M has collected
$316 million from customers for the disposal of nuclear fuel consumed at the
Cook Plant. We deposited $117 million of these funds in external trust funds to
provide for the future disposal of SNF and remitted $199 million to the DOE. TCC
has collected and remitted to the DOE, $56 million for the future disposal of
SNF since STP began operation in the late 1980s. Under the provisions of the
Nuclear Waste Policy Act, collections from customers are to provide the DOE with
money to build a permanent repository for spent fuel. However, in 1996, the DOE
notified the companies that it would be unable to begin accepting SNF by the
January 1998 deadline required by law. To date DOE has failed to comply with the
requirements of the Nuclear Waste Policy Act.

As a result of DOE's failure to make sufficient progress toward a permanent
repository or otherwise assume responsibility for SNF, AEP on behalf of I&M and
STPNOC on behalf of TCC and the other STP owners, along with a number of
unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. On January 17,
2003, the U.S. Court of Federal Claims ruled in favor of I&M on the issue of
liability. The case continues on the issue of damages owed to I&M by the DOE
with a trial scheduled in March 2004. As long as the delay in the availability
of a government approved storage repository for SNF continues, the cost of
both temporary and permanent storage of SNF and the cost of decommissioning
will continue to increase.

The cost to decommission nuclear plants is affected by both NRC regulations and
the delayed SNF disposal program. Studies completed in 2003 estimate the cost to
decommission the Cook Plant ranges from $821 million to $1.08 billion in 2003
non-discounted dollars. External trust funds have been established with amounts
collected from customers to decommission the plant. At December 31, 2003, the
total decommissioning trust fund balance for Cook Plant was $720 million which
includes earnings on the trust investments. Studies completed in 1999 for STP
estimate TCC's share of decommissioning cost to be $289 million in 1999
non-discounted dollars. Amounts collected from customers to decommission STP
have been placed in an external trust. At December 31, 2003, the total
decommissioning trust fund for TCC's share of STP was $125 million which
includes earnings on the trust investments. Estimates from the decommissioning
studies could continue to escalate due to the uncertainty in the SNF disposal
program and the length of time that SNF may need to be stored at the plant site.
I&M and TCC will work with regulators and customers to recover the remaining
estimated costs of decommissioning Cook Plant and STP. However, our future
results of operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning continues to
increase and cannot be recovered.

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

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

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

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

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

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

We believe that the following discussion addresses the most critical accounting
policies, which are those that are most important to the portrayal of the
financial condition and results and require management's most difficult,
subjective and complex judgments, often as a result of the need to make
estimates about the effect of matters that are inherently uncertain.

Revenue Recognition
-------------------

Regulatory Accounting
---------------------

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

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

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

We recognize revenues on the accrual or settlement basis for normal retail and
wholesale electricity supply sales and electricity transmission and distribution
delivery services. That is, we recognize and record revenues when the energy is
delivered to the customer and include estimated unbilled as well as billed
amounts. In general, expenses are recorded when purchased electricity is
received and when expenses are incurred.

Domestic Gas Pipeline and Storage Activities
--------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We sponsor pension and other retirement plans in various forms covering all
employees who meet eligibility requirements. We use several statistical and
other factors which attempt to anticipate future events in calculating the
expense and liability related to our plans. These factors include assumptions
about the discount rate, expected return on plan assets and rate of future
compensation increases as estimated by management, within certain guidelines. In
addition, our actuarial consultants use subjective factors such as withdrawal
and mortality rates to estimate these factors. The actuarial assumptions used
may differ materially from actual results due to changing market and economic
conditions, higher or lower withdrawal rates or longer or shorter life spans of
participants. These differences may result in a significant impact to the amount
of pension expense recorded. See "Pension Plans" in Significant Factors section
of Management's Financial Discussion and Analysis.

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

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

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

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

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

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

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

A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.

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

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

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

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

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

Our investment, including guarantees of debt, in certain types of activities is
limited by PUHCA. SEC authorization under PUHCA limits us to issuing and selling
securities in an amount up to 100% of our average quarterly consolidated
retained earnings balance for investment in EWGs and FUCOs. At December 31,
2003, our investment in EWGs and FUCOs was $1.7 billion, including guarantees of
debt, compared to our limit of $2.1 billion.

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

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

Market Risks
------------

As a major power producer and marketer of wholesale electricity and natural gas,
we have certain market risks inherent in our business activities. These risks
include commodity price risk, interest rate risk, foreign exchange risk and
credit risk. They represent the risk of loss that may impact us due to changes
in the underlying market prices or rates.

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

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

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

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

<TABLE>
<CAPTION>

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

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

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

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


<TABLE>
<CAPTION>

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

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

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

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

<TABLE>
<CAPTION>


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

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

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

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


        * Excluding Cash Flow Hedges.

</TABLE>


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

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

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


<TABLE>
<CAPTION>


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

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

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

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

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

</TABLE>

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

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

<TABLE>
<CAPTION>

                                       Maximum Tenor of the Liquid Portion of Risk Management Contracts
                                                          As of December 31, 2003

           Domestic          Transaction Class                       Market/Region                             Tenor
           --------          -----------------                       -------------                             -----
                                                                                                            (in months)

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

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

        Crude Oil           Swaps                                West Texas Intermediate                         36

        Emissions           Credits                              SO2                                             24

        Coal                Physical Forwards                    PRB,NYMEX,CSX                                   24

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

        Power               Forwards and Options                 United Kingdom                                  24

        Coal                Forward Purchases and Sales          United Kingdom                                  15

                            Swaps                                Europe                                          36

        Freight             Swaps                                Europe                                          24

</TABLE>

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

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

We employ fair value hedges and cash flow hedges to mitigate changes in interest
rates or fair values on short and long-term debt when management deems it
necessary. We do not hedge all interest rate risk. We employ forward contracts
as cash flow hedges to lock-in prices on certain transactions which have been
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations of debt
denominated in foreign currencies. We do not hedge all foreign currency
exposure.

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

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

<TABLE>
<CAPTION>

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

<TABLE>
<CAPTION>

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

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

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

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

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

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

<TABLE>
<CAPTION>

                                                                                          Number of            Net Exposure of
Counterparty                        Exposure Before        Credit          Net          Counterparties          Counterparties
Credit Quality:                    Credit Collateral     Collateral      Exposure           > 10%                    >10%
--------------                     -----------------     ----------      --------       --------------         ---------------

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

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

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

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

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


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

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


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

                                    VaR Model

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

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

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

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

<TABLE>
<CAPTION>

                                                                   CCRO VaR Metrics

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

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

</TABLE>

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

We are exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by a settlement agreement in West
Virginia. To the extent the fuel supply of the generating units in these states
is not under fixed price long-term contracts we are subject to market price
risk. We continue to be protected against market price changes by active fuel
clauses in Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of
Texas. Fuel clauses are active again in Michigan and Texas, effective January 1,
2004 and March 1, 2004, respectively.

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


<PAGE>
<TABLE>
<CAPTION>


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

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

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

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

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

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

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

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

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

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

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

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


See Notes to Consolidated Financial Statements.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>

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

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

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

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

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

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

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


See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>



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

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

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

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

Liabilities Held for Sale                                                                   1,876                  1,279
Liabilities of Discontinued Operations                                                          -                     12

TOTAL LIABILITIES                                                                          28,809                 27,601
                                                                                          --------               --------

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

Commitments and Contingencies

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

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

* See Accompanying Schedules

See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>


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

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

                       INVESTING ACTIVITIES
---------------------------------------------------------------------------
Construction Expenditures                                                                  (1,358)         (1,685)       (1,646)
Business Acquisitions                                                                           -               -        (1,269)
Investment in Discontinued Operations, net                                                   (615)              -          (983)
Proceeds from Sale of Assets                                                                   82           1,263           648
Other                                                                                           3              44           (42)

                                                                                           -------         -------       -------
Net Cash Flows Used For Investing Activities                                               (1,888)           (378)       (3,292)
                                                                                           -------         -------       -------

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

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

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

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

See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


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

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

           COMPREHENSIVE INCOME (LOSS)
------------------------------------------------
Other Comprehensive Income (Loss), Net of Taxes:
     Foreign Currency Translation Adjustments                                                                  (14)         (14)
     Unrealized Losses on Cash Flow Hedges                                                                      (3)          (3)
     Minimum Pension Liability                                                                                  (6)          (6)
NET INCOME                                                                                         971                      971
                                                                                                                         -------
TOTAL COMPREHENSIVE INCOME                                                                                                  948
                                                               -----    -------     -------     -------      ------      -------
DECEMBER 31, 2001                                               331     $2,153      $2,906      $3,296       $(126)      $8,229

Issuance of Common Stock                                         17        108         568                                  676
Common Stock Dividends                                                                            (793)                    (793)
Common Stock Expense                                                                   (30)                                 (30)
Other                                                                                  (31)         15                      (16)
                                                                                                                         -------
TOTAL                                                                                                                     8,066
                                                                                                                         -------

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

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

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


See Notes to Consolidated Financial Statements.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>


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


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

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

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

                                                                            December 31, 2002
                                            --------------------------------------------------------------------------------
                                                  Call                 Shares                Shares                Amount
                                            Price Per Share(a)      Authorized(b)         Outstanding(d)       (in millions)
                                            ------------------      -------------         --------------       -------------
<C>                                            <C>                   <C>                      <C>                    <C>
Not Subject to Mandatory  Redemption:
  4.00% - 5.00%                                $102-$110             1,525,903                608,150                 $61
                                                                                                                     ----

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                                 $100             1,950,000                333,100                  33
  6.02% - 6.875% (c)                                $100             1,650,000                513,450                  51
                                                                                                                     ----
Total Subject to Mandatory
 Redemption (c)                                                                                                        84
                                                                                                                     ----

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

 (a)    At the option of the subsidiary,  the shares may be redeemed at the call
        price plus accrued dividends.  The involuntary liquidation preference is
        $100 per share for all outstanding shares.
 (b)    As of December 31, 2003, the subsidiaries had 13,780,352  shares of
        $100 par value preferred stock, 22,200,000 shares of $25 par value
        preferred stock and 7,768,561 shares of no par value preferred stock
        that were authorized but unissued.
 (c)    Shares outstanding and related amounts are stated net of applicable
        retirements through sinking funds (generally at par) and reacquisitions
        of shares in anticipation of future requirements. The subsidiaries
        reacquired enough shares in 1997 to meet all sinking fund requirements
        on certain series until 2008 and on certain series until 2009 when all
        remaining outstanding shares must be redeemed.
 (d)    The number of shares of preferred stock redeemed is 86,210 shares in
        2003, 106,458 shares in 2002 and 50,000 shares in 2001.
 (e)    Due to the implementation of SFAS 150 in July 2003, Cumulative Preferred
        Stocks of Subsidiaries is no longer presented as one line item on the
        balance sheet. SFAS 150 has required us to present Cumulative Preferred
        Stocks of Subsidiaries Subject to Mandatory Redemption as a liability.
        Cumulative Preferred Stocks of Subsidiaries Not Subject to Mandatory
        Redemption will continue to be reported on the balance sheet in the
        "mezzanine" section.

<PAGE>
<TABLE>
<CAPTION>


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

                                                     Weighted Average
Maturity                                               Interest Rate        Interest Rates at December 31,          December 31,
--------                                             -----------------      ------------------------------       ----------------
                                                     December 31, 2003         2003               2002           2003        2002
                                                     -----------------         ----               ----           ----        ----
                                                                                                                   (in millions)
<C>                                                       <C>             <C>                 <C>             <C>          <C>
FIRST MORTGAGE BONDS (a)
  2003-2004                                               7.40%            6.125%-7.85%        6.00%-7.85%       $231        $648
  2005-2008                                               6.90%             6.20%-8.00%        6.20%-8.00%        463         463
  2022-2025                                               7.28%            6.875%-8.00%       6.875%-8.70%        246         773

INSTALLMENT PURCHASE CONTRACTS (b)(f)
2003-2009                                                 3.74%            2.15%-6.90%         3.75%-7.70%        395         396
2011-2030                                                 4.92%            1.10%-8.20%         1.35%-8.20%      1,631       1,284

NOTES PAYABLE (c)(f)
2003-2017                                                 5.20%            1.537%-15.45%      6.225%-9.60%      1,518         214

SENIOR UNSECURED NOTES
2003-2005                                                 5.10%             2.43%-7.45%        2.12%-7.45%      1,359       1,834
2006-2015                                                 5.49%             3.60%-6.91%        4.31%-6.91%      4,873       2,295
2032-2038                                                 6.41%            5.625%-7.375%       6.00%-7.375%     1,765         690

JUNIOR DEBENTURES
2025-2038                                                    -                   -             7.60%-8.72%          -         205

SECURITIZATION BONDS
2005-2016                                                 5.53%            3.54%-6.25%         3.54%-6.25%        746         797

NOTES PAYABLE TO TRUST (d)
2037-2043                                                 7.06%             5.25-8.00%              -             331           -

EQUITY UNIT SENIOR NOTES (e)
2007                                                      5.75%               5.75%               5.75%           345         345

OTHER LONG-TERM DEBT (g)                                                                                          247         247

Equity Unit Contract Adjustment Payments                                                                           19          31
Unamortized Discount (net)                                                                                        (68)        (32)
                                                                                                              --------     -------
Total Long-term Debt Outstanding                                                                               14,101      10,190
Less Portion Due Within One Year                                                                                1,779       1,327
                                                                                                              --------     -------
Long-term Portion                                                                                             $12,322      $8,863
                                                                                                              ========     =======

</TABLE>

(a)   First mortgage bonds are secured by first mortgage liens on electric
      property, plant and equipment.
(b)   For certain series of installment purchase contracts, interest rates are
      subject to periodic adjustment. Certain series will be purchased on demand
      at periodic interest adjustment dates. Letters of credit from banks and
      standby bond purchase agreements support certain series.
(c)   Notes payable represent outstanding promissory notes issued under term
      loan agreements and revolving credit agreements with a number of banks and
      other financial institutions. At expiration, all notes then issued and
      outstanding are due and payable. Interest rates are both fixed and
      variable. Variable rates generally relate to specified short-term interest
      rates.
(d)   Notes Payable to Trust is a result of a deconsolidation of TCC, PSO and
      SWEPCo's trusts effective July 1, 2003 due to the implementation of FIN
      46.  See Notes 2 and 17 for further information.
(e)   In May 2005, the interest rate on these Equity Unit Senior Notes can be
      reset through a remarketing.
(f)   Installment Purchase Contracts and Notes Payable include $257 million and
      $185 million, respectively, due to the implementation of FIN 46 (see Note
      2).  Notes Payable includes $496 million of a merchant power generation
      facility which was consolidated as of December 31, 2003 (see Notes 10 and
      16).
(g)   Other long-term debt consists of a liability along with accrued interest
      for disposal of spent nuclear fuel (see Note 7) and a financing obligation
      under a sale and leaseback agreement.


<TABLE>
<CAPTION>

LONG-TERM DEBT OUTSTANDING AT DECEMBER 31, 2003 IS PAYABLE AS FOLLOWS:
----------------------------------------------------------------------

                                             2004        2005        2006         2007        2008    Later Years         TOTAL
                                             ----        ----        ----         ----        ----    -----------         -----
                                                                             (in millions)
<C>                                        <C>         <C>         <C>          <C>           <C>         <C>           <C>
Principal Amount                           $1,779      $1,273      $2,187       $1,124        $587        $7,200        $14,150
Equity Unit Contract Adjustment Payments                                                                                     19
Unamortized Discount                                                                                                        (68)
                                                                                                                        --------
                                                                                                                        $14,101
                                                                                                                        ========
</TABLE>

<PAGE>


             AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES
               INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
             ------------------------------------------------------


           1. Organization and Summary of Significant Accounting Policies

           2. New Accounting Pronouncements, Extraordinary Items and Cumulative
              Effect of Accounting Changes

           3. Goodwill and Other Intangible Assets

           4. Rate Matters

           5. Effects of Regulation

           6. Customer Choice and Industry Restructuring

           7. Commitments and Contingencies

           8. Guarantees

           9. Sustained Earnings Improvement Initiative

          10. Acquisitions, Dispositions, Discontinued Operations, Impairments,
              Assets Held for Sale and Assets Held and Used

          11. Benefit Plans

          12. Stock-Based Compensation

          13. Business Segments

          14. Derivatives, Hedging and Financial Instruments

          15. Income Taxes

          16. Leases

          17. Financing Activities

          18. Unaudited Quarterly Financial Information

          19. Subsequent Events (Unaudited)


<PAGE>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
         --------------------------------------------------------------


1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
---------------------------------------------------------------


ORGANIZATION
------------

Our principal business conducted by our eleven domestic electric utility
operating companies is the generation, transmission and distribution of electric
power. These companies are subject to regulation by the FERC under the Federal
Power Act and maintain accounts in accordance with FERC and other regulatory
guidelines. These companies are subject to further regulation with regard to
rates and other matters by state regulatory commissions.

We also engage in wholesale electricity, natural gas and other commodity
marketing and risk management activities in the United States and Europe. In
addition, our domestic operations include non-regulated independent power and
cogeneration facilities, coal mining and intra-state natural gas operations in
Louisiana and Texas.

International operations include the generation and supply of power in the
United Kingdom, and to a lesser extent in Mexico, Australia and China. These
operations are either wholly-owned or partially-owned by our various
subsidiaries.

We also conduct domestic barging operations, provide various energy related
services and furnish communications-related services domestically.

During 2003 we announced plans to significantly restructure and dispose of many
of our non-regulated operations. See Note 10 for a discussion of the impacts of
these plans on our organization.

Certain previously reported amounts have been reclassified to conform to current
classifications with no effect on net income or shareholders' equity.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------

Rate Regulation
---------------

We are subject to regulation by the SEC under the PUHCA. The rates charged by
the domestic utility subsidiaries are approved by the FERC and the state
utility commissions. The FERC regulates wholesale electricity operations and
transmission rates and the state commissions regulate retail rates. The prices
charged by foreign subsidiaries located in China and Mexico are regulated by
the authorities of those countries and are generally subject to price controls.

Principles of Consolidation
---------------------------

Our consolidated financial statements include AEP and its wholly-owned and
majority-owned subsidiaries consolidated with their wholly-owned subsidiaries or
substantially controlled variable interest entities. Intercompany items are
eliminated in consolidation. Equity investments not substantially controlled
that are 50% or less owned are accounted for using the equity method of
accounting; equity earnings are included in Other Income. We also have
generating units that are jointly owned with unaffiliated companies. The
proportionate share of the operating costs associated with such facilities is
included in our Consolidated Statements of Operations and the investments are
reflected in our Consolidated Balance Sheets.

Accounting for the Effects of Cost-Based Regulation
---------------------------------------------------

As the owner of cost-based rate-regulated electric public utility companies, our
consolidated financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time periods than
enterprises that are not rate-regulated. Regulatory assets (deferred expenses)
and regulatory liabilities (future revenue reductions or refunds) are recorded
to reflect the economic effects of regulation by matching expenses with their
recovery through regulated revenues. We discontinued the application of SFAS 71
for the generation portion of our business as follows: in Ohio by OPCo and CSPCo
in September 2000, in Virginia and West Virginia by APCo in June 2000, in Texas
by TCC, TNC, and SWEPCo in September 1999, in Arkansas by SWEPCo in September
1999 and in the FERC jurisdiction for TNC in December 2003. During 2003, APCo
reapplied SFAS 71 for West Virginia and SWEPCo reapplied SFAS 71 for Arkansas.

Use of Estimates
----------------

The preparation of these financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the amounts reported in
the financial statements and accompanying notes. These estimates include but are
not limited to inventory valuation, allowance for doubtful accounts, goodwill
and intangible asset impairment, unbilled electricity revenue, values of
long-term energy contracts, the effects of regulation, long-lived asset
recovery, the effects of contingencies and certain assumptions made in
accounting for pension benefits. Actual results could differ from those
estimates.

Property, Plant and Equipment
-----------------------------

Domestic electric utility property, plant and equipment are stated at original
purchase cost. Property, plant and equipment of the non-regulated operations and
other investments are stated at their fair market value at acquisition (or as
adjusted for any applicable impairments) plus the original cost of property
acquired or constructed since the acquisition, less disposals. Additions, major
replacements and betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and associated
removal costs, net of salvage, are deducted from accumulated depreciation. For
non-regulated operations, retirements from the plant accounts and associated
salvage are deducted from accumulated depreciation and removal costs are charged
to expense. The costs of labor, materials and overhead incurred to operate and
maintain plant are included in operating expenses. Assets are tested for
impairment as required under SFAS 144 (see Note 10).

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
--------------------------------------------------------------------------------

AFUDC represents the estimated cost of borrowed and equity funds used to finance
construction projects that is capitalized and recovered through depreciation
over the service life of domestic regulated electric utility plant. For
non-regulated operations, interest is capitalized during construction in
accordance with SFAS 34, "Capitalization of Interest Costs." Capitalized
interest is also recorded for domestic generating assets in Ohio, Texas and
Virginia, effective with the discontinuance of SFAS 71 regulatory accounting.
The amounts of AFUDC and interest capitalized were not material in 2003, 2002
and 2001.

Depreciation, Depletion and Amortization
----------------------------------------

We provide for depreciation of property, plant and equipment on a straight-line
basis over the estimated useful lives of property, excluding coal-mining
properties, generally using composite rates by functional class as follows:

<TABLE>
<CAPTION>

Functional Class of Property                                    Annual Composite Depreciation Rates Ranges
----------------------------                          ----------------------------------------------------------
                                                           2003                  2002                   2001
                                                      --------------         -------------         -------------
<C>                                                    <C>                   <C>                   <C>
Production:
  Steam-Nuclear                                        2.5% to  3.4%         2.5% to  3.4%         2.5% to  3.4%
  Steam-Fossil-Fired                                   2.3% to  4.6%         2.6% to  4.5%         2.5% to  4.5%
  Hydroelectric-Conventional
   and Pumped Storage                                  1.9% to  3.4%         1.9% to  3.4%         1.9% to  3.4%
Transmission                                           1.7% to  2.8%         1.7% to  3.0%         1.7% to  3.1%
Distribution                                           3.3% to  4.2%         3.3% to  4.2%         2.7% to  4.2%
Other                                                  1.8% to 16.7%         1.8% to  9.9%         1.8% to 15.0%

</TABLE>

We provide for depreciation, depletion and amortization of coal-mining assets
over each asset's estimated useful life or the estimated life of each mine,
whichever is shorter, using the straight-line method for mining structures and
equipment. We use either the straight-line method or the units-of-production
method to amortize mine development costs and deplete coal rights based on
estimated recoverable tonnages. We include these costs in the cost of coal
charged to fuel expense. Average amortization rates for coal rights and mine
development costs were $0.25 per ton in 2003, $0.32 per ton in 2002 and $2.06
per ton in 2001. In 2002, certain coal-mining assets were impaired by $60
million leading to the decline in amortization rates in 2003. In 2001, an AEP
subsidiary sold coal mines in Ohio and West Virginia leading to the decline in
amortization rates in 2002.

Valuation of Non-Derivative Financial Instruments
-------------------------------------------------

The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term
Debt and Accounts Payable approximate fair value because of the short-term
maturity of these instruments. The book value of the pre-April 1983 spent
nuclear fuel disposal liability approximates the best estimate of its fair
value.

Cash and Cash Equivalents
-------------------------

Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.

Inventory
---------

Except for PSO, TCC and TNC, the regulated domestic utility companies value
fossil fuel inventories using a weighted average cost method. PSO, TCC and TNC,
utilize the LIFO method to value fossil fuel inventories. For those domestic
utilities whose generation is unregulated, inventory of coal and oil is carried
at the lower of cost or market. Coal mine inventories are also carried at the
lower of cost or market. Materials and supplies inventories are carried at
average cost. Non-trading gas inventory is carried at the lower of cost or
market. During 2003 a fair value hedging strategy was implemented for certain
non-trading gas and coal inventory. Changes in the fair value of hedged
inventory are recorded to the extent offsetting hedges are designated against
that inventory.

Accounts Receivable
-------------------

Customer accounts receivable primarily includes receivables from wholesale and
retail energy customers, receivables from energy contract counterparties related
to our risk management activities and customer receivables primarily related to
other revenue-generating activities.

We recognize revenue from electric power and gas sales when we deliver power or
gas to our customers. To the extent that deliveries have occurred but a bill has
not been issued, we accrue and recognize, as Accrued Unbilled Revenues, an
estimate of the revenues for energy delivered since the latest billings.

AEP Credit, Inc. factors accounts receivable for certain registrant
subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and
a portion of APCo. Since APCo does not have regulatory authority to sell
accounts receivable in all of its regulatory jurisdictions, only a portion of
APCo's accounts receivable are sold to AEP Credit. AEP Credit has a sale of
receivables agreement with banks and commercial paper conduits. Under the sale
of receivables agreement, AEP Credit sells an interest in the receivables it
acquires to the commercial paper conduits and banks and receives cash. This
transaction constitutes a sale of receivables in accordance with SFAS 140,
allowing the receivables to be taken off of the company's balance sheet. See
Note 17 "Financing Activities" for further details.

Foreign Currency Translation
----------------------------

The financial statements of subsidiaries outside the U.S. which are included in
our consolidated financial statements are measured using the local currency as
the functional currency and translated into U.S. dollars in accordance with SFAS
52 "Foreign Currency Translation." Although the effects of foreign currency
fluctuations are mitigated by the fact that expenses of foreign subsidiaries are
generally incurred in the same currencies in which sales are generated, the
reported results of operations of our foreign subsidiaries are affected by
changes in foreign currency exchange rates and, as compared to prior periods,
will be higher or lower depending upon a weakening or strengthening of the U.S.
dollar. Revenues and expenses are translated at monthly average foreign currency
exchange rates throughout the year. Assets and liabilities are translated into
U.S. dollars at year-end foreign currency exchange rates. Accordingly, our
consolidated common shareholders' equity will fluctuate depending on the
relative strengthening or weakening of the U.S. dollar versus relevant foreign
currencies. Currency translation gain and loss adjustments are recorded in
shareholders' equity as Accumulated Other Comprehensive Income (Loss). The
impact of the changes in exchange rates on cash, resulting from the translation
of items at different exchange rates, is shown on our Consolidated Statements of
Cash Flows in Effect of Exchange Rate Change on Cash. Actual currency
transaction gains and losses are recorded in income when they occur.

Deferred Fuel Costs
-------------------

The cost of fuel consumed is charged to expense when the fuel is burned. Where
applicable under governing state regulatory commission retail rate orders, fuel
cost over-recoveries (the excess of fuel revenues billed to ratepayers over fuel
costs incurred) are deferred as regulatory liabilities and under-recoveries (the
excess of fuel costs incurred over fuel revenues billed to ratepayers) are
deferred as regulatory assets. These deferrals are amortized when refunded or
billed to customers in later months with the regulator's review and approval.
The amounts of an over-recovery or under-recovery can also be affected by
actions of regulators. When these actions become probable we adjust our
deferrals to recognize these probable outcomes. The amount of under-recovered
fuel costs deferred under fuel clauses as a regulatory asset was $51 million at
December 31, 2003 and $148 million at December 31, 2002. The amount of
over-recovered fuel costs deferred under fuel clauses as a regulatory liability
was $132 million at December 31, 2003 and $90 million at December 31, 2002. See
Note 5 "Effects of Regulation" for further information.

In general, changes in fuel costs in Kentucky for KPCo, the SPP area of Texas,
Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for APCo are
timely reflected in rates through the fuel cost adjustment clauses in place in
those states. Where fuel clauses have been eliminated due to the transition to
market pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area
effective January 1, 2002) changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes have also
impacted earnings. The Michigan fuel clause suspension ended December 31, 2003,
and the Indiana freeze is scheduled to end on March 1, 2004. Changes in fuel
costs also impact earnings for certain of our Independent Power Producer
generating units that do not have long-term contracts for their fuel supply. See
Note 4, "Rate Matters" and Note 6, "Customer Choice and Industry Restructuring"
for further information about fuel recovery.

Revenue Recognition
-------------------

Regulatory Accounting
---------------------

Our consolidated financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate-regulated. Regulatory assets (deferred
expenses to be recovered in the future) and regulatory liabilities (deferred
future revenue reductions or refunds) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues in the same accounting period and by matching income with its passage
to customers through regulated revenues in the same accounting period.
Regulatory liabilities or regulatory assets are also recorded for unrealized
gains or losses that occur due to changes in the fair value of physical and
financial contracts that are derivatives and that are subject to the regulated
ratemaking process.

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

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

Revenues are recognized on the accrual or settlement basis for normal retail and
wholesale electricity supply sales and electricity transmission and distribution
delivery services. The revenues are recognized in our statement of operations
when the energy is delivered to the customer and include unbilled as well as
billed amounts. In general, expenses are recorded when purchased electricity is
received and when expenses are incurred.

Domestic Gas Pipeline and Storage Activities
--------------------------------------------

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

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

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

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

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

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

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

We use the mark-to-market method of accounting for derivative contracts.
Unrealized gains and losses prior to settlement, resulting from revaluation of
these contracts to fair value during the period, are recognized currently. When
the derivative contracts are settled and gains and losses are realized, the
previously recorded unrealized gains and losses from mark-to-market valuations
are reversed.

Certain derivative instruments are designated as a hedge of a forecasted
transaction or future cash flow (cash flow hedge) or as a hedge of a recognized
asset, liability or firm commitment (fair value hedge). The gains or losses on
derivatives designated as fair value hedges are recognized in Revenues in the
Consolidated Statement of Operations in the period of change together with the
offsetting losses or gains on the hedged item attributable to the risks being
hedged. For derivatives designated as cash flow hedges, the effective portion of
the derivative's gain or loss is initially reported as a component of
Accumulated Other Comprehensive Income and subsequently reclassified into
Revenues in the Consolidated Statement of Operations when the forecasted
transaction affects earnings. The ineffective portion of the gain or loss is
recognized in Revenues in the Consolidated Statement of Operations immediately
(see Note 14).

The fair values of derivative instruments accounted for using mark-to-market
accounting or hedge accounting are based on exchange prices and broker quotes.
If a quoted market price is not available, the estimate of fair value is based
on the best information available including valuation models that estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
the appropriate valuation adjustments for items such as discounting, liquidity
and credit quality. Credit risk is the risk that the counterparty to the
contract will fail to perform or fail to pay amounts due. Liquidity risk
represents the risk that imperfections in the market will cause the price to be
less than or more than what the price should be based purely on supply and
demand. There are inherent risks related to the underlying assumptions in models
used to fair value open long-term risk management contracts. We have independent
controls to evaluate the reasonableness of our valuation models. However, energy
markets, especially electricity markets, are imperfect and volatile. Unforeseen
events can and will cause reasonable price curves to differ from actual prices
throughout a contract's term and at the time a contract settles. Therefore,
there could be significant adverse or favorable effects on future results of
operations and cash flows if market prices are not consistent with our approach
at estimating current market consensus for forward prices in the current period.
This is particularly true for long-term contracts.

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

Construction Projects for Outside Parties
-----------------------------------------

Our entities engage in construction projects for outside parties that are
accounted for on the percentage-of-completion method of revenue recognition.
This method recognizes revenue in proportion to costs incurred compared to total
estimated costs.

Debt Instrument Hedging and Related Activities
----------------------------------------------

In order to mitigate the risks of market price and interest rate fluctuations,
we enter into contracts to manage the exposure to unfavorable changes in the
cost of debt to be issued. These anticipatory hedges are entered into in order
to manage the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60 days). Gains or
losses from these transactions are deferred and amortized over the life of the
debt issuance with the amortization included in interest charges. There were no
such forward contracts outstanding at December 31, 2003 or 2002.

Maintenance
-----------

Maintenance costs are expensed as incurred. If it becomes probable that we will
recover specifically incurred costs through future rates a regulatory asset is
established to match the expensing of maintenance costs with their recovery in
cost-based regulated revenues.

Other Income and Other Expenses
-------------------------------

Non-operational revenue including the nonregulated business activities of our
utilities, equity earnings of non-consolidated subsidiaries, gains on
dispositions of property, interest and dividends, AFUDC and miscellaneous
income, are reported in Other Income. Non-operational expenses including
nonregulated business activities of our utilities, losses on dispositions of
property, miscellaneous amortization, donations and various other non-operating
and miscellaneous expenses, are reported in Other Expenses.

<TABLE>
<CAPTION>

AEP Consolidated Other Income and Deductions:
---------------------------------------------

                                                                       December 31,
                                                          2003             2002             2001
                                                         ------          -------           -----
                                                                      (in millions)
<C>                                                       <C>              <C>              <C>
Other Income:
-------------
Equity Earnings (Loss)                                     $10             $(15)             $30
Non-operational Revenue                                    129              201              184
Interest                                                    42               26               48
Gain on Sale of Frontera                                     -               -                73
Gain on Sale of REPs (Mutual Energy Companies)              39              129                -
Other                                                      167              120               36
                                                          -----            -----            -----
Total Other Income                                        $387             $461             $371
                                                          =====            =====            =====



Other Expenses:
---------------
Property Taxes                                             $20              $20              $15
Non-operational Expenses                                   112              179               76
Fiber Optic and Datapult Exit Costs                          -                -               49
Provision for Loss - Airplane                                -                -               14
Other                                                       95              124               71
                                                          -----            -----            -----
Total Other Expenses                                      $227             $323             $225
                                                          =====            =====            =====

</TABLE>

Income Taxes and Investment Tax Credits
---------------------------------------

We use the liability method of accounting for income taxes. Under the liability
method, deferred income taxes are provided for all temporary differences between
the book and tax basis of assets and liabilities which will result in a future
tax consequence.

When the flow-through method of accounting for temporary differences is
reflected in regulated revenues (that is, when deferred taxes are not included
in the cost of service for determining regulated rates for electricity),
deferred income taxes are recorded and related regulatory assets and liabilities
are established to match the regulated revenues and tax expense.

Investment tax credits have been accounted for under the flow-through method
except where regulatory commissions have reflected investment tax credits in the
rate-making process on a deferral basis. Investment tax credits that have been
deferred are being amortized over the life of the regulated plant investment.

Excise Taxes
------------

We act as an agent for some state and local governments and collect from
customers certain excise taxes levied by those state or local governments on our
customer. We do not recognize these taxes as revenue or expense.

Debt and Preferred Stock
------------------------

Gains and losses from the reacquisition of debt used to finance domestic
regulated electric utility plant are generally deferred and amortized over the
remaining term of the reacquired debt in accordance with their rate-making
treatment unless the debt is refinanced. If the reacquired debt, associated with
the regulated business, is refinanced, the reacquisition costs attributable to
the portions of the business that are subject to cost based regulatory
accounting are generally deferred and amortized over the term of the replacement
debt consistent with its recovery in rates. We report gains and losses on the
reacquisition of debt for operations that are not subject to cost-based rate
regulation in Other Income and Other Expenses.

Debt discount or premium and debt issuance expenses are deferred and amortized
utilizing the effective interest rate method over the term of the related debt.
The amortization expense is included in interest charges.

Where reflected in rates, redemption premiums paid to reacquire preferred stock
of certain domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.

Goodwill and Intangible Assets
------------------------------

When we acquire businesses we record the fair value of any acquired goodwill and
other intangible assets. Purchased goodwill and intangible assets with
indefinite lives are not amortized. We test acquired goodwill and other
intangible assets with indefinite lives for impairment at least annually.
Intangible assets with finite lives are amortized over their respective
estimated lives to their estimated residual values.

The policies described above became effective with our adoption of a new
accounting standard for goodwill (SFAS 142). For all business combinations with
an acquisition date before July 1, 2001, we amortized goodwill and intangible
assets with indefinite lives through December 2001, and then ceased
amortization. The goodwill associated with those business combinations with an
acquisition date before July 1, 2001 was amortized on a straight-line basis
generally over 40 years except for the portion of goodwill associated with gas
trading and marketing activities which was amortized on a straight-line basis
over 10 years. Intangible assets with finite lives continue to be amortized over
their respective estimated lives ranging from 2 to 10 years.

Nuclear Trust Funds
-------------------

Nuclear decommissioning and spent nuclear fuel trust funds represent funds that
regulatory commissions have allowed us to collect through rates to fund future
decommissioning and spent fuel disposal liabilities. By rules or orders, the
state jurisdictional commissions (Indiana, Michigan and Texas) and the FERC have
established investment limitations and general risk management guidelines. In
general, limitations include:

  o     Acceptable investments (rated investment grade or above)
  o     Maximum percentage invested in a specific type of investment
  o     Prohibition of investment in obligations of the applicable company or
        its affiliates

Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers external to AEP, who must comply with the guidelines and
rules of the applicable regulatory authorities. The trust assets are invested in
order to optimize the after-tax earnings of the trust, giving consideration to
liquidity, risk, diversification, and other prudent investment objectives.

Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Spent Nuclear Fuel and
Decommissioning Trusts for amounts relating to the Cook Plant and are included
in Assets Held for Sale for amounts relating to the Texas Plants. See "Assets
Held for Sale" section of Note 10 for further information regarding the Texas
Plants. These securities are recorded at market value. Securities in the trust
funds have been classified as available-for-sale due to their long-term purpose.
Unrealized gains and losses from securities in these trust funds are reported as
adjustments to the regulatory liability account for the nuclear decommissioning
trust funds and to regulatory assets or liabilities for the spent nuclear fuel
disposal trust funds in accordance with their treatment in rates.

Comprehensive Income (Loss)
---------------------------

Comprehensive income (loss) is defined as the change in equity (net assets) of a
business enterprise during a period from transactions and other events and
circumstances from non-owner sources. It includes all changes in equity during a
period except those resulting from investments by owners and distributions to
owners. Comprehensive income (loss) has two components: net income (loss) and
other comprehensive income (loss).

Components of Accumulated Other Comprehensive Income (Loss)
-----------------------------------------------------------

Accumulated Other Comprehensive Income (Loss) is included on the balance sheet
in the equity section. The following table provides the components that
constitute the balance sheet amount in Accumulated Other Comprehensive Income
(Loss):
<TABLE>
<CAPTION>

                                                                            December 31,
                                                                  --------------------------------
Components                                                         2003         2002         2001
----------                                                        -------      ------       ------
                                                                            (in millions)
<C>                                                               <C>           <C>          <C>
Foreign Currency Translation Adjustments                           $110            $4        $(113)
Unrealized Losses on Securities Available for Sale                   (1)           (2)           -
Unrealized Losses on Cash Flow Hedges                               (94)          (16)          (3)
Minimum Pension Liability                                          (441)         (595)         (10)
                                                                  ------        ------       ------
Total                                                             $(426)        $(609)       $(126)
                                                                  ======        ======       ======
</TABLE>

Stock Based Compensation Plans
------------------------------

At December 31, 2003, we have two stock-based employee compensation plans with
outstanding stock options, which are described more fully in Note 12. No stock
option expense is reflected in our earnings, as all options granted under these
plans had exercise prices equal to or above the market value of the underlying
common stock on the date of grant.

We also grant performance share units, phantom stock units, restricted shares
and restricted stock units to employees, as well as stock units to non-employee
members of the Board of Directors. The Deferred Compensation and Stock Plan for
Non-Employee Directors permits directors to choose to defer up to 100 percent of
their annual Board retainer in stock units, and the Stock Unit Accumulation Plan
for Non-Employee Directors awards stock units to directors. Compensation cost is
included in Net Income for the performance share units, phantom stock units,
restricted shares, restricted stock units and the Director's stock units.

We do not currently intend to adopt the fair-value-based method of accounting
for stock options. The following table shows the effect on our Net Income (Loss)
and Earnings (Loss) per Share as if we had applied fair value measurement and
recognition provisions of FASB Statement No. 123, "Accounting for Stock-Based
Compensation," to stock-based employee compensation awards:

<TABLE>
<CAPTION>

                                                                                  Year Ended December 31,
                                                                              -------------------------------
                                                                               2003        2002        2001
                                                                              ------      ------      ------
                                                                           (in millions, except per share data)

           <C>                                                                <C>        <C>          <C>
           Net Income (Loss), as reported                                      $110       $(519)       $971
           Add:  Stock-based compensation expense included in
            reported net income, net of related tax effects                       2          (5)          3
           Deduct:  Stock-based employee compensation expense
            determined under fair value based method for all
           awards, net of related tax effects                                    (7)         (4)        (15)
                                                                               -----      ------       -----
           Pro Forma Net Income (Loss)                                         $105       $(528)       $959
                                                                               =====      ======       =====

           Earnings (Loss) per Share:
            Basic - as Reported                                               $0.29      $(1.57)      $3.01
            Basic - Pro Forma (a)                                             $0.27      $(1.59)      $2.98

            Diluted - as Reported                                             $0.29      $(1.57)      $3.01
            Diluted - Pro Forma (a)                                           $0.27      $(1.59)      $2.97

           (a)   The pro forma amounts are not representative of the effects on
                 reported net income for future years.
</TABLE>

Earnings Per Share (EPS)
------------------------

Basic earnings (loss) per common share is calculated by dividing net earnings
(loss) available to common shareholders by the weighted average number of common
shares outstanding during the period. Diluted earnings (loss) per common share
is calculated by adjusting the weighted average outstanding common shares,
assuming conversion of all potentially dilutive stock options and awards. The
effects of stock options have not been included in the fiscal 2002 diluted loss
per common share calculation as their effect would have been anti-dilutive.

The calculation of our basic and diluted earnings (loss) per common share (EPS)
is based on weighted average common shares shown in the table below:

<TABLE>
<CAPTION>

                                                                                      2003            2002            2001
                                                                                     ------          ------          ------
                                                                                    (in millions - except per share amounts)
<C>                                                                                     <C>             <C>              <C>
Weighted Average Shares:
Average Common Shares Outstanding                                                       385             332              322
Assumed Conversion of Dilutive Stock Options (see Note 12)                                -               -                1
                                                                                        ---             ---              ---
Diluted Average Common Shares Outstanding                                               385             332              323
                                                                                        ===             ===              ===
</TABLE>

The assumed conversion of stock options does not affect net earnings (loss) for
purposes of calculating diluted earnings per share. Our basic and diluted EPS
are the same in 2003, 2002 and 2001 since the effect on weighted average common
shares outstanding is minimal.

Had we reported net income in fiscal 2002, incremental shares attributable to
the assumed exercise of outstanding stock options would have increased diluted
common shares outstanding by 398,000 shares.

Options to purchase 5.6 million, 8.8 million and 0.7 million shares of common
stock were outstanding at December 31, 2003, 2002 and 2001, respectively, but
were not included in the computation of diluted earnings per share because the
options' exercise prices were greater than the year-end market price of the
common shares and, therefore, the effect would be antidilutive.

In addition, there is no effect on diluted earnings per share related to our
equity units (issued in 2002) unless the market value of our common stock
exceeds $49.08 per share. There were no dilutive effects from equity units at
December 31, 2003 and 2002. If our common stock value exceeds $49.08 we would
apply the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that the
proceeds received as a result of the forward purchase contracts are used to
repurchase outstanding shares. Also see Note 17.

Supplementary Information
-------------------------
<TABLE>
<CAPTION>

                                                                                         Year Ended December 31,
                                                                                      2003        2002         2001
                                                                                      ----        ----         ----
                                                                                              (in millions)
<C>                                                                                    <C>           <C>        <C>
AEP Consolidated Purchased Power -
 Ohio Valley Electric Corporation
  (44.2% owned by AEP System)                                                          $147          $142       $127

Cash was paid for:
  Interest (net of capitalized amounts)                                                $741          $792       $972
  Income Taxes                                                                         $163          $336       $569
Noncash Investing and Financing Activities:
 Acquisitions under Capital Leases                                                      $25            $6        $17
 Assumption of Liabilities Related to Acquisitions                                       $-            $1       $171
 Increase in assets and liabilities resulting from:
   Consolidation of VIEs due to the adoption of  FIN 46 (see Note 2)                   $547            $-         $-
   Consolidation of merchant power generation facility (see Note 16)                   $496            $-         $-
 Exchange of Communication Investment for Common Stock                                   $-            $-         $5

</TABLE>

Power Projects
--------------

We own interests of 50% or less in domestic unregulated power plants with a
capacity of 1,043 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, we have interests of 50% or less in international power
plants totaling 1,113 MW (see Note 10, "Acquisitions, Dispositions, Discontinued
Operations, Impairments, Assets Held for Sale and Assets Held and Used").

Investments in power projects that are 50% or less owned are accounted for by
the equity method and reported in Investments in Power and Distribution Projects
on our Consolidated Balance Sheets (see "Eastex" within the Dispositions section
of Note 10). At December 31, 2003, five domestic power projects and three
international power investments are accounted for under the equity method. The
five domestic projects are combined cycle gas turbines that provide steam to a
host commercial customer and are considered either Qualifying Facilities (QFs)
or Exempt Wholesale Generators (EWGs) under PURPA. The three international power
investments are classified as Foreign Utility Companies (FUCO) under the Energy
Policies Act of 1992. Two of the international investments are power projects
and the other international investment is a company which owns an interest in
four additional power projects. All of the power projects accounted for under
the equity method have unrelated third-party partners.

Seven of the above power projects have project-level financing, which is
non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $8 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits. In addition, AEP has
issued letters of credit with maximum future payments of $23 million for
domestic power projects and $69 million for international power investments.

Reclassifications
-----------------

Certain prior period financial statement items have been reclassified to conform
to current period presentation. Such reclassifications had no impact on
previously reported Net Income (Loss).


2.  NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF
    ACCOUNTING CHANGES
-------------------------------------------------------------------------------


NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------

SFAS 132 (revised 2003) "Employers' Disclosure about Pensions and Other
Postretirement Benefits"
-----------------------------------------------------------------------

In December 2003 the FASB issued SFAS 132 (revised 2003), which requires
additional footnote disclosures about pensions and postretirement benefits, some
of which are effective beginning with the year-end 2003 financial statements.
Other additional disclosures will begin with our 2004 quarterly financial
statements or our 2004 year-end financial statements.

We will implement new quarterly disclosures when they become effective in the
first quarter of 2004, including (a) the amount of net periodic benefit cost for
each period for which an income statement is presented, showing separately each
component thereof, and (b) the amount of employer contributions paid and
expected to be paid during the current year, if significantly different from
amounts disclosed at the most recent year-end.

We will implement the new year-end disclosure when it becomes effective in the
fourth quarter of 2004, concerning information about foreign plans, if
appropriate. See Note 11 for these additional 2003 disclosures.

SFAS 142 "Goodwill and Other Intangible Assets"
-----------------------------------------------

SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized, and that goodwill and intangible assets be tested
annually for impairment. The implementation of SFAS 142 resulted in a $350
million after tax net transitional loss in 2002 for the U.K. and Australian
operations and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change. See Note 3 for further information on
goodwill and other intangible assets.

SFAS 143 "Accounting for Asset Retirement Obligations"
------------------------------------------------------

We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability at fair
value for any legal obligations for asset retirements in the period incurred.
Upon establishment of a legal liability, SFAS 143 requires a corresponding asset
to be established which will be depreciated over its useful life. SFAS 143
requires that a cumulative effect of change in accounting principle be
recognized for the cumulative accretion and accumulated depreciation that would
have been recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in accounting
principle is favorably affected by the reversal of accumulated removal cost.
These costs had previously been recorded for generation and did not qualify as a
legal obligation although these costs were collected in depreciation rates by
certain formerly regulated subsidiaries.

We completed a review of our asset retirement obligations and concluded that we
have related legal liabilities for nuclear decommissioning costs for our Cook
Plant and our partial ownership in the South Texas Project, as well as
liabilities for the retirement of certain ash ponds, wind farms, the U.K.
Plants, and certain coal mining facilities. Since we presently recover our
nuclear decommissioning costs in our regulated cash flow and have existing
balances recorded for such nuclear retirement obligations, we recognized the
cumulative difference between the amount already provided through rates and the
amount as measured by applying SFAS 143 as a regulatory asset or liability.
Similarly, a regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In 2003, we
recorded an unfavorable cumulative effect of $45.4 million after tax for our
non-regulated operations ($38.0 million related to Ash Ponds in the Utility
Operations segment, $7.2 million related to U.K. Plants in the Investments - UK
Operations segment and $0.2 million for Wind Mills in the Investments - Other
segment).

Certain of our utility operating companies have collected removal costs from
ratepayers for certain assets that do not have associated legal asset retirement
obligations. To the extent that operating companies have now been deregulated we
reversed the balance of such removal costs, totaling $287.2 million, after tax,
which resulted in a net favorable cumulative effect in 2003. We have
reclassified approximately $1.2 billion of removal costs for our utility
operations from accumulated depreciation to Regulatory Liabilities and Deferred
Investment Tax Credits in 2003 and to Deferred Credits and Other in 2002. In
addition, $9 million is classified as held-for-sale related to the TCC
generation assets as of December 31, 2003 and 2002.

The net favorable cumulative effect of the change in accounting principle for
the year ended December 31, 2003 consists of the following:

                                              Pre-tax               After-tax
                                           Income (Loss)          Income (Loss)
                                           -------------          -------------
                                                      (in millions)

  Ash Ponds                                    $(62.8)               $(38.0)
  U.K. Plants, Wind Mills and
   Coal Operations                              (11.3)                 (7.4)
  Reversal of Cost of Removal                   472.6                 287.2
                                               -------               -------
  Total                                        $398.5                $241.8
                                               =======               =======

We have identified, but not recognized, asset retirement obligation liabilities
related to electric transmission and distribution and gas pipeline assets, as a
result of certain easements on property on which we have assets. Generally, such
easements are perpetual and require only the retirement and removal of our
assets upon the cessation of the property's use. The retirement obligation is
not estimable for such easements since we plan to use our facilities
indefinitely. The retirement obligation would only be recognized if and when we
abandon or cease the use of specific easements.

The following is a reconciliation of the beginning and ending aggregate carrying
amount of asset retirement obligations:

<TABLE>
<CAPTION>

                                                                                          U.K. Plants,
                                                                                           Wind Mills
                                                     Nuclear                Ash             and Coal
                                                 Decommissioning           Ponds           Operations           Total
                                                 ---------------           -----          ------------          -----
                                                                              (in millions)

        <C>                                          <C>                     <C>                <C>             <C>
        Asset Retirement Obligation Liability
         at January 1, 2003                          $718.3                  $69.8              $37.2           $825.3
        Accretion Expense                              52.6                    5.6                2.3             60.5
        Liabilities Incurred                              -                      -                8.3              8.3
        Foreign Currency
          Translation                                     -                      -                5.3              5.3
                                                     ------                  -----              -----           ------

        Asset Retirement Obligation
         Liability at December 31, 2003
         including Held for Sale                      770.9                   75.4               53.1            899.4

        Less Asset Retirement Obligation
         Liability Held for Sale:
           South Texas Project                       (218.8)                     -                  -           (218.8)
           U.K. Plants                                    -                      -              (28.8)           (28.8)
                                                     ------                  -----              -----           ------
        Asset Retirement Obligation
         Liability at December 31, 2003              $552.1                  $75.4              $24.3           $651.8
                                                     ======                  =====              =====           ======

</TABLE>

Accretion expense is included in Maintenance and Other Operation expense in our
accompanying Consolidated Statements of Operations.

As of December 31, 2003 and 2002, the fair value of assets that are legally
restricted for purposes of settling the nuclear decommissioning liabilities
totaled $845 million and $716 million, respectively, of which $720 million and
$618 million relating to the Cook Plant was recorded in Spent Nuclear Fuel and
Decommissioning Trusts in our Consolidated Balance Sheets. The fair value of
assets that are legally restricted for purposes of settling the nuclear
decommissioning liabilities for the South Texas Project totaling $125 million
and $98 million as of December 31, 2003 and 2002, respectively, was classified
as Assets Held for Sale in our Consolidated Balance Sheets.

Pro forma net income and earnings per share are not presented for the years
ended December 31, 2002 and 2001 because the pro forma application of SFAS 143
would result in pro forma net income and earnings per share not materially
different from the actual amounts reported during those periods.

As of December 31, 2002 and 2001, the pro forma liability for asset retirement
obligations which has been calculated as if SFAS 143 had been adopted at the
beginning of each period was $825 million and $769 million, respectively.

SFAS 144 "Accounting for the Impairment or Disposal of Long-lived Assets"
-------------------------------------------------------------------------

In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or
Disposal of Long-lived Assets" which sets forth the accounting to recognize and
measure an impairment loss. This standard replaced, SFAS 121, "Accounting for
Long-lived Assets and for Long-lived Assets to be Disposed Of." We adopted SFAS
144 effective January 1, 2002. See Note 10 for discussion of impairments
recognized in 2003 and 2002.


SFAS 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and Technical Corrections"
---------------------------------------------------------------------------

In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4,
44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections" (SFAS
145). SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment
of Debt," effective for fiscal years beginning after May 15, 2002. SFAS 4
required gains and losses from extinguishment of debt to be aggregated and
classified as an extraordinary item if material. In 2003, we reclassified
Extraordinary Losses (Net of Tax) on TCC's reacquired debt of $2 million for
2001 to Other Expenses.

SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities"
---------------------------------------------------------------------------

In June 2002, FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes previous
accounting guidance, principally EITF No. 94-3, "Liability Recognition for
Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs Incurred in a Restructuring)." Under EITF No. 94-3, a
liability for an exit cost was recognized at the date of an entity's commitment
to an exit plan. SFAS 146 requires that the liability for costs associated with
an exit or disposal activity be recognized when the liability is incurred. SFAS
146 also establishes that the liability should initially be measured and
recorded at fair value. The time at which we recognize future costs related to
exit or disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. We adopted the provisions of SFAS 146
for exit or disposal activities initiated after December 31, 2002.


SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
--------------------------------------------------------------------------

On April 30, 2003, the FASB issued Statement No. 149, "Amendment of Statement
133 on Derivative Instruments and Hedging Activities" (SFAS 149). SFAS 149
amends SFAS 133 to clarify the definition of a derivative and the requirements
for contracts to qualify for the normal purchase and sale exemption. SFAS 149
also amends certain other existing pronouncements. Effective July 1, 2003, we
implemented SFAS 149 and the effect was not material to our results of
operations, cash flows or financial condition.


SFAS 150 "Accounting for Certain Financial Instruments with Characteristics of
Both Liabilities and Equity"
------------------------------------------------------------------------------

We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the first phase of
the FASB's project to eliminate from the balance sheet the "mezzanine"
presentation of items with characteristics of both liabilities and equity,
including: (1) mandatorily redeemable shares, (2) instruments other than shares
that could require the issuer to buy back some of its shares in exchange for
cash or other assets and (3) certain obligations that can be settled with
shares. Measurement of these liabilities generally is to be at fair value, with
the payment or accrual of "dividends" and other amounts to holders reported as
interest cost.

Beginning with our third quarter 2003 financial statements, we present
Cumulative Preferred Stocks of Subsidiaries Subject to Mandatory Redemption as a
Non-Current Liability. Beginning July 1, 2003, we classify dividends on these
mandatorily redeemable preferred shares as interest expense. In accordance with
SFAS 150, dividends from prior periods remain classified as preferred stock
dividends (a component of Preferred Stock Dividend Requirements of
Subsidiaries).


FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
--------------------------------------------------------------------------

In November 2002, the FASB issued FIN 45 which clarifies the accounting to
recognize liabilities related to issuing a guarantee, as well as additional
disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the
effect was not material to our results of operations, cash flows or financial
condition. See Note 8 for further disclosures.


FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities" and
FIN 46 "Consolidation of Variable Interest Entities"
-------------------------------------------------------------------------------

We implemented FIN 46, "Consolidation of Variable Interest Entities," effective
July 1, 2003. FIN 46 interprets the application of Accounting Research Bulletin
No. 51, "Consolidated Financial Statements," to certain entities in which equity
investors do not have the characteristics of a controlling financial interest or
do not have sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from other parties. Due to the
prospective application of FIN 46, we did not reclassify prior period amounts.

On July 1, 2003, we deconsolidated Caddis Partners, LLC (Caddis). At December
31, 2002 $759 million was reported as a Minority Interest in Finance Subsidiary.
At December 31, 2003 $527 million is reported as a note payable to Caddis, a
component of Long-Term Debt. See Note 17 "Financing Activities" for further
disclosures.

On July 1, 2003, we also deconsolidated the trusts which hold mandatorily
redeemable trust preferred securities. Therefore, of the $321 million net amount
reported as "Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred
Securities of Subsidiary Trusts Holding Solely Junior Subordinated Debentures of
Such Subsidiaries" at December 31, 2002, $331 million is reported as Notes
Payable to Trust (included in Long-term Debt) and $10 million is reported in
Other Non-Current Assets at December 31, 2003.

Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company (Sabine), a
contract mining operation providing mining services to SWEPCo. Upon
consolidation, SWEPCo recorded the assets and liabilities of Sabine ($77.8
million). Also, after consolidation, SWEPCo currently records all expenses
(depreciation, interest and other operation expense) of Sabine and eliminates
Sabine's revenues against SWEPCo's fuel expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate, and
there is no change in net income due to the consolidation of Sabine.

Effective July 1, 2003, OPCo consolidated JMG. Upon consolidation, OPCo recorded
the assets and liabilities of JMG ($469.6 million). OPCo now records the
depreciation, interest and other operating expenses of JMG and eliminates JMG's
revenues against OPCo's operating lease expenses. There is no cumulative effect
of accounting change recorded as a result of our requirement to consolidate JMG,
and there is no change in net income due to the consolidation of JMG. See Note
16 "Leases" for further disclosures.

In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN 46R)
which replaces FIN 46.  The FASB and other accounting constituencies continue to
interpret the application of FIN 46R.  As a result, we are continuing to review
the application of this new interpretation and expect to adopt FIN 46R by
March 31, 2004.

EITF 02-3 and Rescission of EITF 98-10
--------------------------------------

In October 2002, the Emerging Issues Task Force of the FASB reached a final
consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and related
interpretive guidance. Under EITF 02-3, mark-to-market accounting is precluded
for risk management contracts that are not derivatives pursuant to SFAS 133. The
consensus to rescind EITF 98-10 also eliminated the recognition of physical
inventories at fair value other than as provided by GAAP. We have implemented
this standard for all physical inventory and non-derivative risk management
transactions occurring on or after October 25, 2002. For physical inventory and
non-derivative risk management transactions entered into prior to October 25,
2002, we implemented this standard on January 1, 2003 and reported the effects
of implementation as a cumulative effect of an accounting change. We recorded a
$49 million loss, net of income tax, as a cumulative effect of accounting
change.

Effective January 1, 2003, EITF 02-3 requires that gains and losses on all
derivatives, whether settled financially or physically, be reported in the
income statement on a net basis if the derivatives are held for risk management
purposes. Previous guidance in EITF 98-10 permitted contracts that were not
settled financially to be reported either gross or net in the income statement.
Prior to the third quarter of 2002, we recorded and reported upon settlement,
sales under forward risk management contracts as revenues; we also recorded and
reported purchases under forward risk management contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward risk management
revenues and purchases on a net basis. The reclassification of such risk
management activities to a net basis of reporting resulted in a substantial
reduction in both revenues and purchased energy expense, but did not have any
impact on our financial condition, results of operations or cash flows.


EITF 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That
Are Subject to FASB Statement No. 133 and Not "Held for Trading Purposes" as
Defined in Issue No. 02-3"
------------------------------------------------------------------------------

In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus
states that realized gains and losses on derivative contracts not "held for
trading purposes" should be reported either on a net or gross basis based on the
relevant facts and circumstances. Reclassification of prior year amounts is not
required. The adoption of EITF 03-11 did not have a material impact on our
results of operations, financial position or cash flows.


FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug Improvement and Modernization Act of 2003
-----------------------------------------------------------------------------

On January 12, 2004, the FASB Staff issued FSP 106-1, which allows a one-time
election to defer accounting for any effects of the prescription drug subsidy
under the Medicare Prescription Drug Improvement and Modernization Act of 2003
(the Act), enacted on December 8, 2003. There are significant uncertainties as
to whether our plan will be eligible for a subsidy under future federal
regulations that have not yet been drafted. The method of accounting for any
such subsidy and, therefore, the subsidy's possible reduction to our accumulated
postretirement benefit obligation and periodic postretirement benefit costs has
not been resolved by the FASB or other professional accounting standard setting
authority. Accordingly, we elected to defer any potential effects of the Act
until authoritative guidance on the accounting for the federal subsidy is
issued. Our measurements of the accumulated postretirement benefit obligation
and periodic postretirement benefit cost included in these financial statements
do not reflect any potential effects of the Act. We cannot determine what
impact, if any, new authoritative guidance on the accounting for the federal
subsidy may have on our results of operations or financial condition.

Future Accounting Changes
-------------------------

The FASB's standard-setting process is ongoing. Until new standards have been
finalized and issued by FASB, we cannot determine the impact on the reporting of
our operations that may result from any such future changes.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES
---------------------------------------

Accounting for Risk Management Contracts
----------------------------------------

EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. We recorded a
$49 million after tax charge against net income as Accounting for Risk
Management Contracts in our Consolidated Statements of Operations in Cumulative
Effect of Accounting Changes in the first quarter of 2003 ($12 million in
Utility Operations, $22 million in Investments - Gas Operations and $15 million
in Investments - UK Operations segments). This amount will be realized when the
positions settle.

The FASB's Derivative Implementation Group (DIG) issued accounting guidance
under SFAS 133 for certain derivative fuel supply contracts with volumetric
optionality and derivative electricity capacity contracts. This guidance,
effective in the third quarter of 2001, concluded that fuel supply contracts
with volumetric optionality cannot qualify for a normal purchase or sale
exclusion from mark-to-market accounting and provided guidance for determining
when certain option-type contracts and forward contracts in electricity can
qualify for the normal purchase or sale exclusion.

The effect of initially adopting the DIG guidance at July 1, 2001 was a
favorable earnings mark-to-market after tax effect of $18 million (net of tax of
$2 million). It was reported as a cumulative effect of an accounting change on
our Consolidated Statements of Operations (included in Investments-Other
segment).

Asset Retirement Obligations (SFAS 143)
---------------------------------------

In the first quarter of 2003, we recorded $242 million in after-tax income as a
cumulative effect of accounting change for Asset Retirement Obligations.

Goodwill and Other Intangible Assets
------------------------------------

SFAS 142 requires that goodwill and intangible assets with indefinite useful
lives no longer be amortized and be tested annually for impairment. The
implementation of SFAS 142 in 2002 resulted in a $350 million net transitional
loss for our U.K. and Australian operations (included in the Investments - Other
segment) and is reported in our Consolidated Statements of Operations as a
cumulative effect of accounting change (see Note 3, "Goodwill and Other
Intangible Assets" for further details).

See table below for details of the Cumulative Effect of Accounting Changes:

<TABLE>
<CAPTION>

                                                                                        Year Ended  December 31,
                                                                              -----------------------------------------
Description                                                                   2003               2002              2001
-----------                                                                   ----               ----              ----
                                                                                             (in millions)
<C>                                                                           <C>                  <C>              <C>
Accounting for Risk Management Contracts (EITF 02-3)                          $(49)                $-               $-
Asset Retirement Obligations (SFAS 143)                                        242                  -                -
Goodwill and Other Intangible Assets                                             -               (350)               -
Accounting for Risk Management Contracts (DIG Guidance)                          -                  -               18
                                                                              -----             ------             ----
Total                                                                         $193              $(350)             $18
                                                                              =====             ======             ====
</TABLE>

EXTRAORDINARY ITEMS
-------------------

In 2001, we recorded an extraordinary item for the discontinuance of regulatory
accounting under SFAS 71 for the generation portion of our business in the Ohio
state jurisdiction. OPCo and CSPCo recognized an extraordinary loss of $48
million (net of tax of $20 million) for unrecoverable Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits. This loss resulted from regulatory decisions in connection with Ohio
deregulation which stranded the recovery of the GRT. Effective with the
liability affixing on May 1, 2001, CSPCo and OPCo recorded an extraordinary loss
under SFAS 101. Both Ohio companies appealed to the Ohio Supreme Court the PUCO
order on Ohio restructuring that the Ohio companies believe failed to provide
for recovery for the final year of the GRT. In April 2002, the Ohio Supreme
Court denied recovery of the final year of the GRT.


3.  GOODWILL AND OTHER INTANGIBLE ASSETS
----------------------------------------


GOODWILL
--------

The changes in our carrying amount of goodwill for the years ended December 31,
2003 and 2002 by operating segment are:

<TABLE>
<CAPTION>
                                                                                Investments
                                                                   ---------------------------------------
                                                       Utility         Gas              UK                           AEP
                                                     Operations    Operations        Operations      Other      Consolidated
                                                     ----------    ------------      ----------      -----      ------------
                                                                                   (in millions)
   <C>                                                  <C>           <C>              <C>           <C>            <C>
   Balance at January 1, 2002
     (including Assets Held for Sale)                   $37.1         $340.1               $-        $14.9          $392.1
   Goodwill acquired                                        -              -              2.3            -             2.3
   Changes to Goodwill due to
     Purchase price adjustments                             -          (33.8)           172.5         42.4           181.1
   Impairment losses                                        -              -           (170.0)       (15.9)         (185.9)
   Foreign currency exchange rate changes                   -              -              6.4            -             6.4
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2002
     (including Assets Held for Sale)                    37.1          306.3             11.2         41.4           396.0
   Less: Assets Held for Sale, Net (a)                      -         (143.8)           (11.2)           -          (155.0)
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2002
     (excluding Assets Held for Sale)                   $37.1         $162.5               $-        $41.4          $241.0
                                                        =====         ======           =======       ======         =======

   Balance at January 1, 2003
     (including Assets Held for Sale)                   $37.1         $306.3            $11.2        $41.4          $396.0
   Impairment losses                                        -         (291.4)           (12.2)           -          (303.6)
   Foreign currency exchange rate changes                   -              -              1.0            -             1.0
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2003
     (including Assets Held for Sale)                    37.1           14.9                -         41.4            93.4
   Less: Assets Held for Sale, Net (a)                      -          (14.9)               -            -           (14.9)
                                                        -----         -------          -------       ------         -------

   Balance at December 31, 2003
    (excluding Assets Held for Sale)                    $37.1             $-               $-        $41.4           $78.5
                                                        =====         =======          =======       ======         ======

</TABLE>

    (a) On our Consolidated Balance Sheets, amounts related to entities
        classified as held for sale are excluded from Goodwill and are reported
        within Assets Held for Sale (see Note 10). The following entities
        classified as held for sale had goodwill or goodwill impairments during
        the years ended December 31, 2003 or 2002:

  o     Jefferson Island (Investments - Gas Operations segment) - $14.4
        million and $143.3 million balances in goodwill at December 1, 2003
        and 2002, respectively. During 2003, we recognized a goodwill
        impairment loss of $128.9 million.
  o     LIG Chemical (Investments - Gas Operations segment) - $0.5 million
        balance in goodwill at December 31, 2003 and 2002.
  o     U.K. Coal Trading (Investments - UK Operations segment) - $11.2
        million balance in goodwill at December 31, 2002. In 2003, we
        recognized a goodwill impairment loss of $12.2 million related to the
        impairment study (impairment in 2003 was greater than December 31,
        2002 balance due to changes in foreign currency translation rates).
  o     U.K.  Generation  (Investments  - UK  Operations  segment) - No
        goodwill  balances at December  31, 2003 or 2002.  In 2002, we
        recognized a goodwill impairment loss of $166.0 million related to the
        impairment study.
  o     AEP Coal  (Investments - Other  segment) - No goodwill balances at
        December 31, 2003 or 2002. In 2002, we recognized a $3.6 million
        impairment loss related to the impairment study.

Accumulated amortization of goodwill was approximately $1 million and $9 million
at December 31, 2003 and 2002, respectively. The decrease of $8 million between
years is related to the impairment of goodwill on Houston Pipe Line Company and
AEP Energy Services.

In the fourth quarter of 2003, we prepared our annual goodwill impairment tests.
The fair values of the operations were estimated using cash flow projections and
other market value indicators. As a result of the tests, we recognized a $162.5
million goodwill impairment loss related to Houston Pipe Line Company ($150.4
million) and AEP Energy Services ($12.1 million).

During 2002, changes to goodwill were due to purchase price adjustments of $6.7
million primarily related to our acquisition of Houston Pipe Line Company, MEMCO
and Nordic Trading (see Note 10).

In the first quarter of 2002, we recognized a goodwill impairment loss of $12.3
million for all goodwill related to Gas Power Systems (see Note 10).

In the fourth quarter of 2002, we prepared our annual goodwill impairment tests.
The fair values of the operations were estimated using cash flow projections. As
a result of the tests, we recognized a goodwill impairment loss of $4.0 million
related to Nordic Trading (see Note 10).

The transitional impairment loss related to SEEBOARD and CitiPower goodwill,
which is reported as Cumulative Effect of Accounting Changes in 2002, is
excluded from the above schedule.

The following tables show the transitional disclosures to adjust our reported
net income (loss) and earnings (loss) per share to exclude amortization expense
recognized in prior periods related to goodwill and intangible assets that are
no longer being amortized.


<TABLE>
<CAPTION>

Net Income (Loss)                                           Year Ended December 31,
-----------------                                      ----------------------------------
                                                       2003            2002          2001
                                                       ----            ----          ----
                                                                  (in millions)
<C>                                                    <C>            <C>          <C>
Reported Net Income (Loss)                             $110           $(519)         $971
Add back: Goodwill amortization                           -               -            39(a)
Add back: Amortization for intangibles with
 indefinite lives                                         -               -             8(b)
                                                       -----          ------       -------
Adjusted Net Income (Loss)                             $110           $(519)       $1,018
                                                       =====          ======       =======
</TABLE>

<TABLE>
<CAPTION>


Earnings (Loss) Per Share (Basic and Dilutive)              Year Ended December 31,
----------------------------------------------         ----------------------------------
                                                       2003            2002          2001
                                                       ----            ----          ----
<C>                                                    <C>           <C>            <C>
Reported Earnings (Loss) per Share                     $0.29         $(1.57)        $3.01
Add back: Goodwill amortization                            -              -          0.12(c)
Add back: Amortization for intangibles with
 indefinite lives                                          -              -          0.02(b)
                                                       -----         -------        ------
Adjusted Earnings (Loss) per Share                     $0.29         $(1.57)        $3.15
                                                       =====         =======        ======
</TABLE>


(a) This amount includes $34 million in 2001 related to SEEBOARD and CitiPower
    amortization expense included in Discontinued Operations on our Consolidated
    Statements of Operations.
(b) The amounts shown for 2001 relate to CitiPower amortization expense
    included in Discontinued Operations on our Consolidated Statements of
    Operations.
(c) This amount includes $0.10 in 2001 related to SEEBOARD and CitiPower
    amortization expense included in Discontinued Operations on our Consolidated
    Statements of Operations.

OTHER INTANGIBLE ASSETS
-----------------------

Acquired intangible assets subject to amortization are $34 million at December
31, 2003 and $37 million at December 31, 2002, net of accumulated amortization.
The gross carrying amount, accumulated amortization and amortization life by
major asset class are:

<TABLE>
<CAPTION>

                                                                 December 31, 2003                   December 31, 2002
                                                             ---------------------------          ----------------------
                                                              Gross                             Gross
                                         Amortization        Carrying       Accumulated        Carrying         Accumulated
                                             Life             Amount        Amortization        Amount          Amortization
                                         ------------        --------       ------------       --------         ------------
                                          (in years)               (in millions)                       (in millions)
<C>                                            <C>            <C>              <C>              <C>                <C>
Software and customer list (a)                  2                $-               $-             $0.5              $0.2
Software acquired (b)                           3               0.5              0.3              0.5                 -
Patent                                          5               0.1                -              0.1                 -
Easements                                      10               2.2              0.3                -                 -
Trade name and administration of
contracts                                       7               2.4              0.9              2.4               0.6
Purchased technology                           10              10.9              2.2             10.3               1.0
Advanced royalties                             10              29.4              7.7             29.4               4.7
                                                              -----            -----            -----              ----
Total                                                         $45.5            $11.4            $43.2              $6.5
                                                              =====            =====            =====              ====
</TABLE>


(a) This asset was disposed of in the second quarter of 2003.
(b) This asset relates to U.K. Generation Plants and is included in Assets Held
    for Sale on our Consolidated Balance Sheets.

Amortization of intangible assets was $5 million and $4 million for the twelve
months ended December 31, 2003 and 2002, respectively. Our estimated aggregate
amortization expense is $5 million for each year 2004 through 2007, $4 million
for 2008 through 2010 and $3 million in 2011.


4.  RATE MATTERS
----------------


In certain jurisdictions, we have agreed to base rate or fuel recovery
limitations usually under terms of settlement agreements. See Note 5 for a
discussion of those terms related to Nuclear Plant Restart and Merger with CSW.

Fuel in SPP Area of Texas
-------------------------

In 2001, the PUCT delayed the start of customer choice in the SPP area of Texas.
In May 2003, the PUCT ordered that competition would not begin in the SPP areas
before January 1, 2007. TNC filed with the PUCT in 2002 to determine the most
appropriate method to reconcile fuel costs in TNC's SPP area. In April 2003, the
PUCT issued an order adopting the methodology proposed in TNC's filing, with
adjustments, for reconciling fuel costs in the SPP area. The adjustments removed
$3.71 per MWH from reconcilable fuel expense. This adjustment will reduce
revenues received by Mutual Energy SWEPCo who now serves TNC's SPP customers by
approximately $400,000 annually. In October 2003, Mutual Energy SWEPCo agreed
with the PUCT staff and the Office of Public Utility Counsel (OPC) to file a
fuel reconciliation proceeding for the period January 2002 through December 2003
by March 31, 2004 and the PUCT ordered that the filing be made.

TNC Fuel Reconciliations
------------------------

In June 2002, TNC filed with the PUCT to reconcile fuel costs, requesting to
defer any unrecovered portion applicable to retail sales within its ERCOT
service area for inclusion in the 2004 true-up proceeding. This reconciliation
for the period of July 2000 through December 2001 will be the final fuel
reconciliation for TNC's ERCOT service territory. At December 31, 2001, the
deferred under-recovery balance associated with TNC's ERCOT service area was
$27.5 million including interest. During the reconciliation period, TNC incurred
$293.7 million of eligible fuel costs serving both ERCOT and SPP retail
customers. TNC also requested authority to surcharge its SPP customers for
under-recovered fuel costs. TNC's SPP customers will continue to be subject to
fuel reconciliations until competition begins in the SPP area as described
above. The under-recovery balance at December 31, 2001 for TNC's service within
SPP was $0.7 million including interest.

In March 2003, the ALJ in this proceeding filed a Proposal for Decision (PFD)
with a recommendation that TNC's under-recovered retail fuel balance be reduced.
In March 2003, TNC established a reserve of $13 million based on the
recommendations in the PFD. In May 2003, the PUCT reversed the ALJ on certain
matters and remanded TNC's final fuel reconciliation to the ALJ to consider two
issues. The issues are the sharing of off-system sales margins from AEP's
trading activities with customers for five years per the PUCT's interpretation
of the Texas AEP/CSW merger settlement and the inclusion of January 2002 fuel
factor revenues and associated costs in the determination of the under-recovery.
The PUCT proposed that the sharing of off-system sales margins for periods
beyond the termination of the fuel factor should be recognized in the final fuel
reconciliation proceeding. This would result in the sharing of margins for an
additional three and one half years after the end of the Texas ERCOT fuel
factor.

On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC fuel
reconciliation recommending additional disallowances for the two remand issues.
TNC filed responses to the PFD and the PUCT announced a final ruling in the fuel
reconciliation proceeding on January 15, 2004 accepting the PFD. TNC is waiting
for a written order, after which it will request a rehearing of the PUCT's
ruling. While management believes that the Texas merger settlement only provided
for sharing of margins during the period fuel and generation costs were
regulated by the PUCT, an additional provision of $10 million was recorded in
December 2003. Based on the decisions of the PUCT, TNC's final under-recovery
including interest at December 31, 2003 was $6.2 million.

In February 2002, TNC received a final order from the PUCT in a previous fuel
reconciliation covering the period July 1997 to June 2000 and reflected the
order in its financial statements. This final order was appealed to the Travis
County District Court. In May 2003, the District Court upheld the PUCT's final
order. That order is currently on appeal to the Third Court of Appeals.

TCC Fuel Reconciliation
-----------------------

In December 2002, TCC filed its final fuel reconciliation with the PUCT to
reconcile fuel costs to be included in its deferred over-recovery balance in the
2004 true-up proceeding. This reconciliation covers the period of July 1998
through December 2001. At December 31, 2001, the over-recovery balance for TCC
was $63.5 million including interest. During the reconciliation period, TCC
incurred $1.6 billion of eligible fuel and fuel-related expenses.

Based on the PUCT ruling in the TNC proceeding relating to similar issues, TCC
established a reserve for potential adverse rulings of $81 million during 2003.
In July 2003, the ALJ requested that additional information be provided in the
TCC fuel reconciliation related to the impact of the TNC orders, referenced
above, on TCC. On February 3, 2004, the ALJ issued a PFD recommending that the
PUCT disallow $140 million in eligible fuel costs including some new items not
considered in the TNC case, and other items considered but not disallowed in the
TNC ruling. At this time, management is unable to predict the outcome of this
proceeding. An adverse ruling from the PUCT, disallowing amounts in excess of
the established reserve could have a material impact on future results of
operations, cash flows and financial condition. Additional information regarding
the 2004 true-up proceeding for TCC can be found in Note 6 "Customer Choice and
Industry Restructuring."

SWEPCo Texas Fuel Reconciliation
--------------------------------

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP. This
reconciliation covers the period of January 2000 through December 2002. At
December 31, 2002, SWEPCo's filing included a $2 million deferred over-recovery
balance including interest. During the reconciliation period, SWEPCo incurred
$435 million of Texas retail eligible fuel expense. In November 2003,
intervenors and the PUCT Staff recommended fuel cost disallowances of more than
$30 million. In December 2003, SWEPCo agreed to a settlement in principle with
all parties in the fuel reconciliation. The settlement provides for a
disallowance in fuel costs of $8 million which was recorded in December 2003. In
addition, the settlement provides for the deferral as a regulatory asset of
costs of a new lignite mining agreement in excess of a specified benchmark for
lignite at SWEPCo's Dolet Hills Plant. The settlement provides for recovery of
the deferred costs over a period ending in April 2011 as cost savings are
realized under the new mining agreement. The settlement also will allow future
recovery of litigation costs associated with the termination of a previous
lignite mining agreement if future costs savings are adequate. The settlement
will be filed with the PUCT for approval.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal
--------------------------------------------

Several parties including the Office of Public Utility Counsel (OPC) and cities
served by both TCC and TNC appealed the PUCT's December 2001 orders establishing
initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU. On June
25, 2003, the District Court ruled in both appeals. The Court ruled in the
Mutual Energy WTU case that the PUCT lacked sufficient evidence to include
unaccounted for energy in the fuel factor, and that the PUCT improperly shifted
the burden of proof and the record lacked substantial evidence on the effect of
loss of load due to retail competition on generation requirements. The Court
upheld the initial PTB orders on all other issues. In the Mutual Energy CPL
proceeding, the Court ruled that the PUCT improperly shifted the burden of proof
and the record lacked substantial evidence on the effect of loss of load due to
retail competition on generation requirements. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million for Mutual
Energy WTU. At this time, management is unable to estimate the potential
financial impact related to the loss of load issue. The District Court decision
was appealed to the Third Court of Appeals by Mutual Energy CPL, Mutual Energy
WTU and other parties. Management believes, based on the advice of counsel, that
the PUCT's original decision will ultimately be upheld. If the District Court's
decisions are ultimately upheld, the PUCT could reduce the PTB fuel factors
charged to retail customers in 2002 and 2003 resulting in an adverse effect on
future results of operations and cash flows.

Unbundled Cost of Service (UCOS) Appeal
---------------------------------------

The UCOS proceeding established the regulated wires rates to be effective when
retail electric competition began. TCC placed new transmission and distribution
rates into effect as of January 1, 2002 based upon an order issued by the PUCT
resulting from TCC's UCOS proceeding. TCC requested and received approval from
the FERC of wholesale transmission rates determined in the UCOS proceeding.
Regulated delivery charges include the retail transmission and distribution
charge and, among other items, a nuclear decommissioning fund charge, a
municipal franchise fee, a system benefit fund fee, a transition charge
associated with securitization of regulatory assets and a credit for excess
earnings. Certain rulings of the PUCT in the UCOS proceeding, including the
initial determination of stranded costs, the requirement to refund TCC's excess
earnings, regulatory treatment of nuclear insurance and distribution rates
charged municipal customers, were appealed to the Travis County District Court
by TCC and other parties to the proceeding. The District Court issued a decision
on June 16, 2003, upholding the PUCT's UCOS order with one exception. The Court
ruled that the refund of the 1999 through 2001 excess earnings, solely as a
credit to non-bypassable transmission and distribution rates charged to REPs,
discriminates against residential and small commercial customers and is
unlawful. The distribution rate credit began in January 2002. This decision
could potentially affect the PTB rates charged by Mutual Energy CPL and could
result in a refund to certain of its customers. Mutual Energy CPL was a
subsidiary of AEP until December 23, 2002 when it was sold. Management estimates
that the effect of a decision to reduce the PTB rates for the period prior to
the sale is approximately $11 million pre-tax. The District Court decision was
appealed to the Third Court of Appeals by TCC and other parties. Based on advice
of counsel, management believes that it will ultimately prevail on appeal. If
the District Court's decision is ultimately upheld on appeal or the Court of
Appeals reverses the District Court on issues adverse to TCC, it could have an
adverse effect on future results of operations and cash flows.

TCC Rate Case
-------------

On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates should not be
reduced. Other municipalities served by TCC passed similar rate review
resolutions. In Texas, municipalities have original jurisdiction over rates of
electric utilities within their municipal limits. Under Texas law, TCC must
provide support for its rates to the municipalities. TCC filed the requested
support for its rates based on a test year ending June 30, 2003 with all of its
municipalities and the PUCT on November 3, 2003. TCC's proposal would decrease
its wholesale transmission rates by $2 million or 2.5% and increase its retail
energy delivery rates by $69 million or 19.2%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's requested
$67 million rate increase. The recommendations range from a decrease in existing
rates of approximately $100 million to an increase in TCC's current rates of
approximately $27 million. The PUCT Staff filed testimony, on February 17, 2004,
recommending reductions to TCC's request of approximately $51 million. TCC's
rebuttal testimony was filed on February 26, 2004. Hearings are scheduled for
March 2004 with a PUCT decision expected in May 2004. Management is unable to
predict the ultimate effect of this proceeding on TCC's rates or its impact on
TCC's results of operations, cash flows and financial condition.

Louisiana Fuel Audit
--------------------

The LPSC is performing an audit of SWEPCo's historical fuel costs. In addition,
five SWEPCo customers filed a suit in the Caddo Parish District Court in January
2003 and filed a complaint with the LPSC. The customers claim that SWEPCo has
over charged them for fuel costs since 1975. The LPSC consolidated the customer
complaint and audit. In January 2004, a procedural schedule was issued requiring
LPSC Staff and intervenor testimony to be filed in June 2004 and scheduling
hearings for October 2004. Management believes that SWEPCo's fuel costs were
proper and those costs incurred prior to 1999 have been approved by the LPSC.
Management is unable to predict the outcome of these proceedings. If the actions
of the LPSC or the Court result in a material disallowance of recovery of
SWEPCo's fuel costs from customers, it could have an adverse impact on results
of operations and cash flows.

Louisiana Compliance Filing
---------------------------

In October 2002, SWEPCo filed with the LPSC detailed financial information
typically utilized in a revenue requirement filing, including a jurisdictional
cost of service. This filing was required by the LPSC as a result of their order
approving the merger between AEP and CSW. The LPSC's merger order also provides
that SWEPCo's base rates are capped at the present level through mid 2005. The
filing indicates that SWEPCo's current rates should not be reduced. In 2004 the
LPSC required SWEPCo to file updated financial information with a test year
ending December 31, 2003 before April 16, 2004. If, after review of the updated
information, the LPSC disagrees with our conclusion, they could order SWEPCo to
file all documents for a full cost of service revenue requirement review in
order to determine whether SWEPCo's capped rates should be reduced which would
adversely impact results of operations and cash flows.

FERC Wholesale Fuel Complaints
------------------------------

Certain TNC wholesale customers filed a complaint with FERC alleging that TNC
had overcharged them through the fuel adjustment clause for certain purchased
power costs since 1997.

Negotiations to settle the complaint and update the contracts resulted in new
contracts. The FERC approved an offer of settlement regarding the fuel complaint
and new contracts at market prices in December 2003. Since TNC had recorded a
provision for refund in 2002, the effect of the settlement was a $4 million
favorable adjustment recorded in December 2003.

Environmental Surcharge Filing
------------------------------

In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million) to
recover the cost of emissions control equipment being installed at the Big Sandy
Plant. See NOx Reductions in Note 7.

In March 2003, the KPSC granted approximately $18 million of the request. Annual
rate relief of $1.7 million became effective in May 2003 and an additional $16.2
million became effective in July 2003. The recovery of such amounts is intended
to offset KPCo's cost of compliance with the Clean Air Act.

PSO Rate Review
---------------

In February 2003, the Director of the OCC filed an application requiring PSO to
file all documents necessary for a general rate review. In October 2003, PSO
filed financial information and supporting testimony in response to the OCC's
requirements. PSO's response indicates that its annual revenues are $36 million
less than costs. As a result, PSO is seeking OCC approval to increase its base
rates by that amount, which is a 3.6% increase over PSO's existing revenues.
Hearings are scheduled for October 2004. Management is unable to predict the
ultimate effect of this review on PSO's rates or its impact on PSO's results of
operations, cash flows and financial condition.

PSO Fuel and Purchased Power
----------------------------

PSO had a $44 million under-recovery of fuel costs resulting from a 2002
reallocation among AEP West companies of purchased power costs for periods prior
to January 1, 2002. In July 2003, PSO filed with the OCC seeking recovery of the
$44 million over an 18-month time period. In August 2003, the OCC Staff filed
testimony recommending PSO be granted recovery of $42.4 million over three
years. In September 2003, the OCC expanded the case to include a full review of
PSO's 2001 fuel and purchased power practices. PSO filed its testimony in
February 2004 and hearings will occur in June 2004. If the OCC determines as a
result of the review that a portion of PSO's fuel and purchased power costs
should not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.

Virginia Fuel Factor Filing
---------------------------

APCo filed with the Virginia SCC to reduce its fuel factor effective August 1,
2003. The requested fuel rate reduction was approved by the Virginia SCC and is
effective for 17 months (August 1, 2003 to December 31, 2004) and is estimated
to reduce revenues by $36 million during that period. This fuel factor
adjustment will reduce cash flows without impacting results of operations as any
over-recovery or under-recovery of fuel costs would be deferred as a regulatory
liability or a regulatory asset.

FERC Long-term Contracts
------------------------

In 2002, the FERC set for hearing complaints filed by certain wholesale
customers located in Nevada and Washington that sought to break long-term
contracts which the customers alleged were "high-priced." At issue were
long-term contracts entered into during the California energy price spike in
2000 and 2001. The complaints alleged that AEP sold power at unjust and
unreasonable prices.

In February 2003, AEP and one of the customers agreed to terminate their
contract. The customer withdrew its FERC complaint and paid $59 million to AEP.
As a result of the contract termination, AEP reversed $69 million of unrealized
mark-to-market gains previously recorded, resulting in a $10 million pre-tax
loss.

In December 2002, a FERC ALJ ruled in favor of AEP and dismissed a complaint
filed by two Nevada utilities. In 2000 and 2001, we agreed to sell power to the
utilities for future delivery. In 2001, the utilities filed complaints asserting
that the prices for power supplied under those contracts should be lowered
because the market for power was allegedly dysfunctional at the time such
contracts were executed. The ALJ rejected the utilities' complaint, held that
the markets for future delivery were not dysfunctional, and that the utilities
had failed to demonstrate that the public interest required that changes be made
to the contracts. In June 2003, the FERC issued an order affirming the ALJ's
decision. The utilities requested a rehearing which the FERC denied. The
utilities' appeal of the FERC order is pending before the U.S. Court of Appeals
for the Ninth Circuit. Management is unable to predict the outcome of this
proceeding and its impact on future results of operations and cash flows.

RTO Formation/Integration Costs
-------------------------------

With FERC approval, AEP East companies have been deferring costs incurred under
FERC orders to form an RTO (the Alliance RTO) or join an existing RTO (PJM). In
July 2003, the FERC issued an order approving our continued deferral of both our
Alliance formation costs and our PJM integration costs including the deferral of
a carrying charge. The AEP East companies have deferred approximately $28
million of RTO formation and integration costs and related carrying charges
through December 31, 2003. As a result of the subsequent delay in the
integration of AEP's East transmission system into PJM, FERC declined to rule,
in its July order, on our request to transfer the deferrals to regulatory
assets, and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration with PJM.
In August 2003, the Virginia SCC filed a request for rehearing of the July
order, arguing that FERC's action was an infringement on state jurisdiction, and
that FERC should not have treated Alliance RTO startup costs in the same manner
as PJM integration costs. On October 22, 2003, FERC denied the rehearing
request.

In its July 2003 order, FERC indicated that it would review the deferred costs
at the time they are transferred to a regulatory asset account and scheduled for
amortization and recovery in the open access transmission tariff (OATT) to be
charged by PJM. Management believes that the FERC will grant permission for the
deferred RTO costs to be amortized and included in the OATT. Whether the
amortized costs will be fully recoverable depends upon the state regulatory
commissions' treatment of AEP East companies' portion of the OATT at the time
they join PJM. Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. APCo's Virginia retail
base rates are capped with an opportunity for a one-time increase in
non-generation rates after January 1, 2004. We intend to file an application
with FERC seeking permission to delay the amortization of the deferred RTO
formation/integration costs until they are recoverable from all users of the
transmission system including retail customers. Management is unable to predict
the timing of when AEP will join PJM and if upon joining PJM whether FERC will
grant a delay of recovery until the rate caps and freezes end. If the AEP East
companies do not obtain regulatory approval to join PJM, we are committed to
reimburse PJM for certain project implementation costs (presently estimated at
$24 million for the entire PJM integration project). Management intends to seek
recovery of the deferred RTO formation/integration costs and project
implementation cost reimbursements, if incurred. If the FERC ultimately decides
not to approve a delay or the state commissions deny recovery, future results of
operations and cash flows could be adversely affected.

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

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

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

In November 2003, the FERC issued an order preliminarily finding that AEP must
fulfill its CSW merger condition to join an RTO by integrating into PJM
(transmission and markets) by October 1, 2004. The order was based on PURPA
205(a), which allows FERC to exempt electric utilities from state law or
regulation in certain circumstances. The FERC set for public hearing before an
ALJ several issues. Those issues include whether the laws, rules, or regulations
of Virginia and Kentucky are preventing AEP from joining an RTO and whether the
exceptions under PURPA apply. The FERC directed the ALJ to issue his initial
decision by March 15, 2004.

FERC Order on Regional Through and Out Rates
--------------------------------------------

In July 2003, the FERC issued an order directing PJM and the Midwest ISO to make
compliance filings for their respective Open Access Transmission Tariffs to
eliminate, by November 1, 2003, the transaction-based charges for through and
out (T&O) transmission service on transactions where the energy is delivered
within the proposed Midwest ISO and PJM expanded regions (RTO Footprint). In
October 2003, the FERC postponed the November 1, 2003 deadline to eliminate T&O
rates. The elimination of the T&O rates will reduce the transmission service
revenues collected by the RTOs and thereby reduce the revenues received by
transmission owners under the RTOs' revenue distribution protocols. The order
provided that affected transmission owners could file to offset the elimination
of these revenues by increasing rates or utilizing a transitional rate mechanism
to recover lost revenues that result from the elimination of the T&O rates. The
FERC also found that the T&O rates of some of the former Alliance RTO companies,
including AEP, may be unjust, unreasonable, and unduly discriminatory or
preferential for energy delivered in the RTO Footprint. FERC initiated an
investigation and hearing in regard to these rates. We made a filing with the
FERC to support the justness and reasonableness of our rates. We also made a
joint filing with unaffiliated utilities proposing a regional revenue
replacement mechanism for the lost revenues, in the event that FERC eliminated
all T&O rates for delivery points within the RTO Footprint. In orders issued in
November 2003, the FERC dismissed the joint filing, but adopted a new regional
rate design substantially in the form proposed in the joint filing. The orders
directed each transmission provider to file compliance rates to eliminate T&O
rates prospectively within the region and simultaneously implement new seams
elimination cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC did not indicate
the recovery method for the revenues after the two-year period. As required by
the FERC, we filed compliance tariff changes in January 2004 to eliminate the
T&O charges within the RTO Footprint. The SECA rate issues that remain
unresolved have been set before an ALJ for settlement procedures, and the
effective date of the T&O rate elimination and SECA rates were delayed until May
1, 2004. The November orders have been appealed by a number of parties. The AEP
East companies received approximately $150 million of T&O rate revenues from
transactions delivering energy to customers in the RTO Footprint for the twelve
months ended June 30, 2003. At this time, management is unable to predict
whether the new SECA rates will fully compensate the AEP East companies for
their lost T&O rate revenues and, consequently, their impact on our future
results of operations, cash flows and financial condition.

Indiana Fuel Order
------------------

On July 17, 2003, I&M filed a fuel adjustment clause application requesting
authorization to implement the fixed fuel adjustment charge (fixed pursuant to a
prior settlement of the Cook Nuclear Plant Outage) for electric service for the
billing months of October 2003 through February 2004, and for approval of a new
fuel cost adjustment credit for electric service to be applicable during the
March 2004 billing month.

On August 27, 2003, the IURC issued an order approving the requested fixed fuel
adjustment charge for October 2003 through February 2004. The order further
stated that certain parties must negotiate the appropriate action on fuel to
commence on March 1, 2004. Such negotiations are ongoing. The IURC deferred
ruling on the March 2004 factor until after January 1, 2004.

Michigan 2004 Fuel Recovery Plan
--------------------------------

The MPSC's December 16, 1999 order approved a Settlement Agreement regarding the
extended outage of the Cook Plant and fixed I&M Power Supply Cost Recovery
(PSCR) factors for the St. Joseph and Three Rivers rate areas through December
2003. In accordance with the settlement, PSCR Plan cases were not required to be
filed through the 2003 plan year. As required, I&M filed its 2004 PSCR Plan with
the MPSC on September 30, 2003 seeking new fuel and power supply recovery
factors to be effective in 2004. The case has been scheduled for hearing. As
allowed by Michigan law, the proposed factors were effective on January 1, 2004,
subject to review and possible adjustment based on the results of the hearing.


5.  EFFECTS OF REGULATION
-------------------------


Regulatory Assets and Liabilities
---------------------------------

Regulatory assets and liabilities are comprised of the following items:
<TABLE>
<CAPTION>



                                                                            December 31,                          Future
                                                                  ------------------------------                 Recovery/
                                                                   2003                    2002                Refund  Period
                                                                   ----                    ----                --------------
                                                                            (in millions)

<C>                                                                   <C>                <C>              <C>
  Regulatory Assets:

    Income Tax-related Regulatory Assets, Net                           $728               $639           Various Periods  (a)
    Transition Regulatory Assets                                         529                743             Up to 5 Years  (a)
    Regulatory Assets Designated for Securitization                    1,253                331                            (b)
    Texas Wholesale Capacity Auction True-Up                             480                262                            (c)
    Unamortized Loss on Reacquired Debt                                  116                 83             Up to 40 Years (d)
    Cook Nuclear Plant Restart Costs                                       -                 40                            N/A
    Cook Nuclear Plant Refueling Outage Levelization                      57                 30                            (e)
    Deferred Fuel Costs                                                   24                121                     1 Year (a)
    CSW Merger Costs                                                      23                 32              Up to 5 Years (a)
    Deferred Fuel Costs (TNC)                                             27                 27                            (c)
    DOE Decontamination and Decommissioning Assessment                    21                 26              Up to 5 Years (a)
    Other                                                                290                354           Various Periods  (f)
                                                                      -------            -------
  Total Regulatory Assets                                             $3,548             $2,688
                                                                      =======            =======

  Regulatory Liabilities:
    Asset Removal Costs                                               $1,233                 $-                            (h)
    Deferred Investment Tax Credits                                      422                455             Up to 26 Years (a)
    Excess ARO for Nuclear Decommissioning Liability                     216                  -                            (g)
    Deferred Over-Recovered Fuel Costs (TCC)                              69                 69                            (c)
    Deferred Over-Recovered Fuel Costs                                    63                 21                            (a)
    Texas Retail Clawback                                                 57                 66                            (c)
    Other                                                                199                328            Various Periods (f)
                                                                      -------            -------
  Total Regulatory Liabilities                                        $2,259               $939
                                                                      =======            =======
</TABLE>


  (a) Amount does not earn a return.
  (b) Will be included in TCC's PUCT 2004 true-up proceeding and is designated
      for possible securitization during 2005.
  (c) Amount will be included in TCC's and TNC's 2004 true-up proceedings for
      future recovery/payment over a time period to be determined in a future
      PUCT proceeding.
  (d) Amount effectively earns a return.
  (e) Amortized over the period beginning with the commencement of an outage and
      ending with the beginning of the next outage and does not earn a return.
  (f) These regulatory assets and liabilities include items both earning and not
      earning a return.
  (g) Amounts are accrued monthly and will be paid when the nuclear plant is
      decommissioned. This also earns a return.
  (h) The liability for removal costs will be discharged as removal costs are
      incurred over the life of the plant.

Texas Restructuring Related Regulatory Assets and Liabilities
-------------------------------------------------------------

Regulatory Assets Designated for Securitization, Texas Wholesale Capacity
Auction True-up regulatory assets, Deferred Over-Recovered Fuel Costs and Texas
Retail Clawback regulatory liabilities are not being currently recovered from or
returned to ratepayers. Management believes that the laws and regulations,
established in Texas for industry restructuring, provide for the recovery from
ratepayers of these net amounts. See Note 6 for a complete discussion of our
plans to recover these regulatory assets, net of regulatory liabilities.

Nuclear Plant Restart
---------------------

I&M completed the restart of both units of the Cook Plant in 2000. Settlement
agreements in the Indiana and Michigan retail jurisdictions that addressed
recovery of Cook Plant related outage restart costs were approved in 1999 by the
IURC and MPSC.

The amount of deferrals amortized to other O&M expenses were $40 million in
2003, 2002 and 2001. Also pursuant to the settlement agreements, accrued
fuel-related revenues of approximately $37 million in 2003 and $38 million in
2002 and 2001 were amortized as a reduction of revenues.

The amortization of O&M costs and fuel-related revenues deferred under Indiana
and Michigan retail jurisdictional settlement agreements adversely affected
results of operations through December 31, 2003 when the amortization period
ended.

Merger with CSW
---------------

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. The following table summarizes significant merger-related
agreements:

Summary of key provisions of Merger Rate Agreements:

         State/Company                   Ratemaking Provisions
         -------------                   ---------------------
         Texas - SWEPCo, TCC, TNC        $221 million rate
                                         reduction over 6 years. No base rate
                                         increases for 3 years post merger.

         Indiana - I&M                   $67 million rate reduction over 8
                                         years. Extension of base rate freeze
                                         until January 1, 2005. Requires
                                         additional annual deposits of $6
                                         million to the nuclear decommissioning
                                         trust fund for the years 2001 through
                                         2003.

         Michigan - I&M                  Customer billing credits of
                                         approximately $14 million over 8 years.
                                         Extension of base rate freeze until
                                         January 1, 2005.

         Kentucky - KPCo                 Rate reductions of approximately
                                         $28 million over 8 years. No base rate
                                         increases for 3 years post merger.

         Oklahoma - PSO                  Rate reductions of approximately
                                         $28 million over 5 years. No base rate
                                         increase before January 1, 2003.

         Arkansas - SWEPCo               Rate reductions of $6 million over 5
                                         years.No base rate increase before
                                         June 15, 2003

         Louisiana - SWEPCo              Rate reductions to share merger
                                         savings estimated to be $18 million
                                         over 8 years. Base rate cap until
                                         June 2005.

If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year
period following consummation of the merger, future results of operations,
cash flows and possibly financial condition could be adversely affected.

See Note 7, "Commitments and Contingencies" for information on a court decision
concerning the merger.


6.  CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
----------------------------------------------


Prior to 2003, retail customer choice began in four of the eleven state retail
jurisdictions (Michigan, Ohio, Texas and Virginia) in which the AEP domestic
electric utility companies operate. The following paragraphs discuss significant
events related to customer choice and industry restructuring.

OHIO RESTRUCTURING
------------------

On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy Users-Ohio and
American Municipal Power-Ohio filed a complaint with the PUCO alleging that
CSPCo and OPCo have violated the PUCO's orders regarding implementation of their
transition plan and violated the applicable law by failing to participate in an
RTO.

The complainants seek, among other relief, an order from the PUCO:
  o     suspending  collection  of transition  charges by CSPCo and OPCo until
        transfer of control of their  transmission  assets has occurred
  o     requiring the pricing of standard offer electric generation effective
        January 1, 2006 at the market price used by CSPCo and OPCo in their 1999
        transition plan filings to estimate transition costs and
  o     imposing a $25,000 per company forfeiture for each day AEP fails to
        comply with its commitment to transfer control of transmission assets
        to an RTO

Due to FERC, state legislative and regulatory developments, CSPCo and OPCo have
been delayed in the implementation of their RTO participation plans. We continue
to pursue integration of CSPCo, OPCo and other AEP East companies into PJM. In
this regard, on December 19, 2002, CSPCo and OPCo filed an application with the
PUCO for approval of the transfer of functional control over certain of their
transmission facilities to PJM. In February 2003, the PUCO consolidated the June
2002 complaint with our December application. CSPCo's and OPCo's motion to
dismiss the complaint has been denied by the PUCO and the PUCO affirmed that
ruling in rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC and
elsewhere." Management is currently unable to predict the timing of the AEP East
companies' (including CSPCo and OPCo) participation in PJM, the outcome of these
proceedings before the PUCO or their impact on results of operations and cash
flows.

In October 2002, the PUCO initiated an investigation of the financial condition
of Ohio's regulated public utilities. The PUCO's goal is to identify measures
available to the PUCO to ensure that the regulated operations of Ohio's public
utilities are not impacted by adverse financial consequences of parent or
affiliate company unregulated operations and take appropriate corrective action,
if necessary. The utilities and other interested parties were requested to
provide comments and suggestions by November 12, 2002, with reply comments by
November 22, 2002, on the type of information necessary to accomplish the stated
goals, the means to gather the required information from the public utilities
and potential courses of action that the PUCO could take. In January 2004, the
PUCO staff issued a report recommending that the PUCO seek more authority from
the Ohio Legislature on this issue. The PUCO has taken no further action in this
proceeding. Management is unable to predict the outcome of the PUCO's
investigation or its impact on results of operations, cash flows and business
practices, if any.

On March 20, 2003, the PUCO commenced a statutorily required investigation
concerning the desirability, feasibility and timing of declaring retail
ancillary, metering or billing and collection service, supplied to customers
within the certified territories of electric utilities, a competitive retail
electric service. The PUCO sent out a list of questions and set June 6, 2003 and
July 7, 2003 as the dates for initial responses and replies, respectively. CSPCo
and OPCo filed comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this proceeding or
its impact on results of operations or cash flows.

The Ohio Act provides for a Market Development Period (MDP) during which retail
customers can choose their electric power suppliers or receive Default Service
at frozen generation rates from the incumbent utility. The MDP began on January
1, 2001 and is scheduled to terminate no later than December 31, 2005. The PUCO
may terminate the MDP for one or more customer classes before that date if it
determines either that effective competition exists in the incumbent utility's
certified territory or that there is a twenty percent switching rate of the
incumbent utility's load by customer class. Following the MDP, retail customers
will receive distribution and transmission service from the incumbent utility
whose distribution rates will be approved by the PUCO and whose transmission
rates will be approved by the FERC. Retail customers will continue to have the
right to choose their electric power suppliers or receive Default Service, which
must be offered by the incumbent utility at market rates. On December 17, 2003,
the PUCO adopted a set of rules concerning the method by which it will determine
market rates for Default Service following the MDP. The rule provides for a
Market Based Standard Service Offer which would be a variable rate based on a
transparent forward market, daily market, and/or hourly market prices. The rule
also requires a fixed-rate Competitive Bidding Process for residential and small
nonresidential customers and permits a fixed-rate Competitive Bidding Process
for large general service customers and other customer classes. Customers who do
not switch to a competitive generation provider can choose between the Market
Based Standard Service Offer or the Competitive Bidding Process. Customers who
make no choice will be served pursuant to the Competitive Bidding Process.

On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan with the
PUCO addressing rates following the end of the MDP, which ends December 31,
2005. If approved by the PUCO, rates would be established pursuant to the plan
for the period from January 1, 2006 through December 31, 2008 instead of the
rates discussed in the previous paragraph. The plan is intended to provide rate
stability and certainty for customers, facilitate the development of a
competitive retail market in Ohio, provide recovery of environmental and other
costs during the plan period and improve the environmental performance of AEP's
generation resources that serve Ohio customers. The plan includes annual, fixed
increases in the generation component of all customers' bills (3% annually for
CSPCo and 7% annually for OPCo), and the opportunity for additional
generation-related increases upon PUCO review and approval. For residential
customers, however, if the temporary 5% generation rate discount provided by the
Ohio Act were eliminated on June 30, 2004, the fixed increases would be 1.6% for
CSPCo and 5.7% for OPCo. The generation-related increases under the plan would
be subject to caps. The plan would maintain distribution rates through the end
of 2008 for CSPCo and OPCo at the level effective on December 31, 2005. Such
rates could be adjusted for specified reasons through a PUCO filing.
Transmission charges can be adjusted to reflect applicable charges approved by
the FERC related to open access transmission, net congestion, and ancillary
services. The plan also provides for continued recovery of transition regulatory
assets and deferral of regulatory assets in 2004 and 2005 for RTO costs and
carrying costs on required environmental expenditures. A procedural schedule has
not been established for this filing. Management cannot predict whether the plan
will be approved as submitted, modified by the PUCO, or its impacts on results
of operation and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000, we are
deferring customer choice implementation costs and related carrying costs that
are in excess of $40 million. The agreements provide for the deferral of these
costs as a regulatory asset until the next distribution base rate cases. The
February 2004 filing provides for the continued deferral of customer choice
implementation costs during the rate stabilization plan period. At December 31,
2003, we have incurred $66 million and deferred $26 million of such costs.
Recovery of these regulatory assets will be subject to PUCO review in future
Ohio filings for new distribution rates. If the rate stabilization plan is
approved, it would defer recovery of these amounts until after the end of the
rate stabilization period. Management believes that the customer choice
implementation costs were prudently incurred and the deferred amounts should be
recoverable in future rates. If the PUCO determines that any of the deferred
costs are unrecoverable, it would have an adverse impact on future results of
operations and cash flows.

TEXAS RESTRUCTURING
-------------------

Texas Legislation enacted in 1999 provided the framework and timetable to allow
retail electricity competition for all customers. On January 1, 2002, customer
choice of electricity supplier began in the ERCOT area of Texas. Customer choice
has been delayed in the SPP area of Texas until at least January 1, 2007.

The Texas Legislation, among other things:
  o     provides for the recovery of regulatory assets and other stranded costs
        through securitization and non-bypassable wires charges;
  o     requires each utility to structurally unbundle into a retail electric
        provider, a power generation company and a transmission and distribution
        (T&D) utility;
  o     provides for an earnings test for each of the years 1999 through 2001
        and;
  o     provides for a 2004 true-up proceeding. See 2004 true-up proceeding
        discussion below.

The Texas Legislation required vertically integrated utilities to legally
separate their generation and retail-related assets from their transmission and
distribution-related assets. Prior to 2002, TCC and TNC functionally separated
their operations to comply with the Texas Legislation requirements. AEP formed
new subsidiaries to act as affiliated REPs for TCC and TNC effective January 1,
2002 (the start date of retail competition). In December 2002, AEP sold the
affiliated REPs to an unaffiliated company.

In 1999, TCC filed with the PUCT to securitize $1.27 billion of its retail
generation-related regulatory assets and $47 million in other qualified
restructuring costs. The PUCT authorized the issuance of up to $797 million of
securitization bonds ($949 million of generation-related regulatory assets and
$33 million of qualified refinancing costs offset by $185 million of customer
benefits for accumulated deferred income taxes). TCC issued its securitization
bonds in February 2002. The amount not approved for securitization will be
included in regulatory assets/stranded costs in TCC's 2004 true-up proceeding.

TEXAS 2004 TRUE-UP PROCEEDING
-----------------------------

A 2004 true-up proceeding will determine the amount and recovery of:
  o     net stranded generating plant costs and generation-related regulatory
        assets (stranded costs),
  o     a true-up of actual market prices determined through legislatively-
        mandated capacity auctions to the power costs used in the PUCT's ECOM
        model for 2002 and 2003 (wholesale capacity auction true-up),
  o     final approved deferred fuel balance,
  o     unrefunded accumulated excess earnings,
  o     excess of price-to-beat revenues over market prices subject to certain
        conditions and limitations (retail clawback) and
  o     other restructuring true-up items

The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TNC's filing in May 2004 and TCC's filing in September
2004 or 60 days after the completion of the sale of TCC's generation assets, if
later.

Stranded Costs and Generation-Related Regulatory Assets
-------------------------------------------------------

Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generating assets for determining stranded
costs. TCC is the only AEP subsidiary that has stranded costs under the Texas
Legislation. We have elected to use the sale of assets method to determine the
market value of all of our generation assets for stranded cost purposes. When
completed, the sale of our generation assets will substantially complete the
required separation of generation assets from transmission and distribution
assets. For purposes of the 2004 true-up proceeding, the amount of stranded
costs under this market valuation methodology will be the amount by which the
book value of TCC's generating assets, including regulatory assets and
liabilities that were not securitized, exceeds the market value of the
generation assets as measured by the net proceeds from the sale of the assets.
It is anticipated that any such sale will result in significant stranded costs
for purposes of TCC's 2004 true-up proceeding.

In December 2002, TCC filed a plan of divestiture with the PUCT seeking approval
of a sales process for all of its generating facilities. In March 2003, the PUCT
dismissed TCC's divestiture filing, determining that it was more appropriate to
address allowable valuation methods for the nuclear asset in a rulemaking
proceeding. The PUCT approved a rule, in May 2003, which allows the market value
obtained by selling nuclear assets to be used in determining stranded costs.
Although the PUCT declined to review TCC's proposed sale of assets process, the
PUCT has hired a consultant to advise TCC during the sale of the generation
assets. TCC's sale of its generating assets will be subject to a review in the
2004 true-up proceeding.

In June 2003, we began actively seeking buyers for 4,497 megawatts of TCC's
generating capacity in Texas. In order to sell these assets, we anticipate
retiring TCC's first mortgage bonds by making open market purchases or defeasing
the bonds. Bids were received for all of TCC's generating plants. In January
2004, TCC agreed to sell its 7.8% ownership interest in the Oklaunion Power
Station to an unaffiliated third party for $43 million. The sale of TCC's
remaining generation is pending. Additional regulatory approvals will be
required to complete the sale of the generation assets, including NRC approval
of the transfer of our interest in STP.

In the 2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of TCC's
generating assets, including regulatory assets and liabilities that were not
securitized and reduced by mitigation including unrefunded excess earnings,
exceeds the market value of the generation assets as measured by the net
proceeds from the sale of the assets. It is anticipated that any such sale will
result in significant stranded costs for purposes of TCC's 2004 true-up
proceeding.

After the 2004 true-up proceeding, TCC may seek to issue securitization revenue
bonds for its stranded costs and recover the costs of the securitization bonds
through transmission and distribution rates. Based upon the Oklaunion sale and
the bid information for the remaining generation, we recorded an impairment of
generating assets of $938 million in December 2003 as a regulatory asset (see
Note 10). The recovery of the regulatory asset will be subject to review and
approval by the PUCT as a stranded cost in the 2004 true-up proceeding.

Wholesale Capacity Auction True-up
----------------------------------

Texas Legislation also requires that electric utilities and their affiliated
power generation companies (PGC) offer for sale at auction, in 2002 and 2003 and
after, at least 15% of the PGC's Texas jurisdictional installed generation
capacity in order to promote competitiveness in the wholesale market through
increased availability of generation. Actual market power prices received in the
state mandated auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding.

TCC recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction true-up for
the years 2002 and 2003. In TCC's UCOS proceeding, the PUCT estimated that TCC
had negative stranded costs. In its true-up rule, the PUCT determined that the
wholesale capacity auction true-up proceeds should be offset against negative
stranded costs. However, in March 2003, the Texas Court of Appeals ruled that
under the restructuring legislation, other 2004 true-up items, including the
wholesale capacity auction true-up regulatory asset, could be recovered
regardless of the level of stranded costs.


In the fourth quarter of 2003, the PUCT approved a true-up filing package
containing calculation instructions similar to the methodology employed by TCC
to calculate the amount recorded for recovery under its wholesale capacity
auction true-up. The PUCT will review the $480 million wholesale capacity
regulatory asset for recovery as part of the 2004 true-up proceeding.

Fuel Balance Recoveries
-----------------------

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up proceeding. In
January 2004, the PUCT announced a final ruling in TNC's fuel reconciliation
case that established TNC's unrecovered fuel balance, including interest for the
ERCOT service territory, at $6.2 million. This balance will be included in TNC's
2004 true-up proceeding. TNC is waiting for a written order from the PUCT, after
which it will request a rehearing.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to establish its
deferred over-recovery of fuel balance for inclusion in the 2004 true-up
proceeding. In February 2004, an ALJ issued recommendations finding a $205
million over-recovery in this fuel proceeding. Management is unable to predict
the amount of TCC's fuel over-recovery which will be included in its 2004
true-up proceeding.

See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 "Rate Matters"
for further discussion.

Unrefunded Excess Earnings
--------------------------

The Texas Legislation provides for the calculation of excess earnings for each
year from 1999 through 2001. The total excess earnings determined for the three
year period were $3 million for SWEPCo, $47 million for TCC and $19 million for
TNC. TCC, TNC and SWEPCo challenged the PUCT's treatment of fuel-related
deferred income taxes and appealed the PUCT's final 2000 excess earnings to the
Travis County District Court which upheld the PUCT ruling. The District Court's
ruling was appealed to the Third Court of Appeals. In August 2003, the Third
Court of Appeals reversed the PUCT order and the District Court's judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied and the
PUCT chose not to appeal the ruling any further. Appeal of the same issue from
the PUCT's 2001 order is pending before the District Court. Since an expense and
regulatory liability had been accrued in prior years in compliance with the PUCT
orders, the companies reversed a portion of their regulatory liability for the
years 2000 and 2001 consistent with the Appeals Court's decision and credited
amortization expense during the third quarter of 2003. Pre-tax amounts reversed
by company were $5 million for TCC, $3 million for TNC and $1 million for
SWEPCo.

In 2001, the PUCT issued an order requiring TCC to return estimated excess
earnings by reducing distribution rates by approximately $55 million plus
accrued interest over a five-year period beginning January 1, 2002. Since excess
earnings amounts were expensed in 1999, 2000 and 2001, the order has no
additional effect on reported net income but will reduce cash flows for the
five-year refund period. The amount to be refunded is recorded as a regulatory
liability. Management believes that TCC will have stranded costs and that it was
inappropriate for the PUCT to order a refund prior to TCC's 2004 true-up
proceeding. TCC appealed the PUCT's refund of excess earnings to the Travis
County District Court. That court affirmed the PUCT's decision and further
ordered that the refunds be provided to customers. TCC has appealed the decision
to the Court of Appeals.

Retail Clawback
---------------

The Texas Legislation provides for the affiliated PTB REP serving residential
and small commercial customers to refund to its T&D utility the excess of the
PTB revenues over market prices (subject to certain conditions and a limitation
of $150 per customer). This is the retail clawback. If, prior to January 1,
2004, 40% of the load for the residential or small commercial classes is served
by competitive REPs, the retail clawback is not applicable for that class of
customer. During 2003, TCC and TNC filed to notify the PUCT that competitive
REPs serve over 40% of the load in the small commercial class. The PUCT approved
TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a regulatory
liability of approximately $9 million for the small commercial retail clawback
on its REP's books. When the PUCT certified that the REP's in TCC and TNC
service territories had reached the 40% threshold, the regulatory liability was
no longer required for the small commercial class and was reversed in December
2003. At December 31, 2003, the remaining retail clawback regulatory liability
was $57 million.

When the 2004 true-up proceeding is completed, TCC intends to file to recover
PUCT-approved stranded costs and other true-up amounts that are in excess of
current securitized amounts, plus appropriate carrying charges and other true-up
amounts, through non-bypassable competition transition charge in the regulated
T&D rates. TCC may also seek to securitize certain of the approved stranded
plant costs and regulatory assets that were not previously recovered through the
non-bypassable transition charge. The annual costs of securitization are
recovered through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.

In the event we are unable, after the 2004 true-up proceeding, to recover all or
a portion of our stranded plant costs, generation-related regulatory assets,
unrecovered fuel balances, wholesale capacity auction true-up regulatory assets,
other restructuring true-up items and costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.

MICHIGAN RESTRUCTURING
----------------------

Customer choice commenced for I&M's Michigan customers on January 1, 2002.
Effective with that date the rates on I&M's Michigan customers' bills for retail
electric service were unbundled to allow customers the opportunity to evaluate
the cost of generation service for comparison with other offers. I&M's total
rates in Michigan remain unchanged and reflect cost of service. At December 31,
2003, none of I&M's customers have elected to change suppliers and no
alternative electric suppliers are registered to compete in I&M's Michigan
service territory.

Management has concluded that as of December 31, 2003 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan continue
to be cost-based regulated.

ARKANSAS RESTRUCTURING
----------------------

In February 2003, Arkansas repealed customer choice legislation originally
enacted in 1999. Consequently, SWEPCo's Arkansas operations reapplied SFAS 71
regulatory accounting, which had been discontinued in 1999. The reapplication of
SFAS 71 had an insignificant effect on results of operations and financial
condition. As a result of reapplying SFAS 71, derivative contract gains/losses
for transactions within AEP's traditional marketing area allocated to Arkansas
will not affect income until settled. That is, such positions will be recorded
on the balance sheet as either a regulatory asset or liability until realized.

WEST VIRGINIA RESTRUCTURING
---------------------------

APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the first
quarter of 2003 after new developments during the quarter prompted an analysis
of the probability of restructuring becoming effective.

In 2000, the WVPSC issued an order approving an electricity restructuring plan,
which the WV Legislature approved by joint resolution. The joint resolution
provided that the WVPSC could not implement the plan until the WV legislature
made tax law changes necessary to preserve the revenues of state and local
governments.

In the 2001 and 2002 legislative sessions, the WV Legislature failed to enact
the required legislation that would allow the WVPSC to implement the
restructuring plan. Due to this lack of legislative activity, the WVPSC closed
two proceedings related to electricity restructuring during the summer of 2002.

In the 2003 legislative session, the WV Legislature failed to enact the required
tax legislation. Also, legislation enacted in March 2003 clarified the
jurisdiction of the WVPSC over electric generation facilities in WV. In March
2003, APCo's outside counsel advised us that restructuring in WV was no longer
probable and confirmed facts relating to the WVPSC's jurisdiction and rate
authority over APCo's WV generation. APCo has concluded that deregulation of the
WV generation business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.

Reapplying SFAS 71 in WV had an insignificant effect on results of operations
and financial condition. As a result, derivative contract gains/losses related
to transactions within AEP's traditional marketing area allocated to WV will not
affect income until settled. That is, such positions will be recorded on the
balance sheet as either a regulatory asset or liability until realized.
Positions outside AEP's traditional marketing area will continue to be
marked-to-market.


7.  COMMITMENTS AND CONTINGENCIES
---------------------------------


ENVIRONMENTAL
-------------

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

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

Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In 2001,
the District Court ruled claims for civil penalties based on activities that
occurred more than five years before the filing date of the complaints cannot be
imposed. There is no time limit on claims for injunctive relief.

On August 7, 2003, the District Court issued a decision following a liability
trial in a case pending in the Southern District of Ohio against Ohio Edison
Company, an unaffiliated utility. The District Court held that replacements of
major boiler and turbine components that are infrequently performed at a single
unit, that are performed with the assistance of outside contractors, that are
accounted for as capital expenditures, and that require the unit to be taken out
of service for a number of months are not "routine" maintenance, repair, and
replacement. The District Court also held that a comparison of past actual
emissions to projected future emissions must be performed prior to any
non-routine physical change in order to evaluate whether an emissions increase
will occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all of the
challenged activities in that case were not routine, and that the changes
resulted in significant net increases in emissions for certain pollutants. A
remedy trial is scheduled for July 2004.

Management believes that the Ohio Edison decision fails to properly evaluate
and apply the applicable legal standards. The facts in our case also vary widely
from plant to plant. Further, the Ohio Edison decision is limited to liability
issues, and provides no insight as to the remedies that might ultimately be
ordered by the Court.

On August 26, 2003, the District Court for the Middle District of South Carolina
issued a decision on cross-motions for summary judgment prior to a liability
trial in a case pending against Duke Energy Corporation, an unaffiliated
utility. The District Court denied all the pending motions, but set forth the
legal standards that will be applied at the trial in that case. The District
Court determined that the Federal EPA bears the burden of proof on the issue of
whether a practice is "routine maintenance, repair, or replacement" and on
whether or not a "significant net emissions increase" results from a physical
change or change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the relevant
source category" in determining if it is "routine." Further, the Federal EPA
must calculate emissions by determining first whether a change in the maximum
achievable hourly emission rate occurred as a result of the change, and then
must calculate any change in annual emissions holding hours of operation
constant before and after the change. The Federal EPA has requested
reconsideration of this decision, or in the alternative, certification of an
interlocutory appeal to the Fourth Circuit Court of Appeals.

On June 24, 2003, the United States Court of Appeals for the 11th Circuit issued
an order invalidating the administrative compliance order issued by the Federal
EPA to the Tennessee Valley Authority for alleged Clean Air Act violations. The
11th Circuit determined that the administrative compliance order was not a final
agency action, and that the enforcement provisions authorizing the issuance and
enforcement of such orders under the Clean Air Act are unconstitutional.

On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group (UARG),
of which our subsidiaries are members, to reopen petitions for review of the
1980 and 1992 Clean Air Act rulemakings that are the basis for the Federal EPA
claims in our case and other related cases. On August 4, 2003, UARG filed a
motion to separate and expedite review of their challenges to the 1980 and 1992
rulemakings from other unrelated claims in the consolidated appeal. The Circuit
Court denied that motion on September 30, 2003. The central issue in these
petitions concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement actions.
A decision by the D. C. Circuit Court could significantly impact further
proceedings in our case.

On August 27, 2003, the Administrator of the Federal EPA signed a final rule
that defines "routine maintenance repair and replacement" to include
"functionally equivalent equipment replacement." Under the new final rule,
replacement of a component within an integrated industrial operation (defined as
a "process unit") with a new component that is identical or functionally
equivalent will be deemed to be a "routine replacement" if the replacement does
not change any of the fundamental design parameters of the process unit, does
not result in emissions in excess of any authorized limit, and does not cost
more than twenty percent of the replacement cost of the process unit. The new
rule is intended to have prospective effect, and will become effective in
certain states 60 days after October 27, 2003, the date of its publication in
the Federal Register, and in other states upon completion of state processes to
incorporate the new rule into state law. On October 27, 2003 twelve states, the
District of Columbia and several cities filed an action in the United States
Court of Appeals for the District of Columbia Circuit seeking judicial review of
the new rule. The UARG has intervened in this case. On December 24, 2003, the
Circuit Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.

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

In December 2000, Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo, reached a tentative agreement with the Federal
EPA and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an
attempt to reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned
25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.

NUCLEAR
-------

Nuclear Plants
--------------

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by
the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on
behalf of the joint owners under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and specific
regulatory and safety requirements. Should a nuclear incident occur at any
nuclear power plant facility in the U.S., the resultant liability could be
substantial. By agreement I&M and TCC are partially liable together with all
other electric utility companies that own nuclear generating units for a nuclear
power plant incident at any nuclear plant in the U.S. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds and recovery
from customers is not possible, results of operations, cash flows and financial
condition would be adversely affected.

Nuclear Incident Liability
--------------------------

The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $10.6 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $300
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $101 million on each licensed reactor in the U.S. payable in
annual installments of $10 million. As a result, I&M could be assessed $202
million per nuclear incident payable in annual installments of $20 million. TCC
could be assessed $50 million per nuclear incident payable in annual
installments of $5 million as its share of a STPNOC assessment. The number of
incidents for which payments could be required is not limited. Under an
industry-wide program insuring workers at nuclear facilities, I&M and TCC are
also obligated for assessments of up to $6 million and $2 million, respectively,
for potential claims. These obligations will remain in effect until December 31,
2007.

Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. I&M and STPNOC jointly purchase $1 billion of excess coverage for
property damage, decommissioning and decontamination. Additional insurance
provides coverage for extra costs resulting from a prolonged accidental outage.
I&M and STPNOC utilize an industry mutual insurer for the placement of this
insurance coverage. Participation in this mutual insurer requires a contingent
financial obligation of up to $43 million for I&M and $2 million for TCC which
is assessable if the insurer's financial resources would be inadequate to pay
for losses.

The current Price-Anderson Act expired in August 2002. Its contingent financial
obligations still apply to reactors licensed by the NRC as of its expiration
date. It is anticipated that the Price-Anderson Act will be renewed in 2004 with
increases in required third party financial protection for nuclear incidents.

SNF Disposal
------------

Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $226 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2003, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and exceed the liability amount. TCC is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal
---------------------------------------------------------

Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. In November 2003, I&M filed to extend the operating licenses of the
two Cook Plant units for up to an additional 20 years. The review of the license
extension application is expected to take at least two years. After expiration
of the licenses, Cook Plant is expected to be decommissioned using the prompt
decontamination and dismantlement (DECON) method. The estimated cost of
decommissioning and low level radioactive waste accumulation disposal costs for
Cook Plant ranges from $821 million to $1,080 million in 2003 nondiscounted
dollars. The wide range is caused by variables in assumptions including the
estimated length of time SNF may need to be stored at the plant site subsequent
to ceasing operations. This, in turn, depends on future developments in the
federal government's SNF disposal program. Continued delays in the federal fuel
disposal program can result in increased decommissioning costs. I&M is
recovering estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $27 million in 2003, 2002 and 2001.

The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
DECON method. TCC estimates its portion of the costs of decommissioning STP to
be $289 million in 1999 nondiscounted dollars. TCC is accruing and recovering
these decommissioning costs through rates based on the service life of STP at a
rate of $8 million per year.

Decommissioning costs recovered from customers are deposited in external trusts.
In 2003, 2002 and 2001, I&M deposited in its decommissioning trust an additional
$12 million each year related to special regulatory commission approved funding
for decommissioning of the Cook Plant. Trust fund earnings increase the fund
assets and decrease the amount needed to be recovered from ratepayers.
Decommissioning costs including interest, unrealized gains and losses and
expenses of the trust funds are recorded in Other Operation expense for Cook
Plant. For STP, nuclear decommissioning costs are recorded in Other Operation
expense, interest income of the trusts are recorded in Nonoperating Income and
interest expense of the trust funds are included in Interest Charges.

TCC's nuclear decommissioning trust asset and liability are included in held for
sale amounts on the Consolidated Balance Sheets.

OPERATIONAL
-----------

Construction and Commitments
----------------------------

The AEP System has substantial construction commitments to support its
operations. Aggregate construction expenditures for 2004-2006 for consolidated
domestic and foreign operations are estimated to be $5.8 billion including
amounts for proposed environmental rules.

Our subsidiaries have entered into long-term contracts to acquire fuel for
electric generation. The longest contract extends to the year 2014. The
contracts provide for periodic price adjustments and contain various clauses
that would release the subsidiaries from their obligations under certain
conditions.

The AEP System has unit contingent contracts to supply approximately 250 MW of
capacity to unaffiliated entities through December 31, 2009. The commitment is
pursuant to a unit power agreement requiring the delivery of energy only if the
unit capacity is available.

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

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

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

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).

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

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

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

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

See further discussion in Notes 10 and 16.

Merger Litigation
-----------------

In 2002, the U.S. Court of Appeals for the District of Columbia ruled that the
SEC failed to prove that the June 15, 2000 merger of AEP with CSW meets the
requirements of the PUHCA and sent the case back to the SEC for further review.
Specifically, the court told the SEC to revisit its conclusion that the merger
met PUHCA requirements that utilities be "physically interconnected" and
confined to a "single area or region."

In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUCHA's single
region requirement because it is now technically possible to centrally control
the output of power plants across many states. In its ruling, the appeals court
said that the SEC failed to support and explain its conclusions that the
integration and single region requirements are satisfied.

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

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

On October 15, 2002, certain subsidiaries of AEP filed claims against Enron and
its subsidiaries in the bankruptcy proceeding filed by the Enron entities which
are pending in the U.S. Bankruptcy Court for the Southern District of New York.
At the date of Enron's bankruptcy, certain subsidiaries of AEP had open trading
contracts and trading accounts receivables and payables with Enron. In addition,
on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron.
Various HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron's bankruptcy. The timing of the resolution of the claims by
the Bankruptcy Court is not certain.

In connection with the 2001 acquisition of HPL, we acquired exclusive rights to
use and operate the underground Bammel gas storage facility pursuant to an
agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
exclusive right to use the referenced facility is for a term of 30 years, with a
renewal right for another 20 years and includes the use of the Bammel storage
facility and the appurtenant pipelines. We have engaged in discussions with
Enron concerning the possible purchase of the Bammel storage facility and
related assets, the possible resolution of outstanding issues between AEP and
Enron relating to our acquisition of HPL and the possible resolution of
outstanding energy trading issues. We have considered the possible outcomes of
these issues in our impairment analysis of HPL; however, actual results could
differ from those estimates. We are unable to predict whether these discussions
will lead to an agreement on these subjects. In January 2004, AEP and its
subsidiaries filed an amended lawsuit against Enron and its subsidiaries in the
U.S. Bankruptcy Court claiming that Enron does not have the right to reject the
Bammel storage facility agreement or the cushion gas use agreement, described
below. In February 2004 Enron filed Notices of Rejection regarding the cushion
gas use agreement and other incidental agreements. We have objected to Enron's
attempted rejection of these agreements. Management is unable to predict the
outcome of these proceedings or the impact on results of operations, cash flows
or financial condition.

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

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

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

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

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

Shareholder Lawsuits
--------------------

In the fourth quarter of 2002 and the first quarter of 2003, lawsuits alleging
securities law violations and seeking class action certification were filed in
federal District Court, Columbus, Ohio against AEP, certain AEP executives, and
in some of the lawsuits, members of the AEP Board of Directors and certain
investment banking firms. The lawsuits claim that we failed to disclose that
alleged "round trip" trades resulted in an overstatement of revenues, that we
failed to disclose that our traders falsely reported energy prices to trade
publications that published gas price indices and that we failed to disclose
that we did not have in place sufficient management controls to prevent "round
trip" trades or false reporting of energy prices. The plaintiffs seek recovery
of an unstated amount of compensatory damages, attorney fees and costs. The
Court has appointed a lead plaintiff who has filed a Consolidated Amended
Complaint. We have filed a Motion to Dismiss the Consolidated Amended Complaint.
The Motion has been briefed by the parties. Also, in the first quarter of 2003,
a lawsuit making essentially the same allegations and demands was filed in state
Common Pleas Court, Columbus, Ohio against AEP, certain executives, members of
the Board of Directors and our independent auditor. We removed this case to
federal District Court in Columbus and the Court has denied plaintiff's motion
to remand the case to state court. We have moved to consolidate this case with
the other pending cases. We intend to continue to vigorously defend against
these actions.

In the fourth quarter of 2002, two shareholder derivative actions were filed in
state court in Columbus, Ohio against AEP and its Board of Directors alleging a
breach of fiduciary duty for failure to establish and maintain adequate internal
controls over our gas trading operations. These cases have been stayed pending
the outcome of our Motion to Dismiss the Consolidated Amended Complaint in the
federal securities lawsuits. If these cases do proceed, we intend to vigorously
defend against them. Also, in the fourth quarter of 2002 and the first quarter
of 2003, three putative class action lawsuits were filed against AEP, certain
executives and AEP's Employee Retirement Income Security Act (ERISA) Plan
Administrator alleging violations of ERISA in the selection of AEP stock as an
investment alternative and in the allocation of assets to AEP stock. The ERISA
actions are pending in federal District Court, Columbus, Ohio. In these actions,
the plaintiffs seek recovery of an unstated amount of compensatory damages,
attorney fees and costs. We have filed a Motion to Dismiss these actions. The
parties have fully briefed this Motion. We intend to continue to vigorously
defend against these claims.

California Lawsuits
-------------------

In November 2002, the Lieutenant Governor of California filed a lawsuit in Los
Angeles County, California Superior Court against forty energy companies,
including AEP, and two publishing companies alleging violations of California
law through alleged fraudulent reporting of false natural gas price and volume
information with an intent to affect the market price of natural gas and
electricity. This case is in the initial pleading stage and all defendants have
filed motions to dismiss. AEP has been dismissed from the case. The plaintiff
had stated an intention to amend the complaint to add an AEP subsidiary as a
defendant. The plaintiff amended the complaint but did not name any AEP company
as a defendant. In November 2003, Texas-Ohio Energy, Inc. filed a lawsuit in the
United States District Court for the Eastern District of California alleging
that AEP and a large number of other energy companies conspired to manipulate
natural gas prices in California in violation of federal and state antitrust and
unfair competition laws. Certain of the other defendants in this case have filed
a Notice of Potential Tag-Along Action with the Judicial Panel on Multi-District
Litigation seeking to have this case transferred to the United States District
Court for the District of Nevada where there are a number of other cases now
pending that assert claims regarding the alleged manipulation of energy markets
in California. None of the AEP companies is a party to these other pending
cases. Once venue for the Texas-Ohio Energy, Inc. case is determined, we plan to
move to dismiss the complaint and otherwise vigorously defend against these
claims. In February 2004, two individuals on behalf of themselves and two
businesses they own and another individual filed an action in state court in San
Diego County, California against a large number of energy companies including
AEPES. This action alleges violations of state antitrust and unfair competition
laws based on alleged manipulation of gas price indices. This case is in the
initial pleading states. We plan to vigorously defend against these claims.

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

In the third quarter of 2003, Cornerstone Propane Partners filed an action in
the United States District Court for the Southern District of New York against
forty companies, including AEP and AEPES seeking class certification and
alleging unspecified damages from claimed price manipulation of natural gas
futures and options on the NYMEX from January 2000 through December 2002.
Thereafter, two similar actions were filed in the same court against a number of
companies including AEP and AEPES making essentially the same claims as
Cornerstone Propane Partners and also seeking class certification. On December
5, 2003, the Court issued its initial Pretrial Order consolidating all related
cases, appointing co-lead counsel and providing for the filing of an amended
consolidated complaint. In January 2004, plaintiffs filed an amended
consolidated complaint. We plan to move to dismiss the complaint and otherwise
vigorously defend against these claims.

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

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in federal
District Court in Corpus Christi, Texas, in July 2003, against us and four AEP
subsidiaries, certain unaffiliated energy companies and ERCOT. The action
alleges violations of the Sherman Antitrust Act, fraud, negligent
misrepresentation, breach of fiduciary duty, breach of contract, civil
conspiracy and negligence. The allegations, not all of which are made against
the AEP companies, range from anticompetitive bidding to withholding power. TCE
alleges that these activities resulted in price spikes requiring TCE to post
additional collateral and ultimately forced it into bankruptcy when it was
unable to raise prices to its customers due to fixed price contracts. The suit
alleges over $500 million in damages for all defendants and seeks recovery of
damages, exemplary damages and court costs. Two additional parties, Utility
Choice, LLC and Cirro Energy Corporation, have sought leave to intervene as
plaintiffs asserting similar claims. We filed a Motion to Dismiss in September
2003. In February 2004, TCE filed an amended complaint. We intend to file a
motion to dismiss the amended complaint and otherwise vigorously defend against
the claims.

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

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading deals
and claimed that we owed approximately $34 million. In April 2003, we filed a
lawsuit in federal District Court in Columbus, Ohio against BOM claiming BOM had
acted contrary to the appropriate trading contract and industry practice in
terminating the contract and calculating termination and liquidation amounts and
that BOM had acknowledged just prior to the termination and liquidation that it
owed us approximately $68 million. We are claiming that BOM owes us at least $45
million. Although management is unable to predict the outcome of this matter, it
is not expected to have a material impact on results of operations, cash flows
or financial condition.

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

In October 2002, we filed a demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding resulted from Williams'
repudiation of its obligations to provide physical power deliveries to AEP and
Williams' failure to provide the monetary security required for natural gas
deliveries by AEP. Consequently, both parties claimed default and terminated all
outstanding natural gas and electric power trading deals among the various
Williams and AEP affiliates. Williams claimed that we owed approximately $130
million in connection with the termination and liquidation of all trading deals.
Williams and AEP settled the dispute and we paid $90 million to Williams in June
2003. The settlement amount approximated the amount payable that, in the
ordinary course of business, we recorded as part of our trading activity using
MTM accounting. As a result, the resolution of this matter did not have a
material impact on results of operations or financial condition.

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

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

Energy Market Investigation
---------------------------

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

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

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

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

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

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

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

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

A FERC order issued in November 2001 on AEP's triennial market based wholesale
power rate authorization update required certain mitigation actions that AEP
would need to take for sales/purchases within its control area and required AEP
to post information on its website regarding its power system's status. As a
result of a request for rehearing filed by AEP and other market participants,
FERC issued an order delaying the effective date of the mitigation plan until
after a planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a technical
conference in January 2004. Management is unable to predict the timing of any
further action by the FERC or its affect of future results of operations and
cash flows.


8.  GUARANTEES
---------------


There are no liabilities recorded for guarantees entered into prior to December
31, 2002 in accordance with FIN 45. There are certain immaterial liabilities
recorded for guarantees entered into subsequent to December 31, 2002. There is
no collateral held in relation to any guarantees and there is no recourse to
third parties in the event any guarantees are drawn unless specified below.

LETTERS OF CREDIT
-----------------

We have entered into standby letters of credit (LOC) with third parties. These
LOCs cover gas and electricity risk management contracts, construction
contracts, insurance programs, security deposits, debt service reserves and
credit enhancements for issued bonds. All of these LOCs were issued by us in the
ordinary course of business. At December 31, 2003, the maximum future payments
for all the LOCs are approximately $227 million with maturities ranging from
January 2004 to January 2011. Included in these amounts is TCC's LOC of
approximately $43 million with a maturity date of November 3, 2005. As the
parent of all these subsidiaries, we hold all assets of the subsidiaries as
collateral. There is no recourse to third parties in the event these letters of
credit are drawn.

We have guaranteed 50% of the principal and interest payments as well as 100% of
a Power Purchase Agreement (PPA) of Fort Lupton, an IPP of which we are a 50%
owner. In the event Fort Lupton does not make the required debt payments, we
have a maximum future payment exposure of approximately $7 million, which
expires May 2008.

In the event Fort Lupton is unable to perform under its PPA agreement, we have a
maximum future payment exposure of approximately $15 million, which expires June
2019.

We have guaranteed 50% of a security deposit for gas transmission as well as 50%
of a Power Purchase Agreement (PPA) of Orange Cogeneration (Orange), an IPP of
which we are a 50% owner. In the event Orange fails to make payments in
accordance with agreements for gas transmission, we have a maximum future
payment exposure of approximately $1 million, which expires June 2023. In the
event Orange is unable to perform under its PPA agreement, we have a maximum
future payment exposure of approximately $1 million, which expires June 2016.

GUARANTEES OF THIRD-PARTY OBLIGATIONS
-------------------------------------

CSW Energy and CSW International
--------------------------------

CSW Energy and CSW International have guaranteed 50% of the required debt
service reserve of Sweeny Cogeneration (Sweeny), an IPP of which CSW Energy is a
50% owner. The guarantee was provided in lieu of Sweeny funding the debt reserve
as a part of a financing. In the event that Sweeny does not make the required
debt payments, CSW Energy and CSW International have a maximum future payment
exposure of approximately $4 million, which expires June 2020.

AEP Utilities
-------------

AEP Utilities guaranteed 50% of the required debt service reserve for Polk Power
Partners, an IPP of which CSW Energy owns 50%. In the event that Polk Power does
not make the required debt payments, AEP Utilities has a maximum future payment
exposure of approximately $5 million, which expires July 2010.

SWEPCo
------

In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, SWEPCo has agreed under certain conditions, to
assume the capital lease obligations and term loan payments of the mining
contractor, Sabine Mining Company (Sabine). In the event Sabine defaults under
any of these agreements,

SWEPCo's total future maximum payment exposure is approximately $58 million with
maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since SWEPCo uses
self-bonding, the guarantee provides for SWEPCo to commit to use its resources
to complete the reclamation in the event the work is not completed by a third
party miner. At December 31, 2003, the cost to reclaim the mine in 2035 is
estimated to be approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46
(see Note 2). Upon consolidation, SWEPCo recorded the assets and liabilities of
Sabine ($78 million). Also, after consolidation, SWEPCo currently records all
expenses (depreciation, interest and other operation expense) of Sabine and
eliminates Sabine's revenues against SWEPCo's fuel expenses. There is no
cumulative effect of an accounting change recorded as a result of the
requirement to consolidate, and there is no change in net income due to the
consolidation of Sabine.

INDEMNIFICATIONS AND OTHER GUARANTEES
-------------------------------------

We entered into several types of contracts, which would require
indemnifications. Typically these contracts include, but are not limited to,
sale agreements, lease agreements, purchase agreements and financing agreements.
Generally these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect to sale
agreements, our exposure generally does not exceed the sale price. We cannot
estimate the maximum potential exposure for any of these indemnifications
entered into prior to December 31, 2002 due to the uncertainty of future events.
In 2003 we entered into several sale agreements discussed in Note 10. These sale
agreements include indemnifications with a maximum exposure of approximately $57
million. There are no material liabilities recorded for any indemnifications
entered into during 2003. There are no liabilities recorded for any
indemnifications entered prior to December 31, 2002.

We lease certain equipment under a master operating lease. Under the lease
agreement, the lessor is guaranteed to receive up to 87% of the unamortized
balance of the equipment at the end of the lease term. If the fair market value
of the leased equipment is below the unamortized balance at the end of the lease
term, we have committed to pay the difference between the fair market value and
the unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At December 31, 2003, the maximum potential loss for these
lease agreements was approximately $28 million assuming the fair market value of
the equipment is zero at the end of the lease term.

See Note 16 "Leases" for disclosure of lease residual value guarantees.


9.  SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
-----------------------------------------------


In response to difficult conditions in our business, a Sustained Earnings
Improvement (SEI) initiative was undertaken company-wide in the fourth quarter
of 2002, as a cost-saving and revenue-building effort to build long-term
earnings growth.

Termination benefits expense relating to 1,120 terminated employees totaling
$75.4 million pre-tax was recorded in the fourth quarter of 2002. Of this
amount, we paid $9.5 million to these terminated employees in the fourth
quarter of 2002. No additional termination benefits expense related to the SEI
initiative was recorded in 2003, and the remaining SEI related payments were
made in 2003. The termination benefits expense is classified as Maintenance
and Other Operation expense on our Consolidated Statements of Operations. We
determined that the termination of the employees under our SEI initiative did
not constitute a plan curtailment of any of our retirement benefit plans.


10.  ACQUISITIONS, DISPOSITIONS, DISCONTINUED OPERATIONS, IMPAIRMENTS, ASSETS
     HELD FOR SALE AND ASSETS HELD AND USED
-----------------------------------------------------------------------------


ACQUISITIONS
------------

2002
----

Acquisition of Nordic Trading (Investments - UK Operations segment)
-------------------------------------------------------------------

In January 2002 we acquired the trading operations, including key staff, of
Enron's Norway and Sweden-based energy trading businesses (Nordic Trading).
Results of operations are included in our Consolidated Statements of Operations
from the date of acquisition. Subsequently in the fourth quarter of 2002, a
decision was made to exit this non-core European trading business. The sale of
Nordic Trading in the second quarter of 2003 is discussed in the "Dispositions"
section of this note.

Acquisition of USTI (Investments - Other segment)
-------------------------------------------------

In January 2002, we acquired 100% of the stock of United Sciences Testing, Inc.
(USTI) for $12.5 million. USTI provides equipment and services related to
automated emission monitoring of combustion gases to both our affiliates and
external customers. Results of operations are included in our Consolidated
Statements of Operations from the date of acquisition.

2001
----

Houston Pipe Line Company (Investments - Gas Operations segment)
----------------------------------------------------------------

On June 1, 2001, through a wholly-owned subsidiary, we purchased Houston Pipe
Line Company and Lodisco LLC for $727 million from Enron. The acquired assets
include 4,200 miles of gas pipeline, a 30-year prepaid lease of a gas storage
facility and certain gas marketing contracts. The purchase method of accounting
was used to record the acquisition. During 2003 we recorded impairment and other
losses for HPL and related gas operations of $315 million ($228 million net of
tax).

U.K. Generation Plants (Investments - UK  Operations segment)
-------------------------------------------------------------

In December 2001, we acquired 4,000 megawatts of coal-fired generation from
Fiddler's Ferry, a four-unit, 2,000 MW station on the River Mersey in northwest
England, and Ferrybridge, a four-unit, 2,000 MW station on the River Aire in
northeast England and related coal stocks. These assets were acquired for a cash
payment of $942.3 million and the assumption of certain liabilities. During 2003
these assets became held-for-sale and we reported the operations as
discontinued. See U.K. Generation Plants in the "Discontinued Operations"
section of this note for further information.

Other Acquisitions (Various segments)
-------------------------------------

We also purchased the following assets or acquired the following businesses from
July 2001 through December 2001:

  o     Dolet Hills mining operations were purchased by SWEPCo, an AEP
        subsidiary, and SWEPCo also assumed the existing mine reclamation
        liabilities at its jointly owned lignite reserves in Louisiana.
  o     Quaker Coal Company as part of a bankruptcy proceeding settlement was
        acquired, including certain liabilities. The acquisition includes
        property, coal reserves, mining operations and royalty interests in
        Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. We continue to
        operate the mines and facilities. See AEP Coal in the "Assets Held for
        Sale" section of this note for further information on our decision to
        dispose of this investment.
  o     MEMCO Barge Line was acquired adding 1,200 hopper barges and 30 towboats
        to AEP's existing barging fleet. MEMCO added major barging operations on
        the Mississippi and Ohio rivers to AEP's barging operations on the Ohio
        and Kanawha rivers.
  o     A 20% equity interest in Caiua, a Brazilian electric operating company
        which is a subsidiary of Vale was acquired by converting a total of $66
        million on an existing loan and accrued interest on that loan into Caiua
        equity. See Grupo Rede Investment in the "Dispositions" section of this
        note for further information.
  o     Indian Mesa Wind Project (referred to as "Desert Sky") consisting of 160
        MW of wind generation located near Fort Stockton,  Texasm was purchased.
  o     Enron's London-based international coal trading group was acquired by
        purchasing existing contracts and hiring key staff.

Management recorded the assets acquired and liabilities assumed at their
estimated fair values based on currently available information and on current
assumptions as to future operations.

DISPOSITIONS
------------

2003
----

C3 Communications (Investments - Other segment)
-----------------------------------------------

In February 2003, C3 Communications sold the majority of its assets for a sales
price of $7.25 million. We provided for an $82 million pre-tax ($53 million
after-tax) asset impairment in December 2002 and the effect of the sale on 2003
results of operations was not significant. The impairment is classified in Asset
Impairments and Other Related Changes in our Consolidated Statements of
Operations. See "Assets Held for Sale" section of this note for information on
assets and liabilities held for sale at December 31, 2002 related to our
"telecommunications" businesses.

Mutual Energy Companies (Utility Operations segment)
----------------------------------------------------

On December 23, 2002 we sold the general partner interests and the limited
partner interests in Mutual Energy CPL L.P. and Mutual Energy WTU L.P. for a
base purchase price paid in cash at closing and certain additional payments,
including a net working capital payment. The buyer paid a base purchase price of
$145.5 million which was based on a fair market value per customer established
by an independent appraiser and an agreed customer count. We recorded a net gain
totaling $83.7 million after-tax ($129 million pre-tax) in Other Income during
2002. We provided the buyer with a power supply contract for the two REPs and
back-office services related to these customers for a two-year period. In
addition, we retained the right to share in earnings from the two REPs above a
threshold amount through 2006 in the event the Texas retail market develops
increased earnings opportunities. No revenue was recorded in 2003 related to
these sharing agreements. Under the Texas Legislation, REPs are subject to a
clawback liability if customer change does not attain thresholds required by the
legislation. We are responsible for a portion of such liability, if any, for the
period we operated the REPs in the Texas competitive retail market (January 1,
2002 through December 23, 2002). In addition, we retained responsibility for
regulatory obligations arising out of operations before closing. Our
wholly-owned subsidiary Mutual Energy Service Company LLC (MESC) received an
up-front payment of approximately $30 million from the buyer associated with the
back-office service agreement, and MESC deferred its right to receive payment of
an additional amount of approximately $9 million to secure certain contingent
obligations. These prepaid service revenues were deferred on the books of MESC
as of December 31, 2002 and are being amortized over the two-year term of the
back office service agreement.

In February 2003, we completed the sale of MESC for $30.4 million dollars and
realized a pre-tax gain of approximately $39 million, which included the
recognition of the remaining balance of the original $30 million prepayment ($27
million), as no further service obligations existed for MESC.

Water Heater Assets (Utility Operations segment)
------------------------------------------------

We sold our water heater rental program for $38 million and recorded a pre-tax
loss of $3.9 million in the first quarter of 2003 based upon final terms of the
sale agreement. We had provided for a $7.1 million pre-tax charge in the fourth
quarter 2002 based on an estimated sales price ($3.2 million asset impairment
charge and $3.9 million lease prepayment penalty). The impairment loss is
included in Investment Value Losses in our Consolidated Statements of
Operations. We operated a program to lease electric water heaters to residential
and commercial customers until a decision was reached in the fourth quarter of
2002 to discontinue the program and offer the assets for sale. See the "Assets
Held for Sale" section of this Note for assets and liabilities held for sale as
of December 31, 2002.

AEP Gas Power Systems (Investments - Other segment)
---------------------------------------------------

In 2001, we acquired a 75% interest in a startup company, seeking to develop
low-cost peaking generator sets powered by surplus jet turbine engines. In
January 2003, AEP Gas Power Systems, LLC sold its assets. We recognized a
goodwill impairment loss of $12.3 million pre-tax in the first quarter of 2002
due to technological and operational problems (also see Note 3). The impairment
loss was recorded in Investment Value Losses on our Consolidated Statements of
Operations. The fair values of the remaining assets and liabilities as of
December 31, 2002 were excluded from held for sale on our Consolidated Balance
Sheets as the impact was not significant. The effect of the asset sale on the
first quarter 2003 results of operations was not significant.

Newgulf Facility (Investments - Other segment)
----------------------------------------------

In 1995, we purchased an 85 MW gas-fired peaking electrical generation facility
located near Newgulf, Texas (Newgulf). In October 2002, we began negotiations
with a likely buyer of the facility. We estimated a pre-tax loss on sale of
$11.8 million based on the indicative bid. This loss was recorded as Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations during the fourth quarter 2002. Newgulf's Property, Plant and
Equipment, net of accumulated depreciation, was classified on our Consolidated
Balance Sheets as held for sale at December 31, 2002. During the second quarter
of 2003 we completed the sale of Newgulf and the impact on earnings in 2003 was
not significant.

Nordic Trading (Investments - UK Operations segment)
----------------------------------------------------

In October 2002 we announced that our ongoing energy trading operations would be
centered around our generation assets. As a result, we took steps to exit our
coal, gas and electricity trading activities in Europe, except for those
activities predominantly related to our U.K. generation operations. The Nordic
Trading business acquired earlier in 2002 was made available for sale to
potential buyers later in 2002. The estimated pre-tax loss on disposal recorded
in 2002 of $5.3 million, consisted of impairment of goodwill of $4.0 million and
impairment of assets of $1.3 million. The estimated loss of $5.3 million is
included in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations. Management's determination of a zero fair value was
based on discussions with a potential buyer. The assets and liabilities of
Nordic Trading have been classified on our Consolidated Balance Sheets as held
for sale at December 31, 2002. The transfer of the Nordic Trading business,
including the trading portfolio, to new owners was completed during the second
quarter of 2003 and the impact on earnings during the second quarter of 2003 was
not significant.

Eastex (Investments - Other segment)
------------------------------------

In 1998, we began construction of a natural gas-fired cogeneration facility
(Eastex) located near Longview, Texas and commercial operations commenced in
December 2001. In June 2002, we requested that the FERC allow us to modify the
FERC Merger Order and substitute Eastex as a required divestiture under the
order, due to the fact that the agreed upon market-power related divestiture of
a plant in Oklahoma was no longer feasible. The FERC approved the request at the
end of September 2002. Subsequently, in the fourth quarter of 2002, we solicited
bids for the sale of Eastex and several interested buyers were identified by
December 2002. The estimated pre-tax loss on sale of $218.7 million pre-tax
($142 million after-tax), which was based on the estimated fair value of the
facility and indicative bids by interested buyers, was recorded in Discontinued
Operations in our Consolidated Statements of Operations during the fourth
quarter 2002.

We completed the sale of Eastex during the third quarter of 2003 and the effect
of the sale on third quarter 2003 results of operations was not significant. The
results of operations of Eastex have been reclassified as Discontinued
Operations in accordance with SFAS 144 for all years presented. The assets and
liabilities of Eastex were reclassified on the Consolidated Balance Sheets from
Assets Held for Sale and Liabilities Held for Sale to Discontinued Operations at
December 31, 2002. See "Discontinued Operations" section of this note for
additional information.

Grupo Rede Investment (Investments - Other segment)
---------------------------------------------------

In December 2002, we recorded an other than temporary impairment totaling $141.0
million ($217.0 million net of federal income tax benefit of $76.0 million) of
our 44% equity investment in Vale and our 20% equity interest in Caiua, both
Brazilian electric operating companies (referred to as Grupo Rede). This amount
is included in Investment Value Losses on our Consolidated Statements of
Operations.

In December 2003 we transferred our share and investment in Vale to Grupo Rede
for $1 million. The effect of the transfer on fourth quarter results of
operations was not significant.

Excess Equipment (Investments - Other segment)
----------------------------------------------

In November 2002, as a result of a cancelled development project, we obtained
title to a surplus gas turbine generator. We had been unsuccessful in finding
potential buyers of the unit due to an over-supply of generation equipment
available for sale during 2002. An estimated pre-tax loss on disposal of $23.9
million was recorded in December 2002, based on market prices of similar
equipment. The loss is included in Asset Impairments and Other Related Charges
on our Consolidated Statements of Operations. The Other asset of $12 million in
2002 was classified on our Consolidated Balance Sheets as held for sale at
December 31, 2002.

We completed the sale of the surplus gas turbine generator in November 2003. The
proceeds from the sale were $8.7 million. A pre-tax loss of $1.8 million was
recorded in the fourth quarter of 2003.

Ft. Davis Wind Farm (Investments - Other segment)
-------------------------------------------------

In the 1990's, we developed a 6 MW facility wind energy project located on a
lease site near Ft. Davis, Texas. In the fourth quarter of 2002 our engineering
staff determined that operation of the facility was no longer technically
feasible and the lease of the underlying site should not be renewed. Dismantling
of the facility is expected to be completed during 2004. An estimated pre-tax
loss on abandonment of $4.7 million was recorded in December 2002. The loss was
recorded in Asset Impairments and Other Related Charges on our Consolidated
Statements of Operations.

2002
----

SEEBOARD (Investments - Other segment)
--------------------------------------

On June 18, 2002, through a wholly-owned subsidiary, we entered into an
agreement, subject to European Union (EU) approval, to sell our consolidated
subsidiary SEEBOARD, a U.K. electricity supply and distribution company. EU
approval was received July 25, 2002 and the sale was completed on July 29, 2002.
We received approximately $941 million in net cash from the sale, subject to a
working capital true up, and the buyer assumed SEEBOARD debt of approximately
$1.12 billion, resulting in a net loss of $345 million at June 30, 2002. The
results of operations of SEEBOARD have been classified as Discontinued
Operations for all years presented. A net loss of $22 million pre-tax ($14
million after-tax) was classified as Discontinued Operations in the second
quarter of 2002. The remaining $323 million of the net loss has been classified
as a transitional goodwill impairment loss from the adoption of SFAS 142 (see
Notes 2 and 3) and has been reported as a Cumulative Effect of Accounting Change
retroactive to January 1, 2002. A $59 million pre-tax ($38 million after-tax)
reduction of the net loss was recognized in the second half of 2002 to reflect
changes in exchange rates to closing, settlement of working capital true-up and
selling expenses. The net total loss recognized on the disposal of SEEBOARD was
$286 million. Proceeds from the sale of SEEBOARD were used to pay down bank
facilities and short-term debt. See "Discontinued Operations" section for the
total revenues and pretax profit (loss) of the discontinued operations of
SEEBOARD.

CitiPower (Investments - Other segment)
---------------------------------------

On July 19, 2002, through a wholly owned subsidiary, we entered into an
agreement to sell CitiPower, a retail electricity and gas supply and
distribution subsidiary in Australia. We completed the sale on August 30, 2002
and received net cash of approximately $175 million and the buyer assumed
CitiPower debt of approximately $674 million. We recorded a pre-tax charge
totaling $192 million ($125 million after-tax) as of June 30, 2002. The charge
included a pre-tax impairment loss of $151 million ($98 million after-tax) on
the remaining carrying value of an intangible asset related to a distribution
license for CitiPower. The remaining $41 million pre-tax ($27 million after-tax)
of net loss was classified as a transitional goodwill impairment loss from the
adoption of SFAS 142 (see Notes 2 and 3) and was recorded as a Cumulative Effect
of Accounting Change retroactive to January 1, 2002.

The loss on the sale of CitiPower increased $37 million pre-tax ($24 million
after-tax) to $229 million pre-tax ($149 million after-tax; $122 million plus
$27 million of cumulative effect) in the second half of 2002 based on actual
closing amounts and exchange rates. See the "Discontinued Operations" section of
this note for the total revenues and pretax profit (loss) of the discontinued
operations of CitiPower.

2001
----

In March 2001, CSWE, a subsidiary company, completed the sale of Frontera, a
generating plant that the FERC required to be divested in connection with the
merger of AEP and CSW. The sale proceeds were $265 million and resulted in an
after-tax gain of $46 million ($73 million pre-tax).

In July 2001, through a wholly-owned subsidiary, we sold our 50% interest in a
120-megawatt generating plant located in Mexico. The sale resulted in an after
tax gain of approximately $11 million.

In July 2001, we sold coal mines in Ohio and West Virginia and agreed to
purchase approximately 34 million tons of coal from the purchaser of the mines
through 2008. The sale had a nominal impact on our results of operations and
cash flows.

In December 2001, we completed the sale of our ownership interests in the
Virginia and West Virginia PCS (Personal Communications Services) Alliances for
stock, resulting in an after tax gain of approximately $7 million. Subsequently
during 2002, due to decreasing market value of the shares received from the
sale, we reduced the value of them to zero.

DISCONTINUED OPERATIONS
-----------------------

Management periodically assesses the overall AEP business model and makes
decisions regarding our continued support and funding of our various businesses
and operations. When it is determined that we will seek to exit a particular
business or activity and we have met the accounting requirements for
reclassification, we will reclassify the operations of those businesses or
operations as discontinued operations. The assets and liabilities of these
discontinued operations are classified as Assets and Liabilities Held for Sale
until the time that they are sold. At the time they are sold they are
reclassified to Assets and Liabilities of Discontinued Operations on the
Consolidated Balance Sheets for all periods presented. Assets and liabilities
that are held for sale, but do not qualify as a discontinued operations are
reflected as Assets and Liabilities Held for Sale both while they are held for
sale and after they have been sold, for all periods presented.

Certain of our operations were determined to be discontinued operations and have
been classified as such in 2003, 2002 and 2001.  Results of operations of these
businesses have been reclassified as shown in the following table:
<TABLE>
<CAPTION>


                                                                              Pushan                      U.K.
                                           SEE-                                Power                   Generation
                                          BOARD    CitiPower      Eastex       Plant        LIG           Plants        Total
                                          -----    ---------      ------     ---------      ---      ---------------    -----

     <C>                                  <C>           <C>       <C>           <C>         <C>             <C>         <C>
     2003 Revenue                            $-           $-       $58          $60         $653            $125         $896
     2003 Pretax Profit (Loss)                -          (20)      (23)           4         (122)           (713)        (874)
     2003 Earnings(Loss) After Tax           16          (13)      (14)           4          (91)           (507)        (605)


     2002 Revenue                           694          204        73           57          507             251        1,786
     2002 Pretax Profit (Loss)              180         (190)     (239)         (13)          14            (579)        (827)
     2002 Earnings (Loss) After Tax          96         (123)     (156)          (7)           8            (472)        (654)

     2001 Revenue                         1,451          350         -           57          525              26        2,409
     2001 Pretax Profit (Loss)              104           (4)        1            8           (6)            (48)          55
     2001 Earnings (Loss) After Tax          88           (6)        -            4           (4)            (41)          41
</TABLE>

Assets and liabilities of discontinued operations have been reclassified
as follows:

                                                                      Eastex
                                                                      ------
                                                                   (in millions)
           As of December 31, 2002
           Current Assets                                                $15
                                                                         ----
           Total Assets of Discontinued Operations                       $15
                                                                         ====

           Current Liabilities                                            $8
           Deferred Credits and Other                                      4
                                                                         ----
           Total Liabilities of Discontinued Operations                  $12
                                                                         ====

Pushan Power Plant (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began active negotiations to sell our interest
in the Pushan Power Plant (Pushan) in Nanyang, China to our minority interest
partner and a purchase and sale agreement was signed in the fourth quarter of
2003. We expect to close on this transaction by mid 2004. An estimated pre-tax
loss on disposal of $20 million pre-tax ($13 million after-tax) was recorded in
December 2002, based on an indicative price expression. The estimated pre-tax
loss on disposal is classified in Discontinued Operations in our Consolidated
Statements of Operations.

Results of operations of Pushan have been reclassified as Discontinued
Operations. The assets and liabilities of Pushan have been classified on our
Consolidated Balance Sheets as held for sale. We have classified the assets and
liabilities as held for sale for longer than 12 months, which is longer than
originally expected, due to several unusual circumstances including the SARS
outbreak and governmental delays.

Louisiana Intrastate Gas (LIG ) (Investments - Gas Operations segment)
----------------------------------------------------------------------

After announcing during 2003 that we would be divesting our non-core assets we
began actively marketing LIG with the help of an investment advisor. After
receiving and analyzing initial bids during the fourth quarter 2003 we recorded
a $133.9 million pre-tax ($99 million after-tax) impairment loss; of this loss,
$128.9 million pre-tax relates to the impairment of goodwill and $5 million
pre-tax relates to other charges. In February 2004, we signed a definitive
agreement to sell the pipeline portion of LIG. We anticipate the sale will be
completed during the second quarter of 2004 and that the impact on results of
operations in 2004 will not be significant. The assets and liabilities of LIG
are classified as held for sale on our Consolidated Balance Sheets and the
results of operations (including the above-mentioned impairments and other
related charges) are classified in Discontinued Operations in our Consolidated
Statements of Operations.

U.K. Generation Plants (Investments - UK Operations segment)
------------------------------------------------------------

In December 2001, we acquired two coal-fired generation plants (U.K. Generation)
in the U.K. for a cash payment of $942.3 million and assumption of certain
liabilities. Subsequently and continuing through 2002, wholesale U.K. electric
power prices declined sharply as a result of domestic over-capacity and static
demand. External industry forecasts and our own projections made during the
fourth quarter of 2002 indicated that this situation may extend many years into
the future. As a result, the U.K. Generation fixed asset carrying value at
year-end 2002 was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our U.K. Generation indicated
a 2002 pre-tax impairment loss of $548.7 million ($414 million after-tax). This
impairment loss is included in 2002 Discontinued Operations on our Consolidated
Statements of Operations.

Management has retained an investment advisor to assist in determining the best
methodology to exit the U.K. business. An information memorandum was distributed
for the sale of our U.K. Generation and based on current information we recorded
a $577 million pre-tax charge ($375 after-tax), including asset impairments of
$420.7 million during the fourth quarter of 2003 to write down the value of the
assets to their estimated realizable value. Additional charges of $156.7 million
pre-tax were also recorded in December 2003 including $122.2 million related to
the net loss on certain cash flow hedges previously recorded in Accumulated
Other Comprehensive Income that has been reclassified into earnings as a result
of management's determination that the hedged event is no longer probable of
occurring and $34.5 million related to a first quarter 2004 sale of certain
power contracts. The assets and liabilities of U.K. Generation have been
classified as held for sale on our Consolidated Balance Sheets and the results
of operations are included in Discontinued Operations on our Consolidated
Statements of Operations. We anticipate the sale of the U.K. Generation plants
during 2004.

ASSET IMPAIRMENTS, INVESTMENT VALUE LOSSES AND OTHER RELATED CHARGES
--------------------------------------------------------------------

In 2003, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.4 billion [consisting of approximately $650 million
related to Asset Impairments ($610 million) and Other Related Charges ($40
million), $70 million related to Investment Value Losses, $711 million related
to Discontinued Operations ($550 million of impairments and $161 million of
other charges) and $6 million related to charges recorded for Excess Real Estate
in Maintenance and Other Operation in the Consolidated Statements of Operations]
that reflected downturns in energy trading markets, projected long-term
decreases in electricity prices, our decision to exit non-core businesses and
other factors.

In 2002, AEP recorded pre-tax impairments of assets (including goodwill) and
investments totaling $1.7 billion (consisting of approximately $318 million
related to Asset Impairments, $321 million related to Investment Value Losses,
$938 million related to Discontinued Operations and $88 million related to
charges recorded in other lines within the Consolidated Statements of
Operations) that reflected downturns in energy trading markets, projected
long-term decreases in electricity prices, and other factors. These impairments
exclude the transitional goodwill impairment loss from adoption of SFAS 142 (see
Notes 2 and 3).

The categories of impairments include:
<TABLE>
<CAPTION>
                                                              2003                    2002                          2001
                                                              ----                    ----                          ----
                                                                                  (in millions)
Asset Impairments and Other Related Charges (Pre-tax)
-----------------------------------------------------

<C>                                                            <C>                     <C>                           <C>
AEP Coal                                                        $67                     $60                          $-
HPL and Other                                                   315                       -                           -
Power Generation Facility                                       258                       -                           -
Blackhawk Coal Company                                           10                       -                           -
Ft. Davis Wind Farm                                               -                       5                           -
Texas Plants                                                      -                      38                           -
Newgulf Facility                                                  -                      12                           -
Excess Equipment                                                  -                      24                           -
Nordic Trading                                                    -                       5                           -
Excess Real Estate                                                -                      16                           -
Telecommunications - AEPC/C3                                      -                     158                           -
                                                               -----                   -----                         ---
Total                                                          $650                    $318                          $-
                                                               =====                   =====                         ===


Investment Value Losses (Pre-tax)
---------------------------------
Independent Power Producers                                     $70                      $-                          $-
Water Heater Assets                                               -                       3                           -
South Coast Power Investment                                      -                      63                           -
Telecommunications - AFN                                          -                      14                           -
AEP Gas Power Systems                                             -                      12                           -
Grupo Rede Investment - Vale                                      -                     217                           -
Technology Investments                                            -                      12                           -
                                                               -----                   -----                         ---
Total                                                           $70                    $321                          $-
                                                               =====                   =====                         ===
</TABLE>

<TABLE>
<CAPTION>


"Impairments and Other Related Charges" and
"Operations" Included in Discontinued Operations (After-tax)
------------------------------------------------------------

Impairments and Other Related Charges:

  <C>                                                         <C>                     <C>                            <C>
  U.K. Generation Plants                                      $(375)                  $(414)                         $-
  Louisiana Intrastate Gas                                      (99)                     -                            -
  CitiPower                                                       -                    (122)                          -
  Eastex                                                          -                    (142)                          -
  SEEBOARD                                                        -                      24                           -
  Pushan                                                          -                     (13)                          -
                                                              ------                  ------                         ---
Total*                                                         (474)                   (667)                          -
                                                              ------                  ------                         ---

Operations:

  U.K. Generation Plants                                       (132)                    (58)                        (41)
  Louisiana Intrastate Gas                                        8                       8                          (4)
  CitiPower                                                     (13)                     (1)                         (6)
  Eastex                                                        (14)                    (14)                          -
  SEEBOARD                                                       16                      72                          88
  Pushan                                                          4                       6                           4
                                                              ------                  ------                        ----
Total                                                          (131)                     13                          41
                                                              ------                  ------                        ----

Total Discontinued Operations                                 $(605)                  $(654)                        $41
                                                              ======                  ======                        ====
</TABLE>


* See the "Dispositions" and "Discontinued Operations" sections of this note for
  the pre-tax impairment figures.


ASSETS HELD FOR SALE
--------------------

Telecommunications (Investments - Other segment)
------------------------------------------------

We developed businesses to provide telecommunication services to businesses and
other telecommunication companies through broadband fiber optic networks. The
businesses included AEP Communications, LLC (AEPC), C3 Communications, Inc.
(C3), and a 50% share of AFN, LLC (AFN), a joint venture. Due to the difficult
economic conditions in these businesses and the overall telecommunications
industry, the AEP Board approved in December 2002 a plan to cease operations of
these businesses. We took steps to market the assets of the businesses to
potential interested buyers in the fourth quarter of 2002.

We completed the sale of substantially all the assets of C3 in the first quarter
of 2003 as discussed in the "Dispositions" section of this note. AFN closed on
the sale of substantially all of its assets in January 2004 with no significant
additional effect on results of operations in 2004. The sale of remaining
telecommunication assets is proceeding.

An estimated pre-tax impairment loss of $158.5 million ($76.3 million related to
AEPC and $82.2 million related to C3) was recorded in December 2002 and is
classified in Asset Impairments and Other Related Charges in our Consolidated
Statements of Operations. An estimated pre-tax loss in value of the investment
in AFN of $13.8 million was recorded in December 2002 and is classified in
Investment Value Losses in our Consolidated Statements of Operations. The
estimated losses were based on indicative bids by potential buyers. Property,
Plant and Equipment, net of accumulated depreciation, of the telecommunication
businesses have been classified on our Consolidated Balance Sheets as held for
sale in 2002.

AEP Coal (Investments - Other segment)
--------------------------------------

In October 2001, we acquired out of bankruptcy certain assets and assumed
certain liabilities of nineteen coal mine companies formerly known as "Quaker
Coal" and renamed "AEP Coal." During 2002 the coal operations suffered from a
decline in prices and adverse mining factors resulting in significantly reduced
mine productivity and revenue. Based on an extensive review of economically
accessible reserves and other factors, future mine productivity and production
is expected to continue below historical levels. In December 2002, a
probability-weighted discounted cash flow analysis of fair value of the mines
was performed which indicated a 2002 pre-tax impairment loss of $59.9 million
including a goodwill impairment of $3.6 million as discussed in Note 3. This
impairment loss is included in Asset Impairments and Other Related Charges on
our Consolidated Statements of Operations.

In 2003, as a result of management's decision to exit our non-core businesses,
we retained an advisor to facilitate the sale of AEP Coal. In the fourth quarter
of 2003, after considering the current bids and all other options, we recorded a
$66.6 million pre-tax ($43.6 million after-tax) charge comprised of a $29.4
million asset impairment, a $25.2 million charge related to accelerated
remediation cost accruals and $12 million charge (accrued at December 31, 2003)
related to a royalty agreement. These impairment losses were included in Asset
Impairments and Other Related Charges on our Consolidated Statements of
Operations. The assets and liabilities of AEP Coal that are held for sale have
been included in Assets and Liabilities Held for Sale in our Consolidated
Balance Sheets at December 31, 2003 and 2002.

Texas Plants (Utility Operations segment)
-----------------------------------------

In September 2002, AEP indicated to ERCOT its intent to deactivate 16 gas-fired
power plants (8 TCC plants and 8 TNC plants). ERCOT subsequently conducted
reliability studies, which determined that seven plants (4 TCC plants and 3 TNC
plants) would be required to ensure reliability of the electricity grid. As a
result of those studies, ERCOT and AEP mutually agreed to enter into reliability
must run (RMR) agreements, which expired in December 2002, and were subsequently
renewed through December 2003. However, certain contractual provisions provided
ERCOT with a 90-day termination clause, if the contracted facility was no longer
needed to ensure reliability of the electricity grid. With ERCOT's approval, AEP
proceeded with its planned deactivation of the remaining nine plants. In August
2003, pursuant to contractual terms, ERCOT provided notification to AEP of its
intent to cancel a RMR agreement at one of the TNC plants. Upon termination of
the agreement, AEP proceeded with its planned deactivation of the plant. In
December 2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants
(4 TCC plants and 2 TNC plants) through December 2004, subject to ERCOT's 90 day
termination clause and the divestiture of the TCC facilities.

As a result of the decision to deactivate TNC plants, a write-down of utility
assets of approximately $34.2 million (pre-tax) was recorded in Asset
Impairments and Other Related Charges expense during the third quarter 2002 on
our Consolidated Statements of Operations. The decision to deactivate the TCC
plants resulted in a write-down of utility assets of approximately $95.6 million
(pre-tax), which was deferred and recorded in Regulatory Assets during the third
quarter 2002 in our Consolidated Balance Sheets.

During the fourth quarter of 2002, evaluations continued as to whether assets
remaining at the deactivated plants, including materials, supplies and fuel oil
inventories, could be utilized elsewhere within the AEP System. As a result of
such evaluations, TNC recorded an additional asset impairment charge to Asset
Impairments and Other Related Charges expense of $3.9 million (pre-tax) in the
fourth quarter of 2002. In addition, TNC recorded related fuel inventory and
materials and supplies write-downs of $2.6 million ($1.2 million in Fuel for
Electric Generation and $1.4 million in Maintenance and Other Operation).
Similarly, TCC recorded an additional asset impairment write-down of $6.7
million (pre-tax), which was deferred and recorded in Regulatory Assets in the
fourth quarter of 2002. TCC also recorded related inventory write-downs of $14.9
million which was deferred and recorded in Regulatory Assets in the fourth
quarter 2002.

The total Texas plant asset impairment of $38.1 million pre-tax in 2002 (all
related to TNC) is included in Asset Impairments and Other Related Charges in
our Consolidated Statements of Operations.

In December 2002, TCC filed a plan of divestiture with the PUCT proposing to
sell all of its power generation assets, including the eight gas-fired
generating plants that were either deactivated or designated as RMR status.
During the fourth quarter of 2003, after receiving bids from interested buyers,
we recorded a $938 million impairment loss and changed the classification of the
plant assets from plant in service to Assets Held for Sale. In accordance with
Texas legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires charge,
subject to the final outcome of the 2004 Texas true-up proceeding. See Texas
Restructuring section of Note 6, "Customer Choice and Industry Restructuring,"
for further discussion of the divestiture plan, anticipated timeline and true-up
proceeding.

The assets and liabilities of the entities held for sale at December 31, 2003
and 2002 are as follows:
<TABLE>
<CAPTION>

                                            Pushan          U.K.
                                             Power       Generation        AEP            Texas
                                             Plant         Plants          Coal           Plants           LIG           Total
                                           -------       ----------        ----           ------           ----          -----
December 31, 2003
------------------                                                       (in millions)
Assets:
<C>                                           <C>        <C>               <C>          <C>              <C>              <C>
 Current Assets                                $24       $1,245             $6             $57            $50             $1,382
 Property, Plant and Equipment, Net            142           99             13             797            171              1,222
 Regulatory Assets                               -            -              -              49              -                 49
 Spent Nuclear Fuel and
  Decommissioning Trusts                         -            -              -             125              -                125
 Goodwill                                        -            -              -               -             15                 15
 Long-term Risk Management Assets                -          274              -               -              -                274
 Other                                           -            6              -               -              9                 15
                                              -----      -------           ----         -------          -----            -------
 Total Assets  Held for Sale                  $166       $1,624            $19          $1,028           $245             $3,082
                                              =====      =======           ====         =======          =====            =======

Liabilities:
 Current Liabilities                           $26         $988             $-              $-            $61             $1,075
 Long-term Debt                                 20            -              -               -              -                 20
 Long-term Risk Management
  Liabilities                                    -          435              -               -              -                435
 Regulatory Liabilities and Deferred
  Investment Tax Credits                        -            -              -               9              -                  9
 Asset Retirement Obligations and
  Nuclear Decommissioning Trusts                 -           29              -             219              -                248
 Employee Benefits and Pension
  Obligations                                    -           12              -               -              -                 12
 Deferred Credits and Other                     57            -             14               -              6                 77
                                              -----      -------           ----         -------          -----            -------
 Total Liabilities Held for Sale              $103       $1,464            $14            $228            $67             $1,876
                                              =====      =======           ====         =======          =====            =======
</TABLE>

<TABLE>
<CAPTION>


                         Pushan       U.K.                                Tele-                                  Water
                         Power    Generation     AEP      Texas           Commun-   Nordic   Newgulf      Excess   Heater
                         Plant       Plants     Coal     Plants    LIG    ications  Trading  Facility  Equipment   Program   Total
                         -----    ----------    ----     ------    ---    --------  -------  --------  ---------   -------   -----
December 31,  2002                                                (in millions)
------------------
Assets:

<C>                       <C>       <C>         <C>     <C>        <C>        <C>     <C>       <C>        <C>      <C>   <C>
Current Assets             $19        $571        4       $ 70      $62       $-      $35       $-          $-       $1     $762
Property, Plant and
 Equipment, Net            132         445       38      1,647      169        6        -        6           -       38    2,481
Spent Nuclear Fuel
 and Decommissioning
 Trusts                      -           -        -         98        -        -        -        -           -        -       98
Goodwill                     -          11        -          -      144        -        -        -           -        -      155
Long-term Risk
  Management Assets          -          61        -          -        -        -        5        -           -        -       66
Other                        -          22        -          -        -        -        5        -          12        -       39
                          -----     -------     ----    -------    -----      ---     ----      ---        ----     ----  -------
Total Assets
  Held for Sale           $151      $1,110      $42     $1,815     $375       $6      $45       $6         $12      $39   $3,601
                          =====     =======     ====    =======    =====      ===     ====      ===        ====     ====  =======

Liabilities:
Current Liabilities        $28        $992       $-         $-      $53       $-      $48       $-         $ -      $ -   $1,121
Long-term Debt              25           -        -          -        -        -        -        -           -        -       25
Deferred Income Taxes        -           -        -          -        -        -        -        -           -        -        -
Long-term Risk
  Management
  Liabilities                -          39        -          -        7        -        3        -           -        -       49
Deferred Credits and
  Other                     26          24       15          9       10        -        -        -           -        -       84
                          -----     -------     ----    -------    -----      ---     ----      ---        ----     ----  -------
Total Liabilities
   Held for Sale           $79      $1,055      $15         $9      $70       $-      $51       $-          $-      $ -   $1,279
                          =====     =======     ====    =======    =====      ===     ====      ===        ====     ====  =======
</TABLE>


ASSETS HELD AND USED
--------------------

In 2003 and 2002, we recorded the following impairments related to assets
(including Goodwill) held and used to Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations as discussed below:

Excess Real Estate (Investments - Other segment)
------------------------------------------------

In the fourth quarter of 2002, we began to market an under-utilized office
building in Dallas, TX obtained through our merger with CSW. Sale of the
facility was projected by the second quarter 2003 and an estimated pre-tax loss
on disposal of $15.7 million was recorded in 2002, based on the option sale
price. The estimated loss is included in Asset Impairments and Other Related
Charges on our Consolidated Statements of Operations. The Property asset of $18
million in 2002 and $36 million in 2001 was previously classified on our
Consolidated Balance Sheets as held for sale.

The sale of this office building was not completed by the end of 2003 and as a
result the building no longer qualifies for held for sale status. In accordance
with SFAS 144 the building will be moved to held and used status for all periods
presented as of December 31, 2003. In December 2003 we recorded an additional
pre-tax impairment of $6 million based on bids received to date. The impairment
is recorded in Maintenance and Other Operation on our Consolidated Statements of
Operations. The building will continue to be actively marketed.

HPL and Other (Investments - Gas Operations segment)
----------------------------------------------------

HPL owns, or leases, and operates natural gas gathering, transportation and
storage operations in Texas. In 2003, management announced that we were in the
process of divesting our non-core assets, which includes the assets within our
Investments-Gas Operations segment. During the fourth quarter of 2003, based on
a probability-weighted after-tax cash flow analysis of the fair value of HPL, we
recorded an impairment of $300 million pre-tax ($218 million after-tax), with
$150 million pre-tax related to goodwill, reflecting management's decision not
to operate HPL as a major trading hub and market indicators supported by the LIG
bid process. The cash flow analysis used management's estimate of the
alternative likely outcomes of the uncertainties surrounding the continued use
of the Bammel facility and other matters (see Note 7) and an after-tax risk free
discount rate of 3.3% over the remaining life of the assets.

We also recorded a $15 million pre-tax charge ($10 million after-tax) in the
fourth quarter 2003 included in Asset Impairments and Other Related Charges on
our Consolidated Statements of Operations. This charge related to the effect of
the write-off of certain HPL and LIG assets and the impairment of goodwill
related to our former optimization strategy of LIG assets by AEP Energy
Services.

Blackhawk Coal Company (Utility Operations segment)
---------------------------------------------------

Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M and was
formerly engaged in coal mining operations until they ceased due to gas
explosions in the mine. During the fourth quarter of 2003, it was determined
that the carrying value of the investment was impaired based on an updated
valuation reflecting management's decision not to pursue development of
potential gas reserves. As a result, a $10.4 million pre-tax charge was recorded
to reduce the value of the coal and gas reserves to their estimated realizable
value. This charge was recorded in Asset Impairments and Other Related Charges
in our Consolidated Statements of Operations.

Power Generation Facility (Investments - Other segment)
-------------------------------------------------------

We have agreements with Juniper Capital L.P. (Juniper) for Juniper to develop,
construct, and finance a non-regulated merchant power generation facility
(Facility) near Plaquemine, Louisiana and for Juniper to lease the Facility to
us. Juniper will own the Facility and lease it to AEP after construction is
completed and we will sublease the Facility to The Dow Chemical Company (Dow).

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

The current litigation between TEM and ourselves, combined with a substantial
oversupply of generation capacity in the markets where we would otherwise sell
the power freed up by TEM contract termination, triggered us to review the
project for possible impairment of its reported values. We determined that the
value of the Facility was impaired and recorded a $258 million pre-tax
impairment ($168 million after-tax) in December 2003 on the CWIP.

See further discussion in Notes 7 and 16.

INVESTMENT VALUE AND OTHER LOSSES
---------------------------------

In 2003 and 2002, we recorded the following declines in fair value on
investments:

Independent Power Producers (Investments - Other segment)
---------------------------------------------------------

During the third quarter of 2003, we initiated an effort to sell four domestic
Independent Power Producer (IPP) investments accounted for under the equity
method. Based on indicative bids, it was determined that an other than temporary
impairment existed on two of the equity investments. The impairment was the
result of the measurement of fair value that was triggered by our recent
decision to sell the assets. A $70.0 million pre-tax ($45.5 million net of tax)
loss was recorded in September 2003 as a result of an other than temporary
impairment of the equity interest. This loss of investment value is included in
Investment Value Losses on our Consolidated Statements of Operations. We have
received bids on the IPP investments and anticipate a final sale during the
first half of 2004.

South Coast Power Investment (Investments - Other segment)
----------------------------------------------------------

South Coast Power is a 50% owned joint venture that was formed in 1996 to build
and operate a merchant closed-cycle gas turbine generator at Shoreham, U.K.
South Coast Power is subject to the same adverse wholesale electric power rates
described for U.K. Generation Plants above in "Discontinued Operations." A
December 2002 projected cash flow estimate of the fair value of the investment
indicated a 2002 pre-tax other than temporary impairment of the equity interest
(which included the fair value of supply contracts held by South Coast Power and
accounted for in accordance with SFAS 133) in the amount of $63.2 million. This
loss of investment value is included in Investment Value Losses on our
Consolidated Statements of Operations in 2002.

Technology Investments (Investments - Other segment)
----------------------------------------------------

We previously made investments totaling $11.7 million in four early-stage or
startup technologies involving pollution control and procurement. An analysis in
December 2002 of the viability of the underlying technologies and the projected
performance of the investee companies indicated that the investments were
unlikely to be recovered, and an other than temporary impairment of the entire
amount of the equity interest under APB 18 was recorded. The loss of investment
value is included in Investment Value Losses on our Consolidated Statements of
Operations.


11.  BENEFIT PLANS
------------------


In the U.S. we sponsor two qualified pension plans and two nonqualified pension
plans. A substantial majority of our employees in the U.S. are covered by either
one qualified plan or both a qualified and a nonqualified pension plan. Other
postretirement benefit plans are sponsored by us to provide medical and death
benefits for retired employees in the U.S.

We also have a foreign pension plan for employees of AEP Energy Services U.K.
Generation Limited (Genco) in the U.K. The Genco pension plan had $7 million of
accumulated benefit obligations in excess of plan assets at December 31, 2002.
The plan was in an overfunded position at December 31, 2003.

The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending at
the plan's measurement date of December 31, 2003, and a statement of the funded
status as of December 31 for both years:
<TABLE>
<CAPTION>
                                                                                                        U.S.
                                                                     U.S.                        Other Post Retirement
                                                                Pension Plans                        Benefit Plans
                                                                -------------                    ---------------------

                                                              2003            2002              2003            2002
                                                              ----            ----              ----            ----
Change in Benefit Obligation:                                                     (in millions)
<C>                                                         <C>            <C>                <C>              <C>
Obligation at January 1                                     $3,583         $3,292             $1,877           $1,645
Service Cost                                                    80             72                 42               34
Interest Cost                                                  233            241                130              114
Participant Contributions                                        -              -                 14               13
Plan Amendments                                                  -             (2)                 -                -
Actuarial (Gain) Loss                                           91            258                192              152
Benefit Payments                                              (299)          (278)               (92)             (81)
                                                            -------        -------           --------         --------
Obligation at December 31                                   $3,688         $3,583             $2,163           $1,877
                                                            =======        =======           ========         ========

Change in Fair Value of Plan Assets:
Fair Value of Plan Assets at January 1                      $2,795         $3,438               $723             $711
Actual Return on Plan Assets                                   619           (371)               122              (57)
Company Contributions (a)                                       65              6                183              137
Participant Contributions                                        -              -                 14               13
Benefit Payments (a)                                          (299)          (278)               (92)             (81)
                                                            -------        -------           --------         --------
Fair Value of Plan Assets at December, 31                   $3,180         $2,795               $950             $723
                                                            =======        =======           ========         ========

Funded Status:
Funded Status at December 31                                 $(508)         $(788)           $(1,213)         $(1,154)
Unrecognized Net Transition (Asset) Obligation                   2             (7)               206              233
Unrecognized Prior Service Cost                                (12)           (13)                 6                6
Unrecognized Actuarial (Gain) Loss                             797          1,020                977              896
                                                            -------        -------           --------         --------
Net Asset (Liability) Recognized                              $279           $212               $(24)            $(19)
                                                            =======        =======           ========         ========
</TABLE>


(a) Our contributions and benefit payments include only those amounts
    contributed directly to or paid directly from plan assets.

Accumulated Benefit Obligation:                           2003            2002
                                                          ----            ----
                                                              (in millions)
U.S. Qualified Pension Plans                             $3,549          $3,456
U.S. Nonqualified Pension Plans                              76              71

<TABLE>
<CAPTION>

                                                                                                        U.S.
                                                                    U.S.                        Other Post Retirement
                                                                Pension Plans                       Benefit Plans
                                                            -------------------                  ------------------
                                                            2003           2002                  2003          2002
                                                            ----           ----                  ----          ----
                                                                                 (in millions)
<C>                                                         <C>             <C>                 <C>             <C>
Prepaid Benefit Costs                                       $325            $255                  $-              $-
Accrued Benefit Liability                                    (46)            (44)                (24)            (19)
Additional Minimum Liability                                (723)           (944)                N/A             N/A
Unrecognized Prior Service Costs                              39              45                 N/A             N/A
Accumulated Other Comprehensive Income                       684             900                 N/A             N/A
                                                           ------           -----               -----            ----
Net Asset (Liability) Recognized                            $279            $212                $(24)           $(19)
                                                           ======           =====               =====           =====

Increase (Decrease) in Minimum Liability
  Included in Other Comprehensive Income (Pre-tax)         $(216)           $894                 N/A             N/A
                                                           ======           =====               =====           =====
</TABLE>


        N/A = Not Applicable

The asset allocations for our U.S. pension plans at the end of 2003 and 2002,
and the target allocation for 2004, by asset category, are as follows:
<TABLE>
<CAPTION>

                                              Target Allocation           Percentage of Plan Assets at Yearend
                                              -----------------           ------------------------------------
       Asset Category                                2004                     2003                    2002
       --------------                                ----                     ----                    ----
                                                                           (in percentage)

       <C>                                            <C>                      <C>                    <C>
       Equity                                          70                       71                     67
       Fixed Income                                    28                       27                     32
       Cash and Cash Equivalents                        2                        2                      1
                                                      ----                     ----                   ----
       Total                                          100                      100                    100
                                                      ====                     ====                   ====
</TABLE>



The asset allocations for our U.S. other postretirement benefit plans at the
end of 2003 and 2002, and target allocation for 2004, by asset category, are as
follows:
<TABLE>
<CAPTION>

                                              Target Allocation           Percentage of Plan Assets at Yearend
                                              -----------------           ------------------------------------
       Asset Category                                2004                      2003                  2002
       --------------                                ----                      ----                  ----
                                                                          (in percentage)

       <C>                                            <C>                      <C>                   <C>
       Equity                                          70                       61                    41
       Fixed Income                                    28                       36                    38
       Cash and Cash Equivalents                        2                        3                    21
                                                      ----                     ----                  ----
       Total                                          100                      100                   100
                                                      ====                     ====                  ====
</TABLE>



Our investment strategy for our employee benefit trust funds is to use a
diversified mixture of equity and fixed income securities to preserve the
capital of the funds and to maximize the investment earnings in excess of
inflation within acceptable levels of risk.

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

At December 31, 2003 and 2002, the projected benefit obligation, accumulated
benefit obligation, and fair value of U.S. plan assets of the U.S. pension plans
with an accumulated benefit obligation in excess of plan assets, were as
follows:

                                                         U.S. Plans
                                                         ----------
End of Year                                           2003        2002
-----------                                         --------    --------
                                                       (in millions)
Projected Benefit Obligation                         $3,688      $3,583
Accumulated Benefit Obligation                        3,625       3,527
Fair Value of Plan Assets                             3,180       2,795
Accumulated Benefit Obligation
 Exceeds the Fair Value of Plan Assets                  445         732

We base our determination of pension expense or income on a market-related
valuation of assets which reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related value
of assets and the actual return based on the market-related value of assets.
Since the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as previously
deferred gains or losses are recorded.

The weighted-average assumptions as of December 31, used in the measurement of
our benefit obligations are shown in the following tables:
<TABLE>
<CAPTION>

                                                                                    U.S.
                                               U.S.                         Other Postretirement
                                          Pension Plans                         Benefit Plans
                                          -------------                     --------------------

                                         2003        2002                   2003          2002
                                         ----        ----                   ----          ----
                                                          (in percentages)

        <C>                              <C>         <C>                    <C>            <C>
        Discount Rate                    6.25        6.75                   6.25           6.75
        Rate of Compensation Increase     3.7         3.7                    N/A            N/A
</TABLE>

2
In determining the discount rate in the calculation of future pension
obligations we review the interest rates of long-term bonds that receive one of
the two highest ratings given by a recognized rating agency. As a result of a
decrease in this benchmark rate during 2003, we determined that a decrease in
our discount rate from 6.75% at December 31, 2002 to 6.25% at December 31, 2003
was appropriate.

The rate of compensation increase assumed varies with the age of the employee,
ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.

Information about the expected cash flows for the U.S. pension (qualified and
non-qualified) and other postretirement benefit plans is as follows:
<TABLE>
<CAPTION>
                                                                                                U.S.
                                                                                        Other Postretirement
                                                               U.S. Pension Plans          Benefit Plans
                                                               ------------------       --------------------
                                                                              (in millions)
       <C>                                                       <C>                           <C>
       Employer Contributions
       2003                                                      $65                           $183
       2004 (expected)                                            41                            180
</TABLE>



The table below reflects the total benefits expected to be paid from the plan or
from our assets, including both our share of the benefit cost and the
participants' share of the cost, which is funded by participant contributions to
the plan. Future benefit payments are dependent on the number of employees
retiring, whether the retiring employees elect to receive pension benefits as
annuities or as lump sum distributions, future integration of the benefit plans
with changes to Medicare and other legislation, future levels of interest rates,
and variances in actuarial results. The estimated payments for pension benefits
and other postretirement benefits are as follows:
<TABLE>
<CAPTION>

                                                                                                  U.S.
                                                                    U.S.                  Other Postretirement
                                                              Pension Benefits                Benefit Plans
                                                              ----------------            --------------------
                                                                              (in millions)
       <C>                                                          <C>                          <C>
       2004                                                          $293                        $106
       2005                                                           300                         114
       2006                                                           310                         123
       2007                                                           325                         132
       2008                                                           335                         140
       Years 2009 to 2013, in Total                                 1,840                         836
</TABLE>


The contribution to the pension fund is based on the minimum amount required by
the U.S. Department of Labor or the amount of the pension expense for accounting
purposes, whichever is greater. The contribution to the other postretirement
benefit plans' trusts is generally based on the amount of the other
postretirement benefit plans' expense for accounting purposes and is provided
for in agreements with state regulatory authorities.

The following table provides the components of our net periodic benefit cost
(credit) for the plans for fiscal years 2003, 2002 and 2001:
<TABLE>
<CAPTION>

                                                             U.S.                                    U.S.
                                                        Pension Plans                 Other Postretirement Benefit Plans
                                                        -------------                 -----------------------------------
                                                 2003        2002        2001            2003        2002         2001
                                                 ----        ----        ----            ----        ----         ----
                                                                             (in millions)
       <C>                                       <C>         <C>         <C>             <C>         <C>          <C>
       Service Cost                               $80         $72         $69             $42         $34          $30
       Interest Cost                              233         241         232             130         114          114
       Expected Return on Plan Assets            (318)       (337)       (338)            (64)        (62)         (61)
       Amortization of Transition
        (Asset) Obligation                         (8)         (9)         (8)             28          29           30
       Amortization of Prior-service Cost          (1)         (1)          -               -           -            -
       Amortization of Net Actuarial
        (Gain) Loss                                11         (10)        (24)             52          27           18
                                                 -----       -----       -----           -----       -----        -----
       Net Periodic Benefit Cost (Credit)          (3)        (44)        (69)            188         142          131
       Curtailment Loss                             -           -           -               -           -            1
                                                 -----       -----       -----           -----       -----        -----
       Net Periodic Benefit Cost (Credit)
        After Curtailments                        $(3)       $(44)       $(69)           $188        $142         $132
                                                 =====       =====       =====           =====       =====        =====
</TABLE>


The weighted-average assumptions as of January 1, used in the measurement of our
benefit costs are shown in the following tables:
<TABLE>
<CAPTION>
                                                             U.S.                                    U.S.
                                                        Pension Plans                 Other Postretirement Benefit Plans
                                                        -------------                 ----------------------------------

                                                    2003        2002        2001          2003        2002         2001
                                                    ----        ----        ----          ----        ----         ----
                                                                             (in percentage)
       <C>                                          <C>         <C>         <C>           <C>         <C>          <C>
       Discount Rate                                6.75        7.25        7.50          6.75        7.25         7.50
       Expected Return on Plan Assets               9.00        9.00        9.00          8.75        8.75         8.75
       Rate of Compensation Increase                3.7         3.7         3.2           N/A         N/A          N/A
</TABLE>


The expected return on plan assets for 2003 was determined by evaluating
historical returns, the current investment climate, rate of inflation, and
current prospects for economic growth. After evaluating the current yield on
fixed income securities as well as other recent investment market indicators,
the expected return on plan assets was reduced to 8.75% for 2004. The expected
return on other postretirement benefit plan assets (a portion of which is
subject to capital gains taxes as well as Unrelated Business Income Taxes) was
reduced to 8.35%.

The assumptions used for other postretirement benefit plan measurement purposes
are shown below:

          Health Care Trend Rates:       2003             2002
                                        ------           ------
                                            (in percentage)
          Initial                         10.0            10.0
          Ultimate                         5.0             5.0
          Year Ultimate Reached           2008            2008

Assumed health care cost trend rates have a significant effect on the amounts
reported for the other postretirement benefit health care plans. A 1% change in
assumed health care cost trend rates would have the following effects:
<TABLE>
<CAPTION>

                                                                      1% Increase        1% Decrease
                                                                      -----------        -----------
                                                                             (in millions)
          <C>                                                              <C>               <C>
          Effect on Total Service and Interest Cost
           Components of Net Periodic Postretirement
           Health Care Benefit Cost                                        $26               $(21)

          Effect on the Health Care Component of the
           Accumulated Postretirement Benefit Obligation                   315               (257)
</TABLE>

We have not yet determined the impact of the Medicare Prescription Drug
Improvement and Modernization Act of 2003 on our other postretirement benefit
plans' accumulated benefit obligation and periodic benefit cost. See FASB Staff
Position No. 106-1 in Note 2 for additional information on the potential impact
on our results of operations, cash flows and financial condition.

AEP Savings Plans
-----------------

We sponsor various defined contribution retirement savings plans eligible to
substantially all non-United Mine Workers of America (UMWA) U.S. employees.
These plans include features under Section 401(k) of the Internal Revenue Code
and provide for company matching contributions. On January 1, 2003, the two
major AEP Savings Plans merged into a single plan. Beginning in 2001, and
continuing under the single merged plan, our contributions to the plans
increased from 50% to 75% of the first 6% of eligible employee compensation. The
cost for contributions to these plans totaled $57.0 million in 2003, $60.1
million in 2002 and $55.6 million in 2001.

Other UMWA Benefits
-------------------

We provide UMWA pension, health and welfare benefits for certain unionized
mining employees, retirees, and their survivors who meet eligibility
requirements. UMWA trustees make final interpretive determinations with regard
to all benefits. The pension benefits are administered by UMWA trustees and
contributions are made to their trust funds.

The health and welfare benefits are administered by us and benefits are paid
from our general assets. Contributions are expensed as paid as part of the cost
of active mining operations and were not material in 2003, 2002 and 2001.


12.  STOCK-BASED COMPENSATION
------------------------------


The American Electric Power System 2000 Long-Term Incentive Plan (the Plan)
authorizes the use of 15,700,000 shares of AEP common stock for various types of
stock-based compensation awards, including stock option awards, to key
employees. The Plan was adopted in 2000 by the Board of Directors and
shareholders.

Stock-based compensation awards granted by AEP include restricted stock units,
restricted shares, performance share units and stock options. Restricted stock
units vest, subject to the participant's continued employment, in approximately
equal 1/3 increments on January 1st for three years following the grant date.
Amounts equivalent to cash dividends on the units accrue as additional units.
AEP awarded 105,910 restricted stock units, including dividends, in 2003, with a
weighted-average grant-date fair value of $22.17 per unit. Compensation cost is
recorded over the vesting period, based on the market value on the grant date.
Expense associated with units that are forfeited is reversed in the period of
forfeiture.

AEP awarded 300,000 restricted shares in January 2004, which vest over periods
ranging from 1 to 8 years. Compensation cost will be recorded over the vesting
period based on the market value of $30.76 per unit on the grant date.

Performance share units are equal in value to shares of AEP common stock but are
subject to an attached performance factor ranging from 0% to 200%. The
performance factor is determined at the end of the performance period based on
performance measure(s) established for each grant at the beginning of the
performance period by the Human Resources Committee of the Board of Directors.
Performance share units are typically paid in cash at the end of a three-year
vesting period, unless they are needed to satisfy a participant's stock
ownership requirement, in which case they are mandatorily deferred as phantom
stock units until the end of the participants AEP career. Phantom stock units
have a value equivalent to AEP common stock and are typically paid in cash upon
the participant's termination of employment. The compensation cost for
performance share units is recorded over the vesting period and both the
performance share and phantom stock unit liability is adjusted for changes in
fair market value. Amounts equivalent to cash dividends on both performance
share and phantom stock units accrue as additional units.

Under the Plan, the exercise price of all stock option grants must equal or
exceed the market price of AEP's common stock on the date of grant, and in
accordance with its policy, AEP does not record compensation expense. AEP
generally grants options that have a ten-year life and vest, subject to the
participant's continued employment, in approximately equal 1/3 increments on
January 1 following the first, second and third anniversary of the grant date.

CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into
AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP
stock option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. Outstanding CSW stock options will continue in effect until all
options are exercised, cancelled or expired. Under the CSW stock option plan,
the option price was equal to the fair market value of the stock on the grant
date. All CSW options fully vested upon the completion of the merger and expire
10 years after their original grant date.

A summary of AEP stock option transactions in fiscal periods 2003, 2002 and 2001
is as follows:
<TABLE>
<CAPTION>


                                             2003                           2002                                2001
                                 ----------------------------    ----------------------------        ----------------------------

                                                     Weighted                        Weighted                            Weighted
                                                     Average                          Average                             Average
                                     Options         Exercise       Options          Exercise            Options         Exercise
                                 (in thousands)       Price      (in thousands)        Price          (in thousands)       Price
                                 --------------    ----------    --------------     ---------        --------------     ---------
       <C>                            <C>              <C>            <C>               <C>               <C>               <C>
       Outstanding at
        beginning of year             8,787            $34            6,822             $37               6,610             $36
          Granted                       927            $28            2,923             $27                 645             $45
          Exercised                     (23)           $27             (600)            $36                (216)            $38
          Forfeited                    (597)           $33             (358)            $41                (217)            $37
                                      ------                          ------                              ------
       Outstanding at end of year     9,094            $33            8,787             $34               6,822             $37
                                      ======                          ======                              ======
       Options exercisable
        at end of year                3,909            $36            2,481             $36                 395             $43
                                      ======                          ======                              ======

       Weighted average exercise price of options:
         -Granted above Market Price                   N/A                              $27                                 N/A
         -Granted at Market Price                      $28                              $27                                 $45
</TABLE>


The following table summarizes information about AEP stock options outstanding
at December 31, 2003:
<TABLE>
<CAPTION>


                     Options Outstanding
                     -------------------


                                                                                Weighted Average         Weighted Average
        Range of Exercise Prices               Number Outstanding               Remaining Life           Exercise Price
        ------------------------               ------------------               --------------           --------------
                                                 (in thousands)                   (in years)
        <C>                                             <C>                          <C>                       <C>
        $25.73 - $27.95                                 3,530                        9.1                       $27.28
        $34.58 - $41.50                                 5,054                        6.6                       $35.74
        $43.79 - $49.00                                   510                        7.5                       $45.98
                                                        ------

                                                        9,094                        7.6                       $33.03
                                                        ======
</TABLE>

<TABLE>
<CAPTION>

                    Options Exercisable
                    -------------------

        Range of Exercise Prices               Number Outstanding              Weighted Average Exercise Price
        ------------------------               ------------------              -------------------------------
                                                 (in thousands)
        <C>                                           <C>                                 <C>
        $25.73 - $27.95                                  52                               $27.06
        $34.58 - $41.50                               3,610                               $35.78
        $43.79 - $49.00                                 247                               $46.57
                                                      ------

                                                      3,909                               $36.35
                                                      ======
</TABLE>

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

The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of AEP options granted:
<TABLE>
<CAPTION>

                                                            2003               2002                 2001
                                                            ----               ----                 -----
          <C>                                              <C>                 <C>                <C>
          Risk Free Interest Rate                            3.92%               3.53%              4.87%
          Expected Life                                    7 years             7 years            7 years
          Expected Volatility                               27.57%              29.78%             28.40%
          Expected Dividend Yield                            4.86%               6.15%              6.05%


          Weighted average fair value of options:
           -Granted above Market Price                        N/A               $4.58                N/A
           -Granted at Market Price                         $5.26               $4.37              $8.01
</TABLE>


13.  BUSINESS SEGMENTS
----------------------


Our segments and their related business activities are as follows:

Utility Operations
o     Domestic generation of electricity for sale to retail and wholesale
      customers
o     Domestic electricity transmission and distribution

Investments - Gas Operations*
o     Gas pipeline and storage services

Investments - UK Operations**
o     International generation of electricity for sale to wholesale customers
o     Coal procurement and transportation to AEP plants and third parties

Investments - Other
o     Coal mining, bulk commodity barging operations and other energy supply
      businesses

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

The tables below present segment information for the twelve months ended
December 31, 2003, 2002 and 2001. These amounts include certain estimates and
allocations where necessary. Prior year amounts have been reclassified to
conform to the current year's presentation.
<TABLE>
<CAPTION>

                                                          Investments
                                                 ---------------------------------
                                     Utility        Gas          UK                        All     Reconciling
                                   Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                   ----------    ----------   ----------     -----        ------   -----------    ------------
2003                                                                     (in millions)
----
<C>                               <C>              <C>             <C>        <C>       <C>           <C>            <C>
Revenues from:
  External Customers              $10,871          $3,097            $-       $ 577         $-            $ -        $14,545
  Other Operating Segments              -             192             -          96         11           (299)             -
Discontinued Operations,
   Net of Tax                           -             (91)         (507)         (7)         -              -           (605)
Cumulative Effect of
  Accounting Changes,
   Net of Tax                         237             (23)          (21)          -          -              -            193
Net Income (Loss)                   1,455            (404)         (528)       (284)      (129)             -            110
Depreciation, Depletion and
  Amortization Expense              1,241              18             -          39          1              -          1,299
Total Assets                       30,816           2,405         1,705       1,697     14,925        (14,804)        36,744
Assets Held for Sale                1,033             240         1,624         185          -              -          3,082
Investments in Equity
  Method Subsidiaries                   -              36            38          87          -              -            161
Gross Property Additions            1,323              25             -          10          -              -          1,358
</TABLE>


*  All Other includes interest, litigation and other miscellaneous parent
   company expenses, as well as the operations of a service company subsidiary,
   which provides services at cost to the other operating segments.
<TABLE>
<CAPTION>

                                                          Investments
                                                ----------------------------------
                                     Utility        Gas          UK                        All     Reconciling
                                   Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                   ----------    ----------   ----------     -----        ------   -----------    ------------
2002                                                                     (in millions)
----
<C>                                 <C>            <C>            <C>       <C>          <C>          <C>             <C>
Revenues from:
  External Customers                $10,446        $2,071            $-       $791           $-           $ -         $13,308
  Other Operating Segments                -           222             -        147           10          (379)              -
Discontinued Operations,
  Net of Tax                              -             8          (472)      (190)           -             -            (654)
Cumulative Effect of
  Accounting Changes,
  Net of Tax                              -             -             -       (350)           -             -            (350)
Net Income (Loss)                     1,154           (91)         (472)    (1,062)         (48)            -            (519)
Depreciation, Depletion and
  Amortization Expense                1,268            13             -         67            -             -           1,348
Total Assets                         29,431         3,912         1,215      1,947       18,388       (19,003)         35,890
Assets Held for Sale                  1,866           375         1,150        210            -             -           3,601
Investments in Equity
  Method Subsidiaries                     -            35             -        137            -             -             172
Gross Property Additions              1,517            47             -         25           96             -           1,685
</TABLE>


* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.
<TABLE>
<CAPTION>


                                                          Investments
                                               ---------------------------------
                                  Utility        Gas           UK                        All     Reconciling
                                 Operations    Operations   Operations     Other        Other*   Adjustments    Consolidated
                                 ----------    ----------   ----------     -----        ------   -----------    ------------
2001                                                                    (in millions)
----
<C>                               <C>             <C>          <C>         <C>         <C>           <C>           <C>
Revenues from:
  External Customers              $10,546         $1,797        $-         $410         $-            $-           $12,753
  Other Operating Segments              -              -         -           86          5           (91)                -
Discontinued Operations,
  Net of Tax                            -             (4)      (41)          86          -             -                41
Extraordinary Items,
  Net of Tax                          (48)             -         -            -          -             -               (48)
Cumulative Effect,
  Net of Tax                            -              -         -           18          -             -                18
Net Income (Loss)                     911             87       (41)          86        (72)            -               971
Depreciation, Depletion and
  Amortization Expense              1,193             15         -           25          -             -             1,233
Gross Property Additions            1,397             14         -          137         98             -             1,646
</TABLE>


* All Other includes interest, litigation and other miscellaneous parent company
expenses, as well as the operations of a service company subsidiary, which
provides services at cost to the other operating segments.


14.  DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS
---------------------------------------------------


DERIVATIVES AND HEDGING
-----------------------

In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended. We recorded a favorable
transition adjustment to Accumulated Other Comprehensive Income (Loss) of $27
million at January 1, 2001 in connection with the adoption of SFAS 133.
Derivatives included in the transition adjustment are interest rate swaps,
foreign currency swaps and commodity swaps, options and futures. Most of the
derivatives identified in the transition adjustment were designated as cash flow
hedges and relate to foreign operations.

SFAS 133 requires recognition of all derivative instruments as either assets or
liabilities in the statement of financial position at fair value. Our accounting
for the changes in the fair value of a derivative instrument depends on whether
it qualifies, and has been designated, as part of a hedging relationship and
further, on the type of hedging relationship. We designate the hedging
instrument, based on the exposure being hedged, as a fair value hedge, a cash
flow hedge or a hedge of a net investment in a foreign operation. Certain
qualifying derivative instruments have been designated as normal purchase or
normal sale contracts, as provided in SFAS 133. These contracts are not reported
at fair value, as otherwise required by SFAS 133.

For fair value hedges (i.e. hedging the exposure to changes in the fair value of
an asset, liability or an identified portion thereof that is attributable to a
particular risk), we recognize the gain or loss on the derivative instrument as
well as the offsetting loss or gain on the hedged item associated with the
hedged risk in Revenues in the Consolidated Statement of Operations during the
period of change. For cash flow hedges (i.e. hedging the exposure to variability
in expected future cash flows that is attributable to a particular risk), we
initially report the effective portion of the gain or loss on the derivative
instrument as a component of Other Accumulated Comprehensive Income and
subsequently reclassify it to Revenues in the Consolidated Statement of
Operations when the forecasted transaction affects earnings. The remaining gain
or loss on the derivative instrument in excess of the cumulative change in the
present value of future cash flows of the hedged item, if any, is recognized
currently in Revenues during the period of change. For a hedge of a net
investment in a foreign currency, we include the effective portion of the gain
or loss in Other Accumulated Comprehensive Income as part of the cumulative
translation adjustment. We recognize any ineffective portion of the gain or loss
in Revenues immediately during the period of change.

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

Fair Value Hedging Strategies
-----------------------------

We enter into natural gas forward and swap transactions to hedge natural gas
inventory. The purpose of the hedging activity is to protect the natural gas
inventory against changes in fair value due to changes in the spot gas prices.
During the year ended December 31, 2003, we recognized a pre-tax loss of
approximately $3.4 million within revenues related to hedge ineffectiveness and
changes in time value excluded from the assessment of hedge ineffectiveness.


We enter into interest rate forward and swap transactions for interest rate risk
exposure management purposes. The interest rate forward and swap transactions
effectively modifies our exposure to interest risk by converting a portion of
our fixed-rate debt to a floating rate. We do not hedge all interest rate
exposure.

Cash Flow Hedging Strategies
----------------------------

We enter into forward contracts to protect against the reduction in value of
forecasted cash flows resulting from transactions denominated in foreign
currencies. When the dollar strengthens significantly against the foreign
currencies, the decline in value of future foreign currency revenue is offset by
gains in the value of the forward contracts designated as cash flow hedges.
Conversely, when the dollar weakens, the increase in the value of future foreign
currency cash flows is offset by losses in the value of forward contracts. We do
not hedge all foreign currency exposure.

We enter into interest rate forward and swap transactions in order to manage
interest rate risk exposure. These transactions effectively modify our exposure
to interest risk by converting a portion of our floating-rate debt to a fixed
rate. We do not hedge all interest rate exposure.

We enter into forward and swap transactions for the purchase and sale of
electricity and natural gas to manage the variable price risk related to the
forecasted purchase and sale of electricity. We closely monitor the potential
impacts of commodity price changes and, where appropriate, enter into contracts
to protect margins for a portion of future sales and generation revenues. We do
not hedge all variable price risk exposure related to the forecasted purchase
and sale of electricity.

Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on
our Consolidated Balance Sheets at December 31, 2003 are:
<TABLE>
<CAPTION>
                                                                                              Portion Expected to
                                                                   Accumulated                 Be Reclassified to
                             Hedging         Hedging           Other Comprehensive              Earnings during
                             Assets        Liabilities       Income (Loss) After Tax           the Next 12 Months
                             ------        -----------       -----------------------           ------------------
                                                                   (in millions)
<C>                            <C>          <C>                       <C>                              <C>
Power and Gas                  $21          $(121)                    $(65)                            $(58)
Interest Rate                    -             (7)                      (9)*                             (8)
Foreign Currency                 -            (30)                     (20)                             (20)
                                                                      -----                            -----
                                                                      $(94)                            $(86)
                                                                      =====                            =====
</TABLE>


* Includes $6 million loss recorded in an equity investment.

The net losses from cash flow hedges in Accumulated Other Comprehensive Income
(Loss) at December 31, 2003 are expected to be reclassified to net income in the
next twelve months as the items being hedged settle. The actual amounts
reclassified from AOCI to Net Income can differ as a result of market price
changes. The maximum term for which the exposure to the variability of future
cash flows is being hedged is five years.

The following table represents the activity in Accumulated Other Comprehensive
Income (Loss) for derivative contracts that qualify as cash flow hedges at
December 31, 2003:
                                                            (in millions)

  Beginning Balance, January 1, 2003                              $(16)
  Changes in fair value                                            (79)
  Reclasses from AOCI to net gain                                    1
                                                                  -----
  Ending Balance, December 31, 2003                               $(94)
                                                                  =====

Hedge of Net Investment in Foreign Operations
---------------------------------------------

In 2001 and 2002, we used foreign denominated fixed-rate debt to protect the
value of our investments in foreign subsidiaries in the U.K. Realized gains and
losses from these hedges are not included in the income statement, but are shown
in the cumulative translation adjustment account included in Other Accumulated
Comprehensive Income.

During 2002, we recognized $64 million of net losses, included in the cumulative
translation adjustment, related to the foreign denominated fixed-rate debt.

FINANCIAL INSTRUMENTS
---------------------

The fair values of Long-term Debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange.

The book values and fair values of significant financial instruments at December
31, 2003 and 2002 are summarized in the following tables.
<TABLE>
<CAPTION>

                                                   2003                                       2002
                                       ------------------------------           ----------------------------------

                                       Book Value          Fair Value           Book Value              Fair Value
                                       ----------          ----------           ----------              ----------
                                                (in millions)                               (in millions)

<C>                                     <C>                   <C>                 <C>                    <C>
Long-term Debt                          $14,101               $14,621             $10,190                $10,535
Cumulative Preferred
 Stocks of Subsidiaries
 Subject to Mandatory
 Redemption*                                 76                    76                  84                     77
Trust Preferred Securities                    -                     -                 321                    324
</TABLE>

     * See Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
       for the effect of SFAS 150 in 2003.

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value
--------------------------------------------------------------------------

The trust investments which are classified as available for sale for
decommissioning and SNF disposal, reported in "Spent Nuclear Fuel and
Decommissioning Trusts" and "Assets Held for Sale" on our Consolidated Balance
Sheets, are recorded at market value in accordance with SFAS 115 "Accounting
for Certain Investments in Debt and Equity Securities." At December 31, 2003
and 2002, the fair values of the trust investments were $1,107 million and $969
million, respectively, and had a cost basis of $995 million and $909 million,
respectively. The change in market value in 2003, 2002, and 2001 was a net
unrealized holding gain of $53 million and a net unrealized holding loss of
$33 million and $11 million, respectively.


15.  INCOME TAXES
-----------------


The details of our consolidated income taxes before discontinued operations,
extraordinary items, and cumulative effect as reported are as follows:
<TABLE>
<CAPTION>

                                                                                 Year Ended December 31,
                                                                     -----------------------------------------------
                                                                     2003                 2002                  2001
                                                                     ----                 ----                  ----
                                                                                      (in millions)
<C>                                                                  <C>                  <C>                   <C>
Federal:
  Current                                                            $297                 $307                  $411
  Deferred                                                             34                  (60)                   54
                                                                     -----                -----                 -----
Total                                                                 331                  247                   465
                                                                     -----                -----                 -----

State and Local:
  Current                                                              19                   32                    61
  Deferred                                                              1                   28                    34
                                                                     -----                -----                 -----
Total                                                                  20                   60                    95
                                                                     -----                -----                 -----

International:
  Current                                                               7                    8                    (7)
  Deferred                                                              -                    -                     -
                                                                     -----                -----                 -----
Total                                                                   7                    8                    (7)
                                                                     -----                -----                 -----

Total Income Tax as Reported Before
 Discontinued Operations, Extraordinary Items and
 Cumulative Effect                                                   $358                 $315                  $553
                                                                     =====                =====                 =====
</TABLE>


The following is a reconciliation of our consolidated difference between the
amount of federal income taxes computed by multiplying book income before
federal income taxes by the statutory tax rate and the amount of income taxes
reported.
<TABLE>
<CAPTION>

                                                                                   Year Ended December 31,
                                                                        ---------------------------------------------
                                                                           2003              2002             2001
                                                                        ---------         ---------         --------
                                                                                         (in millions)

<C>                                                                          <C>              <C>             <C>
Net Income (Loss)                                                            $110             $(519)            $971
Discontinued Operations (net of income tax of $312 million,
 $174 million and $14 million in 2003, 2002 and 2001,
 respectively)                                                                605               654              (41)
Extraordinary Items (net of income tax of $20 million in
 2001)                                                                          -                 -               48
Cumulative Effect of Accounting Change
 (net of income tax of $138 million in 2003)                                 (193)              350              (18)
Preferred Stock Dividends                                                       9                11               10
                                                                             -----            ------          -------
Income Before Preferred Stock Dividends of  Subsidiaries                      531               496              970
Income Taxes Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                                    358               315              553
                                                                             -----            ------          -------
Pre-Tax Income                                                               $889              $811           $1,523
                                                                             =====            ======          =======

Income Taxes on Pre-Tax Income at Statutory Rate (35%)                       $311              $284             $533
Increase (Decrease) in Income Taxes Resulting from the
 Following Items:
  Depreciation                                                                 40                32               48
  Asset Impairments and Investment Value Losses                                23                 4                -
  Investment Tax Credits (net)                                                (33)              (35)             (37)
  Tax Effects of International Operations                                       8                27              (22)
  Energy Production Credits                                                   (15)              (14)               -
  State Income Taxes                                                           13                39               62
  Other                                                                        11               (22)             (31)
                                                                             -----            ------          -------

Total Income Taxes as Reported Before
  Discontinued Operations, Extraordinary Items and
  Cumulative Effect                                                          $358              $315             $553
                                                                             =====            ======          =======

Effective Income Tax Rate                                                    40.3%             38.8%            36.3%
</TABLE>



The following table shows our elements of the net deferred tax liability and the
significant temporary differences.
<TABLE>
<CAPTION>
                                                                              As of December 31,
                                                                         --------------------------

                                                                            2003             2002
                                                                         -----------       --------
                                                                                (in millions)
<C>                                                                       <C>               <C>
Deferred Tax Assets                                                        $3,354            $2,604
Deferred Tax Liabilities                                                   (7,311)           (6,520)
                                                                          --------         ---------
Net Deferred Tax Liabilities                                              $(3,957)          $(3,916)
                                                                          ========          ========

Property Related Temporary Differences                                    $(2,836)          $(3,195)
Amounts Due From Customers For Future Federal
 Income Taxes                                                                (389)             (360)
Deferred State Income Taxes                                                  (416)             (422)
Transition Regulatory Assets                                                 (254)             (234)
Regulatory Assets Designated for Securitization                              (281)             (310)
Deferred Income Taxes on Other Comprehensive Loss                             306               326
All Other (net)                                                               (87)              279
                                                                          --------          --------
Net Deferred Tax Liabilities                                              $(3,957)          $(3,916)
                                                                          ========          ========
</TABLE>


We have settled with the IRS all issues from the audits of our consolidated
federal income tax returns for the years prior to 1991. We have received Revenue
Agent's Reports from the IRS for the years 1991 through 1996, and have filed
protests contesting certain proposed adjustments. Returns for the years 1997
through 2000 are presently being audited by the IRS. Management is not aware of
any issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.

We join in the filing of a consolidated federal income tax return with our
affiliated companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is in accordance
with SEC rules under the 1935 Act. These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to them in
determining their current tax expense. The tax loss of the System parent
company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the parent company, the method of allocation
approximates a separate return result for each company in the consolidated
group.

16.  LEASES
-----------

Leases of property, plant and equipment are for periods up to 99 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. Capital leases for non-regulated property are accounted for as if
the assets were owned and financed. The components of rental costs are as
follows:
<TABLE>
<CAPTION>


                                                                             Year Ended December 31,
                                                         ------------------------------------------------------------
                                                              2003                   2002                     2001
                                                         --------------         -------------             -----------
                                                                                (in millions)

<C>                                                            <C>                    <C>                      <C>
Lease Payments on Operating Leases                             $330                   $346                     $292
Amortization of Capital Leases                                   64                     65                       82
Interest on Capital Leases                                        9                     14                       22
                                                               -----                  -----                    -----

Total Lease Rental Costs                                       $403                   $425                     $396
                                                               =====                  =====                    =====
</TABLE>



Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
<TABLE>
<CAPTION>
                                                                             December 31,
                                                                       ----------------------
                                                                          2003         2002
                                                                       ---------    ---------
                                                                            (in millions)

<C>                                                                       <C>           <C>
Property, Plant and Equipment Under Capital Leases
  Production                                                               $37           $40
  Distribution                                                              15            15
  Other                                                                    470           687
                                                                          -----         -----
Total Property, Plant and Equipment                                        522           742
Accumulated Amortization                                                   218           299
                                                                          -----         -----
Net Property, Plant and Equipment Under Capital Leases                    $304          $443
                                                                          =====         =====

Obligations Under Capital Leases:
  Noncurrent Liability                                                    $131          $170
  Liability Due Within One Year                                             51            58
                                                                          -----         -----
Total Obligations under Capital Leases                                    $182          $228
                                                                          =====         =====
</TABLE>

Future minimum lease payments consisted of the following at December 31, 2003:
<TABLE>
<CAPTION>

                                                                                Noncancelable
                                                          Capital Leases       Operating Leases
                                                          --------------       ----------------
                                                                     (in millions)

<C>                                                             <C>                <C>
2004                                                             $63                 $291
2005                                                              43                  255
2006                                                              34                  237
2007                                                              31                  227
2008                                                              18                  214
Later Years                                                       31                2,331
                                                                -----              -------
Total Future Minimum Lease Payments                              220               $3,555
                                                                                   =======

Less Estimated Interest Element                                   38
                                                                -----
Estimated Present Value of Future
 Minimum Lease Payments                                         $182
                                                                =====
</TABLE>


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

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

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

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

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

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

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

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

See further discussion in Notes 7 and 10.

Gavin Lease
-----------

OPCo has entered into an agreement with JMG, an unrelated special purpose
entity. JMG has a capital structure of which 3% is equity from investors with no
relationship to AEP or any of its subsidiaries and 97% is debt from commercial
paper, pollution control bonds and other bonds. JMG was formed to design,
construct and lease the Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the
Gavin Scrubber and leases it to OPCo. Prior to July 1, 2003, the lease was
accounted for as an operating lease. Payments under the lease agreement are
based on JMG's cost of financing (both debt and equity) and include an
amortization component plus the cost of administration. OPCo and AEP do not have
an ownership interest in JMG and do not guarantee JMG's debt.

At any time during the lease, OPCo has the option to purchase the Gavin Scrubber
for the greater of its fair market value or adjusted acquisition cost (equal to
the unamortized debt and equity of JMG) or sell the Gavin Scrubber on behalf of
JMG. The initial 15-year lease term is non-cancelable. At the end of the initial
term, OPCo can renew the lease, purchase the Gavin Scrubber (terms previously
mentioned), or sell the Gavin Scrubber on behalf of JMG. In case of a sale at
less than the adjusted acquisition cost, OPCo must pay the difference to JMG.

On March 31, 2003, OPCo made a prepayment of $90 million under this lease
structure. AEP recognizes lease expense on a straight-line basis over the
remaining lease term, in accordance with SFAS 13 "Accounting for Leases." The
asset will be amortized over the remaining lease term, which ends in the first
quarter of 2010.

On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46. Upon
consolidation, OPCo recorded the assets and liabilities of JMG ($469.6 million).
OPCo now records the depreciation, interest and other operating expenses of JMG
and eliminates JMG's revenues against OPCo's operating lease expenses. There was
no cumulative effect of an accounting change recorded as a result of our
requirement to consolidate JMG, and there was no change in net income due to the
consolidation of JMG. Since the debt obligations of JMG are now consolidated,
the JMG lease is no longer accounted for on a consolidated basis as an operating
lease and has been excluded from the above table of future minimum lease
payments.

Rockport Lease
--------------

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

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

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the future minimum lease payments schedule earlier in
this note. The lease term is for 33 years with potential renewal options. At the
end of the lease term, AEGCo and I&M have the option to renew the lease or the
Owner Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an ownership
interest in the Owner Trustee and do not guarantee its debt.

Railcar Lease
-------------

In June 2003, we entered into an agreement with an unrelated, unconsolidated
leasing company to lease 875 coal-transporting aluminum railcars. The lease has
an initial term of five years and may be renewed for up to three additional
five-year terms, for a maximum of twenty years. We intend to renew the lease for
the full twenty years.
At the end of each lease term, we may (a) renew for another five-year term, not
to exceed a total of twenty years, (b) purchase the railcars for the purchase
price amount specified in the lease, projected at the lease inception to be the
then fair market value, or (c) return the railcars and arrange a third party
sale (return-and-sale option). The lease is accounted for as an operating lease
with the future payment included in the future minimum lease payments schedule
earlier in this note. This operating lease agreement allows us to avoid a large
initial capital expenditure, and to spread our railcar costs evenly over the
expected twenty-year usage.

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


17.  FINANCING ACTIVITIES
-------------------------


Trust Preferred Securities
--------------------------

PSO, SWEPCo and TCC have wholly-owned business trusts that have issued trust
preferred securities. The trusts which hold mandatorily redeemable trust
preferred securities were deconsolidated effective July 1, 2003 due to the
implementation of FIN 46. Therefore, $321 million ($75 million PSO, $110 million
SWEPCo and $136 million TCC), previously reported at December 31, 2002 as
Certain Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries, is now reported as two components on the Balance Sheet. The $10
million investment in the trust is now reported as Other within Other
Non-Current Assets while the $331 million of subordinated debentures are now
reported as Notes Payable to Trust within Long-term Debt.

The Junior Subordinated Debentures of PSO and TCC mature on April 30, 2037. In
October 2003, SWEPCo refinanced its Junior Subordinated Debentures which are
now due October 1, 2043. The following Trust Preferred Securities issued by the
wholly-owned statutory business trusts of PSO, SWEPCo and TCC were outstanding
at December 31, 2003 and 2002:

<TABLE>
<CAPTION>
                                                                                              Amount
                                            Units                           Amount in        Reported           Description of
                                           Issued/        Amount in       Notes Payable      Prior to            Underlying
                                         Outstanding       Other            to Trust          FIN 46            Debentures of
Business Trust       Security            at 12/31/03    at 12/31/03(a)    at 12/31/03(b)  at 12/31/02(c)         Registrant
--------------       --------            -----------    -------------     -------------   --------------        --------------
                                                        (in millions)     (in millions)    (in millions)

<C>                  <C>                   <C>              <C>              <C>              <C>            <C>
CPL Capital I        8.00%, Series A       5,450,000        $5               $141             $136           TCC, $141 million,
                                                                                                              8.00%, Series A

PSO Capital I        8.00%, Series A       3,000,000         2                 77               75           PSO, $77 million,
                                                                                                              8.00%, Series A

SWEPCo Capital I     7.875%, Series A              -         -                  -              110           SWEPCo, $113 million,
                                                                                                              7.875%, Series A

SWEPCo Capital I     5.25%, Series B         110,000         3                113                -           SWEPCo, $113 million,
                                           -----------     ----              -----            -----           5.25% five year fixed
                                                                                                              rate period, Series B



Total                                      8,560,000       $10               $331             $321
                                           ==========      ====              =====            =====
</TABLE>


(a) Amounts are in Other within Other Non-Current Assets.
(b) Amounts are in Notes Payable to Trust within Long-term Debt.
(c) Amounts reported on Balance Sheet prior to FIN 46.


Each of the business trusts is treated as a non-consolidated subsidiary of its
parent company. The only assets of the business trusts are the subordinated
debentures issued by their parent company as specified above. In addition to the
obligations under their subordinated debentures, each of the parent companies
has also agreed to a security obligation which represents a full and
unconditional guarantee of its capital trust obligation.

Minority Interest in Finance Subsidiary
---------------------------------------

We formed AEP Energy Services Gas Holding Co. II, LLC (SubOne) and Caddis
Partners, LLC (Caddis) in August 2001. SubOne is a wholly-owned consolidated
subsidiary that was capitalized with the assets of Houston Pipe Line Company and
Louisiana Intrastate Gas Company and $321.4 million of AEP Energy Services Gas
Holding Company (AEP Gas Holding is a subsidiary of AEP and the parent of
SubOne) preferred stock, that was convertible into AEP common stock at market
price on a dollar-for-dollar basis. Caddis was capitalized with $2 million cash
and a subscription agreement that represents an unconditional obligation to fund
$83 million from SubOne for a managing member interest and $750 million from
Steelhead Investors LLC (Steelhead) for a non-controlling preferred member
interest. As managing member, SubOne consolidated Caddis. Steelhead is an
unconsolidated special purpose entity and had an original capital structure of
$750 million (currently approximately $525 million) of which 3% is equity from
investors with no relationship to us or any of our subsidiaries and 97% is debt
from a syndicate of banks. The $525 million invested in Caddis by Steelhead was
loaned to SubOne. The loan to SubOne is due August 2006. Net proceeds from the
proposed sale of LIG will be used to reduce the outstanding balance of the loan
from Caddis (see Note 10 for additional information on LIG and HPL).

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

On May 9, 2003, SubOne borrowed $225 million from us and used the proceeds to
reduce the outstanding balance of the loan from Caddis, which Caddis used to
reduce the preferred interest held by Steelhead. This payment eliminated the
convertible preferred stock of AEP Gas Holding which under certain conditions
had been convertible to AEP common stock.

The credit agreement between Caddis and SubOne contains covenants that restrict
certain incremental liens and indebtedness, asset sales, investments,
acquisitions, and distributions. The credit agreement also contains covenants
that impose minimum financial ratios. Non-performance of these covenants may
result in an event of default under the credit agreement. Through December 31,
2003, SubOne has complied with the covenants contained in the credit agreement.
In addition, the acceleration of outstanding debt in excess of $50 million would
be an event of default under the credit agreement.

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

Steelhead has certain rights as a preferred member in Caddis. Upon the
occurrence of certain events, including a default in the payment of the
preferred return, Steelhead's rights include forcing a liquidation of Caddis and
acting as the liquidator. Liquidation of Caddis could negatively impact our
liquidity.

Caddis and SubOne are each a limited liability company, with a separate
existence and identity from its members, and the assets of each are separate and
legally distinct from us.

Equity Units
------------

In June 2002, AEP issued 6.9 million equity units at $50 per unit and received
proceeds of $345 million. Each equity unit consists of a forward purchase
contract and a senior note.

The forward purchase contracts obligate the holders to purchase shares of AEP
common stock on August 16, 2005. The purchase price per equity unit is $50. The
number of shares to be purchased under the forward purchase contract will be
determined under a formula based upon the average closing price of AEP common
stock near the stock purchase date. Holders may satisfy their obligation to
purchase AEP common stock under the forward purchase contracts by allowing the
senior notes to be remarketed or by continuing to hold the senior notes and
using other resources as consideration for the purchase of stock. If the holders
elect to allow the notes to be remarketed, the proceeds from the remarketing
will be used to purchase a portfolio of U.S. treasury securities that the
holders will pledge to AEP in order to meet their obligations under the forward
purchase contracts.

The senior notes have a principal amount of $50 each and mature on August 16,
2007. The senior notes are the collateral that secures the holders' requirement
to purchase common stock under the forward purchase contracts.

AEP is making quarterly interest payments on the senior notes at an initial
annual rate of 5.75%. The interest rate can be reset through a remarketing,
which is initially scheduled for May 2005. AEP makes contract adjustment
payments to the purchaser at the annual rate of 3.50% on the forward purchase
contracts. The present value of the contract adjustment payments was recorded as
a $31 million liability in Equity Unit Senior Notes offset by a charge to
Paid-in Capital in June 2002. Interest payments on the senior notes are reported
as interest expense. Accretion of the contract adjustment payment liability is
reported as interest expense.

AEP applies the treasury stock method to the equity units to calculate diluted
earnings per share. This method of calculation theoretically assumes that the
proceeds received as a result of the forward purchase contract are used to
repurchase outstanding shares.

Lines of Credit - AEP System
----------------------------

We use our corporate borrowing program to meet the short-term borrowing needs of
our subsidiaries. The corporate borrowing program includes a utility money pool,
which funds the utility subsidiaries, and a non-utility money pool, which funds
the majority of the non-utility subsidiaries. In addition, we also fund, as
direct borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or operational
reasons. As of December 31, 2003, we had credit facilities totaling $2.9 billion
to support our commercial paper program. At December 31, 2003, AEP had $326
million outstanding in short-term borrowings of which $282 million was
commercial paper supported by the revolving credit facilities. In addition, JMG
has commercial paper outstanding in the amount of $26 million. This commercial
paper is specifically associated with the Gavin scrubber lease identified in
Note 16 "Leases". This commercial paper does not reduce available liquidity to
AEP. The maximum amount of commercial paper outstanding during the year, which
had a weighted average interest rate during 2003 of 1.98%, was $1.5 billion
during January 2003. On December 11, 2002, Moody's Investor Services placed
AEP's Prime-2 short-term rating for commercial paper under review for possible
downgrade. On January 24, 2003, Standard & Poor's Rating Services placed AEP's
A-2 short-term rating for commercial paper under review for possible downgrade.
On February 10, 2003, Moody's Investor Services downgraded AEP's short-term
rating for commercial paper to Prime-3 from Prime-2. On March 7, 2003, Standard
& Poor's Rating Services reaffirmed AEP's A-2 short-term rating for commercial
paper.

Outstanding Short-term Debt consisted of:

                                   December 31,
                                   ------------
                                 2003        2002
                                 ----        ----
                                  (in millions)
Balance Outstanding:
  Notes Payable                   $18       $1,322
  Commercial Paper - AEP          282        1,417
  Commercial Paper - JMG           26            -
                                 -----      -------
  Total                          $326       $2,739
                                 =====      =======

Sale of Receivables - AEP Credit
--------------------------------

AEP Credit has a sale of receivables agreement with banks and commercial paper
conduits. Under the sale of receivables agreement, AEP Credit sells an interest
in the receivables it acquires to the commercial paper conduits and banks and
receives cash. This transaction constitutes a sale of receivables in accordance
with SFAS 140, allowing the receivables to be taken off of AEP Credit's balance
sheet and allowing AEP Credit to repay any debt obligations. AEP has no
ownership interest in the commercial paper conduits and does not consolidate
these entities in accordance with GAAP. We continue to service the receivables.
We entered into this off-balance sheet transaction to allow AEP Credit to repay
its outstanding debt obligations, continue to purchase the AEP operating
companies' receivables, and accelerate its cash collections.

AEP Credit extended its sale of receivables agreement to July 25, 2003 from its
May 28, 2003 expiration date. The agreement was then renewed for an additional
364 days and now expires on July 23, 2004. This new agreement provides
commitments of $600 million to purchase receivables from AEP Credit. At December
31, 2003, $385 million was outstanding. As collections from receivables sold
occur and are remitted, the outstanding balance for sold receivables is reduced
and as new receivables are sold, the outstanding balance of sold receivables
increases. All of the receivables sold represented affiliate receivables. AEP
Credit maintains a retained interest in the receivables sold and this interest
is pledged as collateral for the collection of the receivables sold. The fair
value of the retained interest is based on book value due to the short-term
nature of the accounts receivable less an allowance for anticipated
uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements with
certain registrant subsidiaries and, until the first quarter of 2002, with
non-affiliated companies. These subsidiaries include CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority
to sell accounts receivable in all of its regulatory jurisdictions, only a
portion of APCo's accounts receivable are sold to AEP Credit. As a result of the
restructuring of electric utilities in the State of Texas, the purchase
agreement between AEP Credit and Reliant Energy, Incorporated was terminated as
of January 25, 2002 and the purchase agreement between AEP Credit and Texas-New
Mexico Power Company, the last remaining non-affiliated company, was terminated
on February 7, 2002. In addition, the purchase agreements between AEP Credit and
its Texas affiliates, AEP Texas Central Company (formerly Central Power and
Light Company) and AEP Texas North Company (formerly West Texas Utilities
Company), were terminated effective March 20, 2002.

Comparative accounts receivable information for AEP Credit:
<TABLE>
<CAPTION>
                                                                                       Year Ended December 31,
                                                                                       -----------------------
                                                                                         2003           2002
                                                                                         ----           ----
                                                                                            (in millions)

        <C>                                                                             <C>             <C>
        Proceeds from Sale of Accounts Receivable                                       $5,221          $5,513
        Accounts Receivable Retained Interest Less Uncollectible
         Accounts and Amounts Pledged as Collateral                                        124              76
        Deferred Revenue from Servicing Accounts Receivable                                  1               1
        Loss on Sale of Accounts Receivable                                                  7               4
        Average Variable Discount Rate                                                    1.33%           1.92%
        Retained Interest if 10% Adverse Change in Uncollectible Accounts                  122              74
        Retained Interest if 20% Adverse Change in Uncollectible Accounts                  121              72
</TABLE>


Historical loss and delinquency amount for the AEP System's customer accounts
receivable managed portfolio:
<TABLE>
<CAPTION>
                                                                                                  Face Value
                                                                                            Year Ended December 31,
                                                                                            -----------------------
                                                                                                2003       2002
                                                                                                ----       ----
                                                                                                 (in millions)

      <C>                                                                                     <C>          <C>
      Customer Accounts Receivable Retained                                                   $1,155       $1,553
       Accrued Unbilled Revenues Retained                                                        596          551
       Miscellaneous Accounts Receivable Retained                                                 83           93
       Allowance for Uncollectible Accounts Retained                                            (124)        (108)
                                                                                              -------      -------
       Total Net Balance Sheet Accounts Receivable                                             1,710        2,089

       Customer Accounts Receivable Securitized (Affiliate)                                      385          454
                                                                                              -------      ------
       Total Accounts Receivable Managed                                                      $2,095       $2,543
                                                                                              =======      =======

       Net Uncollectible Accounts Written Off                                                    $39          $48
                                                                                              =======      =======
</TABLE>


Customer accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit. Miscellaneous accounts receivable
have been fully retained and not securitized.

At December 31, 2003, delinquent customer accounts receivable for the electric
utility affiliates that AEP Credit currently factors was $30 million.


18.  UNAUDITED QUARTERLY FINANCIAL INFORMATION
----------------------------------------------


Our unaudited quarterly financial information is as follows:
<TABLE>
<CAPTION>

                                                                             2003 Quarterly Periods Ended
                                                                             ----------------------------
                                                                 March 31      June 30      September 30     December 31
                                                                 --------      -------      ------------     -----------
(In Millions - Except Per Share Amounts)
----------------------------------------
<C>                                                               <C>           <C>             <C>            <C>
Revenues                                                          $3,834        $3,451          $3,940         $3,320
Operating Income (Loss)                                              630           393             735           (126)
Income (Loss) Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                           294           185             298           (255)
Net Income (Loss)                                                    440           175             257           (762)
Earnings (Loss) per Share Before Discontinued
 Operations, Extraordinary Items and Cumulative Effect*
                                                                    0.83          0.47            0.75          (0.65)
Earnings (Loss) per Share**                                         1.24          0.44            0.65          (1.93)

</TABLE>

<TABLE>
<CAPTION>

                                                                              2002 Quarterly Periods Ended
                                                                              ----------------------------
                                                                 March 31      June 30      September 30     December 31
                                                                 ---------     -------      ------------     -----------
(In Millions - Except Per Share Amounts)
----------------------------------------
<C>                                                              <C>            <C>             <C>             <C>
Revenues                                                         $2,802         $3,395          $3,639          $3,472
Operating Income                                                    420            433             781             170
Income (Loss) Before Discontinued Operations,
 Extraordinary Items and Cumulative Effect                          134            167             385            (201)
Net Income (Loss)                                                  (169)            62             425            (837)
Earnings (Loss) per Share Before Discontinued
 Operations, Extraordinary Items and Cumulative
 Effect***                                                         0.42           0.51            1.14           (0.59)
Earnings (Loss) per Share****                                     (0.53)          0.19            1.25           (2.47)
</TABLE>



* Amounts for 2003 do not add to $1.35 earnings per share before Discontinued
  Operations, Extraordinary Loss and Cumulative Effect due to rounding and the
  dilutive effect of shares issued in 2003.

** Amounts for 2003 do not add to $0.29 earnings per share due to rounding and
   the dilutive effect of shares issued in 2003.

*** Amounts for 2002 do not add to $1.46 earnings per share before Discontinued
    Operations, Extraordinary Loss and Cumulative Effect due to rounding.

**** Amounts for 2002 do not add to $(1.57) earnings per share due to rounding.

Income (Loss) Before Discontinued Operations, Extraordinary Items and Cumulative
Effect for the fourth quarter 2003 ($255 million loss) and 2002 ($201 million
loss) were significantly lower than the previous three quarters due to asset
impairments, investment value losses and other related charges. These pre-tax
writedowns ($650 million in the fourth quarter 2003 and $593 million in the
fourth quarter 2002) were made to reflect impairments and discontinued
operations as discussed in Note 10.


19.  SUBSEQUENT EVENTS (UNAUDITED)
----------------------------------

After December 31, 2003, we entered into separate agreements to dispose of the
following investments:

Investment                          Sales Price            Date of Agreement
----------                          -----------            -----------------
                                   (in millions)

Oklaunion Power Station                $42.8               January 30, 2004

LIG Pipeline and its subsidiaries      $76.2               February 13, 2004

STP                                   $332.6               February 27, 2004

We anticipate these sales to be completed during 2004 and that the impact on
results of operations will not be significant.

The Nanyang General Light (Pushan) investment was sold for $60.7 million on
March 2, 2004.  This sale had no significant impact on our results of
operations.

On March 10, 2004, we entered into an agreement to sell four domestic
Independent Power Producer (IPP) investments for a sales price of $156 million.
We anticipate this sale to be completed during 2004 and to result in a
pre-tax gain of approximately $100 million.
<PAGE>


INDEPENDENT AUDITORS' REPORT
----------------------------


To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:


We have audited the accompanying consolidated balance sheets of American
Electric Power Company, Inc. and subsidiary companies as of December 31, 2003
and 2002, and the related consolidated statements of operations, cash flows and
common shareholders' equity and comprehensive income, for each of the three
years in the period ended December 31, 2003. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and subsidiary companies as of December 31, 2003 and 2002,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 142, "Goodwill and Other Intangible Assets," effective January 1,
2002.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities" effective January 1, 2003.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities" effective
July 1, 2003.



/s/ Deloitte & Touche LLP

Columbus, Ohio
March 5, 2004



<PAGE>



MANAGEMENT'S RESPONSIBILITY
---------------------------

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

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




























                             AEP GENERATING COMPANY
















<PAGE>
<TABLE>
<CAPTION>

                                                              AEP GENERATING COMPANY
                                                             SELECTED FINANCIAL DATA




                                                         2003            2002            2001            2000            1999
                                                        ------          ------          ------          ------          ------
                                                                                    (in thousands)
              INCOME STATEMENTS DATA
-------------------------------------------------
<C>                                                    <C>             <C>             <C>             <C>             <C>
Operating Revenues                                     $233,165        $213,281        $227,548        $228,516        $217,189
Operating Expenses                                      225,991         207,152         220,571         220,092         211,849
                                                       ---------       ---------       ---------       ---------       ---------
Operating Income                                          7,174           6,129           6,977           8,424           5,340
Nonoperating Items, Net                                   3,340           3,681           3,484           3,429           3,659
Interest Charges                                          2,550           2,258           2,586           3,869           2,804
                                                       ---------       ---------       ---------       ---------       ---------
Net Income                                               $7,964          $7,552          $7,875          $7,984          $6,195
                                                       =========       =========       =========       =========       =========

               BALANCE SHEETS DATA
-------------------------------------------------
Electric Utility Plant                                 $674,055        $652,213        $648,254        $642,302        $640,093
Accumulated Depreciation                                351,062         330,187         310,804         290,858         271,941
                                                       ---------       ---------       ---------       ---------       ---------
Net Electric Utility Plant                             $322,993        $322,026        $337,450        $351,444        $368,152
                                                       =========       =========       =========       =========       =========

TOTAL ASSETS                                           $380,045        $377,716        $387,688        $399,310        $421,764
                                                       =========       =========       =========       =========       =========

Common Stock and Paid-in Capital                        $24,434         $24,434         $24,434         $24,434         $30,235
Retained Earnings                                        21,441          18,163          13,761           9,722           3,673
                                                       ---------       ---------       ---------       ---------       ---------
Total Common Shareholder's Equity                       $45,875         $42,597         $38,195         $34,156         $33,908
                                                       =========       =========       =========       =========       =========

Long-term Debt (a)                                      $44,811         $44,802         $44,793         $44,808         $44,800
                                                       =========       =========       =========       =========       =========

Obligations Under Capital Leases (a)                       $269            $501            $311            $591            $867
                                                       =========       =========       =========       =========       =========

TOTAL CAPITALIZATION AND LIABILITIES                   $380,045        $377,716        $387,688        $399,310        $421,764
                                                       =========       =========       =========       =========       =========

(a) Including portion due within one year.

</TABLE>


<PAGE>


                            AEP GENERATING COMPANY
             MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
             --------------------------------------------------------

AEGCo, co-owner of the Rockport Plant, is engaged in the generation and
wholesale sale of electric power to two affiliates, I&M and KPCo, under
long-term agreements. I&M is the operator and the other co-owner of the Rockport
Plant.

Operating revenues are derived from the sale of Rockport Plant energy and
capacity to I&M and KPCo pursuant to FERC approved long-term unit power
agreements. Under the terms of its unit power agreement, I&M agreed to purchase
all of AEGCo's Rockport energy and capacity unless it is sold to other utilities
or affiliates. I&M assigned 30% of its rights to energy and capacity to KPCo.
This assignment expires December 31, 2004.

The unit power agreements provide for a FERC approved rate of return on common
equity, a return on other capital (net of temporary cash investments) and
recovery of costs including operation and maintenance, fuel and taxes. Under the
terms of the unit power agreements, AEGCo accumulates all expenses monthly and
prepares bills for its affiliates. In the month the expenses are incurred, AEGCo
recognizes the billing revenues and establishes a receivable from the affiliated
companies.

Results of Operations
---------------------

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

Net Income increased $412 thousand for the year 2003 compared with the year
2002. The fluctuations in Net Income are a result of terms in the unit power
agreements which allow for the return on total capital of the Rockport Plant
calculated and adjusted monthly.

Operating Income
----------------

Operating Income increased $1 million for the year 2003 compared with the year
2002 primarily due to:

  o     A $20 million increase in Operating Revenue as a result of increased
        recoverable expenses, primarily Fuel for Electric Generation, in
        accordance with the unit power agreements along with increased return
        on total capital.
  o     A $2 million decrease in Maintenance and Other Operation expense. This
        decrease is due primarily to the impact of cost reduction efforts
        instituted in the fourth quarter of 2002 and related employment
        termination benefits allocated to AEGCo in 2002.

The increase in Operating Income was partially offset by:

  o     A $20 million increase in Fuel for Electric Generation expense. This
        increase is primarily due to an increase in the average cost of coal
        and an 8% increase in MWH generation.

Off-Balance Sheet Arrangements
------------------------------

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

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

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

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

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. Neither
AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of
these entities guarantee its debt.

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

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

<TABLE>
<CAPTION>

                                                                      Payments Due by Period
                                                                           (in millions)

Contractual Cash Obligations                Less Than 1 year      2-3 years    4-5 years      After 5 years      Total
----------------------------                ----------------      ---------    ---------      -------------      -----

<C>                                                 <C>             <C>            <C>            <C>           <C>
Long-term Debt                                        $-             $-             $-               $45           $45
Advances from Affiliates                              37              -              -                -             37
Unconditional Purchase
 Obligations (a)                                      82              75             75              161           393
Noncancellable Operating Leases                       74             148            148            1,033         1,403
                                                    -----           -----          -----          -------       -------
  Total                                             $193            $223           $223           $1,239        $1,878
                                                    =====           =====          =====          =======       =======

</TABLE>

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

Some of the transactions, described under "Off-Balance Sheet Arrangements"
above, have been employed for a contractual cash obligation reported in the
above table. The lease of Rockport Unit 2 is reported in Noncancellable
Operating Leases.

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.


<PAGE>
<TABLE>
<CAPTION>


                                                             AEP GENERATING COMPANY
                                                              STATEMENTS OF INCOME
                                               For the Years Ended December 31, 2003, 2002 and 2001


                                                                        2003                    2002                       2001
                                                                       ------                  ------                     ------
                                                                                           (in thousands)
<C>                                                                   <C>                     <C>                        <C>
OPERATING REVENUES                                                    $233,165                $213,281                   $227,548
                                                                      ---------               ---------                  ---------

               OPERATING EXPENSES
-------------------------------------------------
Fuel for Electric Generation                                           109,238                  89,105                    102,828
Rent - Rockport Plant Unit 2                                            68,283                  68,283                     68,283
Other Operation                                                         10,399                  12,924                     11,025
Maintenance                                                             10,346                   9,418                      8,853
Depreciation                                                            22,686                  22,560                     22,423
Taxes Other Than Income Taxes                                            3,396                   3,281                      4,257
Income Taxes                                                             1,643                   1,581                      2,902
                                                                      ---------               ---------                  ---------
TOTAL                                                                  225,991                 207,152                    220,571
                                                                      ---------               ---------                  ---------

OPERATING INCOME                                                         7,174                   6,129                      6,977

Nonoperating Income                                                        151                     344                         30
Nonoperating Expenses                                                      361                     199                         16
Nonoperating Income Tax Credits                                          3,550                   3,536                      3,470
Interest Charges                                                         2,550                   2,258                      2,586
                                                                      ---------               ---------                  ---------
NET INCOME                                                              $7,964                  $7,552                     $7,875
                                                                      =========               =========                  =========
</TABLE>

<TABLE>
<CAPTION>


                                                          STATEMENTS OF RETAINED EARNINGS
                                                For the Years Ended December 31, 2003, 2002 and 2001

                                                                        2003                    2002                       2001
                                                                       ------                  ------                     ------
                                                                                           (in thousands)

<C>                                                                    <C>                     <C>                        <C>
BALANCE AT BEGINNING OF PERIOD                                         $18,163                 $13,761                     $9,722

Net Income                                                               7,964                   7,552                      7,875

Cash Dividends Declared                                                  4,686                   3,150                      3,836
                                                                       --------                --------                   --------

BALANCE AT END OF PERIOD                                               $21,441                 $18,163                    $13,761
                                                                       ========                ========                   ========

The common stock of AEGCo is wholly-owned by AEP.

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


                                                     AEP GENERATING COMPANY
                                                         BALANCE SHEETS
                                                             ASSETS
                                                    December 31, 2003 and 2002


                                                                                           2003                      2002
                                                                                          ------                    ------
                                                                                                    (in thousands)
               ELECTRIC UTILITY PLANT
-------------------------------------------------
<C>                                                                                      <C>                       <C>
Production                                                                               $645,251                  $637,095
General                                                                                     4,063                     4,728
Construction Work in Progress                                                              24,741                    10,390
                                                                                         ---------                 ---------
TOTAL                                                                                     674,055                   652,213
Accumulated Depreciation                                                                  351,062                   330,187
                                                                                         ---------                 ---------
TOTAL - NET                                                                               322,993                   322,026
                                                                                         ---------                 ---------

OTHER PROPERTY AND INVESTMENTS - Non-Utility Property, Net                                    119                       119
                                                                                         ---------                 ---------

                 CURRENT ASSETS
-------------------------------------------------
Accounts Receivable - Affiliated Companies                                                 24,748                    18,454
Fuel                                                                                       20,139                    20,260
Materials and Supplies                                                                      5,419                     4,913
                                                                                         ---------                 ---------
TOTAL                                                                                      50,306                    43,627
                                                                                         ---------                 ---------

          DEFERRED DEBITS AND OTHER ASSETS
-------------------------------------------------
Regulatory Assets:
  Unamortized Loss on Reacquired Debt                                                       4,733                     4,970
  Asset Retirement Obligations                                                                928                         -
Deferred Charges                                                                              966                     6,974
                                                                                         ---------                 ---------
TOTAL                                                                                       6,627                    11,944
                                                                                         ---------                 ---------


TOTAL ASSETS                                                                             $380,045                  $377,716
                                                                                         =========                 =========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                             AEP GENERATING COMPANY
                                                                 BALANCE SHEETS
                                                         CAPITALIZATION AND LIABILITIES
                                                           December 31, 2003 and 2002

                                                                                           2003                      2002
                                                                                          ------                    ------
                                                                                                   (in thousands)
                CAPITALIZATION
-------------------------------------------------
<C>                                                                                      <C>                       <C>
Common Shareholder's Equity:
   Common Stock - Par Value $1,000 per share:
     Authorized and Outstanding - 1,000 Shares                                             $1,000                    $1,000
     Paid-in Capital                                                                       23,434                    23,434
     Retained Earnings                                                                     21,441                    18,163
                                                                                         ---------                 ---------
Total Common Shareholder's Equity                                                          45,875                    42,597
Long-term Debt                                                                             44,811                    44,802
                                                                                         ---------                 ---------
TOTAL                                                                                      90,686                    87,399
                                                                                         ---------                 ---------
              CURRENT LIABILITIES
-------------------------------------------------
Advances from Affiliates                                                                   36,892                    28,034
Accounts Payable:
   General                                                                                    498                        26
   Affiliated Companies                                                                    15,911                    15,907
Taxes Accrued                                                                               6,070                     2,327
Interest Accrued                                                                              911                       911
Obligations Under Capital Leases                                                               87                       200
Rent Accrued - Rockport Plant Unit 2                                                        4,963                     4,963
                                                                                         ---------                 ---------
TOTAL                                                                                      65,332                    52,368
                                                                                         ---------                 ---------

       DEFERRED CREDITS AND OTHER LIABILITIES
-------------------------------------------------
Deferred Income Taxes                                                                      24,329                    29,002
Regulatory Liabilities:
  Asset Removal Costs                                                                      27,822                         -
  Deferred Investment Tax Credits                                                          49,589                    52,943
  SFAS 109 Regulatory Liability, Net                                                       15,505                    16,670
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                               105,475                   111,046
Obligations Under Capital Leases                                                              182                       301
Asset Retirement Obligations                                                                1,125                         -
Other                                                                                           -                    27,987
                                                                                         ---------                 ---------
TOTAL                                                                                     224,027                   237,949
                                                                                         ---------                 ---------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                     $380,045                  $377,716
                                                                                         =========                 =========
</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                                               AEP GENERATING COMPANY
                                                              STATEMENTS OF CASH FLOWS
                                                 For the Years Ended December 31, 2003, 2002 and 2001

                                                                            2003                 2002                2001
                                                                           ------               ------              ------
                                                                                     (in thousands)
              OPERATING ACTIVITIES
-------------------------------------------------

<C>                                                                           <C>                 <C>                   <C>
Net Income                                                                     $7,964             $7,552                $7,875
Adjustments to Reconcile Net Income to Net Cash  Flows From
Operating Activities:
  Depreciation                                                                 22,686             22,560                22,423
  Deferred Income Taxes                                                        (5,838)            (5,028)               (6,224)
  Deferred Investment Tax Credits                                              (3,354)            (3,361)               (3,414)
  Amortization of Deferred Gain on Sale and Leaseback -
   Rockport Plant Unit 2                                                       (5,571)            (5,571)               (5,571)
Changes in Certain Assets and Liabilities:
  Accounts Receivable                                                          (6,294)             4,037                 1,224
  Fuel, Materials and Supplies                                                   (385)            (5,450)               (4,738)
  Accounts Payable                                                                476              6,697                (4,597)
  Taxes Accrued                                                                 3,743             (2,450)                 (216)
  Deferred Property Taxes                                                         (45)               190                   (49)
  Change in Other Assets                                                        3,531             (5,401)                 (520)
  Change in Other Liabilities                                                   1,007             (2,295)               (1,244)
                                                                              --------            -------               -------
Net Cash Flows From Operating Activities                                       17,920             11,480                 4,949
                                                                              --------            -------               -------

              INVESTING ACTIVITIES
-------------------------------------------------
Construction Expenditures                                                     (22,197)            (5,298)               (6,868)
Proceeds From Sale of Assets                                                      105                  -                     -
                                                                              --------            -------               -------
Net Cash Flows Used For Investing Activities                                  (22,092)            (5,298)               (6,868)
                                                                              --------            -------               -------

              FINANCING ACTIVITIES
-------------------------------------------------
Change in Advances from Affiliates                                              8,858             (4,015)                3,981
Dividends Paid                                                                 (4,686)            (3,150)               (3,836)
                                                                              --------            -------               -------
Net Cash Flows From (Used For) Financing Activities                             4,172             (7,165)                  145
                                                                              --------            -------               -------

Net Decrease in Cash and Cash Equivalents                                           -               (983)               (1,774)
Cash and Cash Equivalents at Beginning of Period                                    -                983                 2,757
                                                                              --------            -------               -------
Cash and Cash Equivalents at End of Period                                         $-                 $-                  $983
                                                                              ========            =======               =======
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $2,283,000, $2,019,000
and $1,509,000 and for income taxes was $6,483,000, $7,884,000 and $8,597,000
in 2003, 2002 and 2001, respectively.

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

<PAGE>
<TABLE>
<CAPTION>



                                                       AEP GENERATING COMPANY
                                                    STATEMENTS OF CAPITALIZATION
                                                     December 31, 2003 and 2002


                                                                                                             2003            2002
                                                                                                            ------          ------
                                                                                                                  (in thousands)

<C>                                                                                                         <C>            <C>
COMMON SHAREHOLDER'S EQUITY                                                                                 $45,875        $42,597
                                                                                                            --------       --------

LONG-TERM DEBT:
Installment Purchase Contracts - City of Rockport (a) Series Due Date
      1995 A          2025 (b)                                                                               22,500         22,500
      1995 B          2025 (b)                                                                               22,500         22,500
Unamortized Discount                                                                                           (189)          (198)
                                                                                                          ----------     ----------
TOTAL LONG-TERM DEBT                                                                                         44,811         44,802
                                                                                                           ---------      ---------

TOTAL CAPITALIZATION                                                                                        $90,686        $87,399
                                                                                                            ========       ========

</TABLE>

(a)  Installment purchase contracts were entered into in connection with the
     issuance of pollution control revenue bonds by the City of Rockport,
     Indiana. The terms of the installment purchase contracts require AEGCo to
     pay amounts sufficient to enable the payment of interest and principal on
     the related pollution control revenue bonds issued to refinance the
     construction costs of pollution control facilities at the Rockport Plant.
(b)  These series have an adjustable interest rate that can be a daily, weekly,
     commercial paper or term rate as designated by AEGCo. Prior to July 13,
     2001, AEGCo had selected a daily rate which ranged from 0.9% to 5.6% during
     2001 and averaged 2.8% in 2001. Effective July 13, 2001, AEGCo selected a
     term rate of 4.05% for five years ending July 12, 2006.

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




<PAGE>
<TABLE>
<CAPTION>

                                                 AEP GENERATING COMPANY
                                      INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS


The notes to AEGCo's financial statements are combined with the notes to respective financial statements for other subsidiary
registrants. Listed below are the notes that apply to AEGCo. The footnotes begin on page L-1.

                                                                                                                       Footnote
                                                                                                                       Reference
                                                                                                                       ---------

<C>                                                                                                                    <C>
Organization and Summary of Significant Accounting Policies                                                            Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                         Note 2

Effects of Regulation                                                                                                  Note 5

Commitments and Contingencies                                                                                          Note 7

Guarantees                                                                                                             Note 8

Sustained Earnings Improvement Initiative                                                                              Note 9

Benefit Plans                                                                                                          Note 11

Business Segments                                                                                                      Note 12

Derivatives, Hedging and Financial Instruments                                                                         Note 13

Income Taxes                                                                                                           Note 14

Leases                                                                                                                 Note 15

Financing Activities                                                                                                   Note 16

Related Party Transactions                                                                                             Note 17

Unaudited Quarterly Financial Information                                                                              Note 19

</TABLE>

<PAGE>


INDEPENDENT AUDITORS' REPORT
----------------------------

To the Shareholder and Board of Directors
of AEP Generating Company:

We have audited the accompanying balance sheets and statements of capitalization
of AEP Generating Company as of December 31, 2003 and 2002, and the related
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2003. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of AEP Generating Company as of December 31,
2003 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004


<PAGE>









                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY





<PAGE>
<TABLE>
<CAPTION>



                                                     AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                       SELECTED CONSOLIDATED FINANCIAL DATA

                                                        2003              2002            2001           2000              1999
                                                       ------            ------          ------         ------            ------
                                                                                    (in thousands)
       INCOME STATEMENTS DATA
-------------------------------------------
<C>                                                   <C>              <C>             <C>             <C>              <C>
Operating Revenues                                    $1,747,511       $1,690,493      $1,738,837      $1,770,402       $1,482,475
Operating Expenses                                     1,425,971        1,296,760       1,443,106       1,463,304        1,188,490
                                                      -----------      -----------     -----------     -----------      -----------
Operating Income                                         321,540          393,733         295,731         307,098          293,985
Nonoperating Items, Net                                   29,819            8,079           2,815           7,235            2,596
Interest Charges                                         133,812          125,871         116,268         124,766          114,380
                                                      -----------      -----------     -----------     -----------      -----------
Income Before Cumulative Effect of Accounting Change     217,547          275,941         182,278         189,567          182,201
Cumulative Effect of Accounting Change (Net of Tax)          122                -               -               -                -
                                                      -----------      -----------     -----------     -----------      -----------
Net Income                                               217,669          275,941         182,278         189,567          182,201
Preferred Stock Dividend Requirements                        241              241             242             241            6,931
Gain (Loss) on Reacquired Preferred Stock                      -                4               -               -           (2,763)
                                                      -----------      -----------     -----------     -----------      -----------
Earnings Applicable To Common Stock                     $217,428         $275,704        $182,036        $189,326         $172,507
                                                      ===========      ===========     ===========     ===========      ===========

            BALANCE SHEETS DATA
-------------------------------------------
Electric Utility Plant                                $2,425,038       $2,334,794      $2,231,287      $2,097,497       $1,996,374
Accumulated Depreciation and Amortization                695,359          662,345         616,526         570,522          598,275
                                                      -----------      -----------     -----------     -----------      -----------
Net Electric Utility Plant                            $1,729,679       $1,672,449      $1,614,761      $1,526,975       $1,398,099
                                                      ===========      ===========     ===========     ===========      ===========

TOTAL ASSETS                                          $5,824,707       $5,453,960      $4,989,381      $5,556,275       $4,930,547
                                                      ===========      ===========     ===========     ===========      ===========

Common Stock and Paid-in Capital                        $187,898         $187,898        $573,903        $573,904         $573,904
Retained Earnings                                      1,083,023          986,396         826,197         792,219          758,894
Accumulated Other Comprehensive Income (Loss)            (61,872)         (73,160)              -               -                -
                                                      -----------      -----------     -----------     -----------      -----------
Total Common Shareholder's Equity                     $1,209,049       $1,101,134      $1,400,100      $1,366,123       $1,332,798
                                                      ===========      ===========     ===========     ===========      ===========

Cumulative Preferred Stock Not Subject to
 Mandatory Redemption                                     $5,940           $5,942          $5,952          $5,951          $5,951
                                                      ===========      ===========     ===========     ===========      ===========

Trust Preferred Securities (a)                                $-         $136,250        $136,250        $148,500         $150,000
                                                      ===========      ===========     ===========     ===========      ===========

Long-term Debt (b)                                    $2,291,625       $1,438,565      $1,253,768      $1,454,559       $1,454,541
                                                      ===========      ===========     ===========     ===========      ===========

Obligations Under Capital Leases (b)                      $1,043               $-              $-              $-               $-
                                                      ===========      ===========     ===========     ===========      ===========

TOTAL CAPITALIZATION AND LIABILITIES                  $5,824,707       $5,453,960      $4,989,381      $5,556,275       $4,930,547
                                                      ===========      ===========     ===========     ===========      ===========

</TABLE>

(a) See Note 16 of the Notes to Respective Financial Statements.
(b) Including portion due within one year.

<PAGE>



                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

AEP Texas Central Company (TCC), formerly know as Central Power and Light
Company (CPL), is a public utility engaged in the generation and purchase of
electric power, and the subsequent sale, transmission and distribution of that
power. As a power pool member with AEP West companies, we share in the revenues
and expenses of the power pool's sales to neighboring utilities and power
marketers. TCC also sells electric power at wholesale to other utilities,
municipalities, rural electric cooperatives and retail electric providers (REPs)
in Texas.

Power pool members are compensated for energy delivered to other members based
upon the delivering members' incremental cost plus a portion of the savings
realized by the purchasing member that avoids the use of more costly
alternatives. The revenue and costs for sales to neighboring utilities and power
marketers made by AEPSC on behalf of the AEP West companies are shared among the
members based upon the relative magnitude of the energy each member provides to
make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

Net Income decreased $58 million for 2003. The decrease is mainly due to an
increased provision for refunds of $85 million ($55 million after tax) and a
decrease in the recognition of non-cash earnings related to legislatively
mandated capacity auctions and regulatory assets established in Texas of $29
million net of tax. Additionally, income from transactions with ERCOT increased
significantly due mainly to Texas Restructuring Legislation.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs, effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a shift in our sales as further described below.

In December 2002, AEP sold Mutual Energy CPL to an unrelated third party, who
assumed the obligations of the affiliated REP including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy CPL were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions and delivery charges
with Mutual Energy CPL are classified as Electric Generation, Transmission and
Distribution.

Operating Income
----------------

Operating Income decreased $72 million primarily due to:

  o     Increased  provisions  for rate refunds of $85 million due mainly to
        2003 Texas fuel issues (see "TCC Fuel Reconciliation" in Note 4).
  o     Decreased revenues associated with establishing regulatory assets
        in Texas of $44 million or 17% in 2003 (see "Texas Restructuring"
        in Note 6). These revenues will not continue after 2003.
  o     Decreased system sales, including those to REPs, of $7 million due
        mainly to a decrease in the overall average price per KWH and
        higher KWH sales of 2%.
  o     Decreased revenues from ERCOT for various services, including balancing
        energy, of $7 million or 7%.
  o     The 2002 ICR adjustments which accounted for approximately $59 million
        of the decrease in revenue with an offsetting $51 million decrease in
        purchased power.
  o     Decreased retail revenues of $24 million driven by a 9% decrease
        in cooling degree-days offset by a slight increase in heating
        degree-days. Average price per KWH decreased 2%.
  o     Increases in fuel and purchased electricity on a net basis of $197
        million to replace portions of the energy from the non-RMR mothballed
        plants and the unscheduled forced outage at the STP nuclear unit
        (See "Significant Factors" below). KWH purchased increased 47% while
        the cost increased 54%. Although the KWH generated decreased, fuel
        costs increased 16% due to higher per unit costs attributable mostly to
        natural gas.
  o     Increased Maintenance expense of $8 million due mainly to the STP
        Unit 2 forced outage in the first quarter of 2003 and the STP Unit 1
        scheduled refueling outage and forced outage in the second and third
        quarters of 2003.

The decrease in Operating Income was partially offset by:

  o     Increased Reliability Must Run (RMR) revenues from ERCOT of $214
        million which include both fuel recovery and a fixed cost component of
        $35 million (see "Texas Plants" in Note 10 for discussion of RMR
        facilities).
  o     Increased margins of $31 million resulting from risk management
        activities.
  o     Increased other operating revenue of $25 million comprised primarily of
        miscellaneous service revenue and fees as a result of the Texas
        Restructuring Legislation.
  o     Decreased Other Operation expense of $6 million due primarily to lower
        distribution and customer related expenses in 2003, offset in part by
        $16 million of accretion expense associated with the implementation of
        SFAS 143, as well as increased cost of $6 million related to 2003
        ERCOT transmission charges.
  o     Decreased Depreciation and Amortization expense of $25 million due
        mainly to decreases resulting from ARO of $16 million (see Note 2)
        and reduced depreciable plant by $6 million due to the mothballing
        of certain generating units in 2002.
  o     Decreased Taxes Other Than Income Taxes of $3 million due mainly
        to reduce gross receipt taxes as a result of the sale of the Texas
        REPs, partially offset by higher property taxes.
  o     Decreased Income Taxes of $41 million due to decreased pre-tax
        operating income.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $1 million. While 2003 gains from risk management
activities increased $33 million, they are almost totally offset by lower 2003
revenues of $33 million from third party non-utility energy related construction
projects.

Nonoperating Expense decreased $25 million primarily due to lower non-utility
expenses associated with energy related construction projects for third parties.

Nonoperating Income Tax Expense (Credit) increased $4 million due to increased
pre-tax nonoperating income partially offset by changes related to consolidated
tax savings.


Interest Charges increased $8 million primarily due to the replacement of lower
cost short-term floating rate debt with longer-term higher cost fixed rate debt.

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

In 2002, Net Income increased $94 million primarily due to $262 million of
revenue associated with recognition of stranded costs in Texas offset in part by
losses associated with the commencement of customer choice in Texas, which
resulted in the loss of customers and reduced prices (see Note 6).

Operating Income
----------------

Operating Income increased $98 million primarily due to:

  o     Increased revenue associated with establishing regulatory assets in
        Texas of $262 million in 2002 (see "Texas Restructuring" in Note 6).
  o     Increased system sales, including those to REPs, of $84 million
        due mainly to the newly created affiliated REP, offset by retail
        fuel revenue, as a result of Texas Restructuring Legislation.
  o     Increase revenues of $73 million from ERCOT for various services,
        including balancing energy, as a result of Texas Restructuring
        Legislation.
  o     The 2002 ICR adjustments which accounted for approximately $59
        million of the increase in revenue with an offsetting $51 million
        increase in purchased power (See "ICR Explanation" in Note 4 for
        discussion of the ICR adjustments).
  o     Decreased provisions for rate refunds of $3 million due mainly to a
        2001 FERC transmission tariff refund.
  o     Increased RMR revenues from ERCOT of $28 million which include both
        fuel recovery and a fixed cost component (see "Texas Plants" in Note
        10 for discussion of RMR facilities).
  o     Net decreases in fuel and purchased electricity on a combined
        basis of $198 million due to a decrease in both generation and the
        average cost of fuel, offset in part by increased KWH purchased.
        More KWH were purchased in part due to our ability to purchase
        power below our cost to produce. KWH purchased increased 5% while
        the total cost increased 26%. The KWH generated decreased by 27%
        and fuel costs decreased 50%.
  o     Decreased Other Operation expense of $17 million due to the
        elimination of factoring of accounts receivable, as well as lower
        ERCOT transmission charges.
  o     Decreased Maintenance expense of $8 million due mainly to two
        scheduled "18 months interval" refueling outages for STP during
        2001 that increased maintenance expense above the 2002 level. Also
        contributing to the decrease in 2002 was an increase in
        maintenance expense for scheduled major overhauls of four power
        plants in 2001.

The increase in Operating Income was partially offset by:

  o     Decreased retail revenues due to the Texas  Restructuring  Legislation
        of $467 million in 2002 (see "Texas Restructuring" in Note 6).
  o     Decreased revenues of $54 million resulting from risk management
        activities.
  o     Increased Depreciation and Amortization expense of $46 million due
        mainly to the amortization of regulatory assets that were
        securitized in the first quarter of 2002 and being collected in
        revenue, offset by the elimination of excess earnings expense in
        2002 under Texas Restructuring Legislation (See Note 6).
  o     Increased Taxes Other Than Income Taxes of $5 million due to
        higher local franchise taxes, offset by one-time 2001 assessments
        and decreased gross receipts tax due to deregulation.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $31 million primarily due to increased non-utility
revenues associated with energy related construction projects for third parties
offset in part by decreased interest income.

Nonoperating Expense increased $20 million primarily due to increased
non-utility expenses associated with energy related construction projects for
third parties offset in part by the extraordinary loss on reacquired debt in
2001, that was reclassified to Nonoperating Expense with the implementation of
SFAS 145 (See Note 1).

Nonoperating Income Tax Expense (Credit) increased $5 million due to higher
pre-tax nonoperating book income.

Interest Charges increased $10 million primarily due to higher levels of
outstanding debt.

Cumulative Effect of Accounting Change
--------------------------------------

This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Note 2).

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Our current ratings are
as follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               Baa1          BBB         A
          Senior Unsecured Debt              Baa2          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of TCC's rating for unsecured debt from Baa1 to Baa2 and secured debt from A3 to
Baa1. The completion of this review was a culmination of ratings action started
during 2002. With the completion of the reviews, Moody's has placed AEP and its
rated subsidiaries on stable outlook. In March 2003, S&P lowered AEP and our
senior unsecured debt and first mortgage bonds ratings from BBB+ to BBB.

Cash Flow
---------

Cash flows for the year ended December 31, 2003, 2002 and 2001 were as follows:
<TABLE>
<CAPTION>

                                                                                  2003             2002              2001
                                                                                 ------           ------            ------
                                                                                              (in thousands)
           <C>                                                                  <C>             <C>                <C>
           Cash and cash equivalents at beginning of period                      $85,420         $10,909            $14,253
                                                                                ---------       ---------          ---------
           Cash flow from (used for):
             Operating activities                                                367,223         147,493            469,920
             Investing activities                                               (134,316)       (151,502)          (194,086)
             Financing activities                                               (252,445)         78,520           (279,178)
                                                                                ---------       ---------          ---------
           Net increase (decrease) in cash and cash equivalents                  (19,538)         74,511             (3,344)
                                                                                ---------       ---------          ---------
           Cash and cash equivalents at end of period                            $65,882         $85,420            $10,909
                                                                                =========       =========          =========
</TABLE>

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

Cash flow from operating activities were $367 million primarily due to net
income as explained above, changes to Accounts Receivable, Accounts Payable and
Accrued Taxes, as well as, non-cash Depreciation and Amortization partially
offset by the non-cash Texas Wholesale Clawback regulatory asset recorded in
2003.

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

Investing expenditures in 2003 were $134 million due mostly to construction
expenditures focused on improved service reliability projects for transmission
and distribution systems.

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

We obtained the additional funds needed for financing activities through new
borrowings of $962 million in 2003. Current year debt proceeds replaced both
short and long-term debt.

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

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

<TABLE>
<CAPTION>


                                                                     Payments Due by Period
                                                                         (in thousands)

Contractual Cash Obligations               Less Than 1 year      2-3 years    4-5 years      After 5 years       Total
----------------------------               ----------------      ---------    ---------      -------------       -----

<C>                                             <C>              <C>           <C>            <C>              <C>
Long-term Debt                                  $237,651         $524,838      $121,417       $1,407,719       $2,291,625
Unconditional Purchase Obligations (a)            53,749           82,203        60,648          133,608          330,208
Capital Lease Obligations                            450              571           110                -            1,131
Noncancellable Operating Leases                    6,112           11,104         8,347           11,272           36,835
                                                ---------        ---------     ---------      -----------      -----------
  Total                                         $297,962         $618,716      $190,522       $1,552,599       $2,659,799
                                                =========        =========     =========      ===========      ===========

</TABLE>

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

In addition to the amounts disclosed in the contractual cash obligations table
above, we make additional commitments in the normal course of business. These
commitments include standby letters of credit and other commitments. Our
commitments outstanding at December 31, 2003 under these agreements are
summarized in the table below:

<TABLE>
<CAPTION>

                                                         Amount of Commitment Expiration Per Period
                                                                         (in thousands)

Other Commercial Commitments                   Less Than 1 year      2-3 years      4-5 years     After 5 years      Total
----------------------------                   ----------------      ---------      ---------     -------------      -----

<C>                                                <C>               <C>             <C>                <C>         <C>
Standby Letters of Credit                               $-            $43,000             $-            $-           $43,000
Transmission Facilities for Third Parties (a)       22,811             74,716         30,720             -           128,247
                                                   --------          ---------       --------           ---         ---------
 Total                                             $22,811           $117,716        $30,720            $-          $171,247
                                                   ========          =========       ========           ===         =========

</TABLE>

 (a) As construction agent for third party owners of transmission facilities, we
     have committed by contract terms to complete construction by dates
     specified in the contracts.

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>


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

        Domestic Power
        --------------
        <C>                                                                      <C>
        Beginning Balance December 31, 2002                                      $5,414
        (Gain) Loss from Contracts  Realized/Settled During the Period (a)       (2,033)
        Fair Value of New Contracts When Entered Into During the Period (b)           -
        Net Option Premiums Paid/(Received) (c)                                    (130)
        Change in Fair Value Due to Valuation Methodology Changes                     -
        Effect of  EITF 98-10 Rescission (d)                                        187
        Changes in Fair Value of Risk Management Contracts (e)                    8,504
        Changes in Fair Value of Risk Management Contracts
         Allocated to Regulated Jurisdictions (f)                                     -
                                                                                 -------
        Total MTM Risk Management Contract Net Assets,
         Excluding Cash Flow Hedges                                              11,942
        Net Cash Flow Hedge Contracts (g)                                        (2,812)
                                                                                 -------
        Ending Balance December 31, 2003                                         $9,130
                                                                                 =======
</TABLE>


     (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
         includes realized gains from risk management contracts and related
         derivatives that settled during 2003 that were entered into prior
         to 2003.
     (b) The "Fair Value of New Contracts When Entered Into During the
         Period" represents the fair value of long-term contracts entered
         into with customers during 2003. The fair value is calculated as of
         the execution of the contract. Most of the fair value comes from
         longer term fixed price contracts with customers that seek to limit
         their risk against fluctuating energy prices. The contract prices
         are valued against market curves associated with the delivery
         location.
     (c) "Net Option Premiums Paid/(Received)" reflects the net option
         premiums paid/(received) as they relate to unexercised and
         unexpired option contracts that were entered into in 2003.
     (d) See Note 2 "New Accounting Pronouncements Extraordinary Items and
         Cumulative Effect of Accounting Changes."
     (e) "Changes in Fair Value of Risk Management Contracts" represents the
         fair value change in the risk management portfolio due to market
         fluctuations during the current period. Market fluctuations are
         attributable to various factors such as supply/demand, weather,
         etc.
     (f) "Change in Fair Value of Risk Management Contracts Allocated to
         Regulated Jurisdictions" relates to the net gains (losses) of those
         contracts that are not reflected in the Consolidated Statements of
         Income. These net gains (losses) are recorded as regulatory
         liabilities/assets for those subsidiaries that operate in regulated
         jurisdictions.
     (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
         Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>


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

                                                                                                               After
                                                      2004        2005        2006        2007       2008      2008      Total (c)
                                                      ----        ----        ----        ----       ----      ----      ---------
                                                                      (in thousands)
     <C>                                             <C>         <C>          <C>         <C>         <C>     <C>         <C>
     Prices Actively Quoted - Exchange
      Traded Contracts                                 $238        $(99)        $9         $61          $-        $-         $209
     Prices Provided by Other External Sources
      - OTC Broker Quotes (a)                         1,752       1,570        576         363         208         -        4,469
     Prices Based on Models and Other Valuation
      Methods (b)                                     4,346         511        114         237         497     1,559        7,264
                                                     ------      -------      -----       -----       -----   -------     --------

     Total                                           $6,336      $1,982       $699        $661        $705    $1,559      $11,942
                                                     =======     =======      =====       =====       =====   =======     ========
</TABLE>


     (a)"Prices Provided by Other External Sources - OTC Broker Quotes" reflects
        information obtained from over-the-counter brokers, industry services,
        or multiple-party on-line platforms.
     (b)"Prices Based on Models and Other Valuation Methods" is in absence of
        pricing information from external sources, modeled information is
        derived using valuation models developed by the reporting entity,
        reflecting when appropriate, option pricing theory, discounted cash
        flow concepts, valuation adjustments, etc. and may require projection
        of prices for underlying commodities beyond the period that prices
        are available from third-party sources. In addition, where external
        pricing information or market liquidity are limited, such valuations
        are classified as modeled. The determination of the point at which a
        market is no longer liquid for placing it in the Modeled category
        varies by market.
     (c)Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

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

                                                              Domestic
                                                                Power
                                                              --------
                                                            (in thousands)
         Beginning Balance December 31, 2002                     $(36)
         Changes in Fair Value (a)                              (1,931)
         Reclassifications from AOCI to Net Income (b)             139
                                                               --------
         Ending Balance December 31, 2003                      $(1,828)
                                                               ========

       (a) "Changes in Fair Value" shows changes in the fair value of
           derivatives designated as hedging instruments in cash flow hedges
           during the reporting period not yet reclassified into net income,
           pending the hedged item's affecting net income. Amounts are reported
           net of related income taxes.
       (b) "Reclassifications from AOCI to Net Income" represents gains or
            losses from derivatives used as hedging instruments in cash flow
            hedges that were reclassified into net income during the reporting
            period. Amounts are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,413 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
          End   High   Average   Low             End   High   Average   Low
         -----  ----   -------  -----           -----  ----   -------  -----
         $189   $733     $307    $73             $115  $353    $126     $26


VaR Associated with Debt Outstanding
------------------------------------
The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $206 million and $65 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>



                                               AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                  CONSOLIDATED STATEMENTS OF INCOME
                                         For the Years Ended December 31, 2003, 2002 and 2001

                                                                        2003                  2002                 2001
                                                                        ----                  ----                 ----
                                                                                         (in thousands)
                 OPERATING REVENUES
-----------------------------------------------------
<C>                                                                  <C>                    <C>                  <C>
Electric Generation, Transmission and Distribution                   $1,593,943              $682,049            $1,697,075
Sales to AEP Affiliates                                                 153,568             1,008,444                41,762
                                                                     -----------            ----------           -----------
TOTAL                                                                 1,747,511             1,690,493             1,738,837
                                                                     -----------            ----------           -----------

                 OPERATING EXPENSES
-----------------------------------------------------
Fuel for Electric Generation                                             89,389                88,488               492,057
Fuel from Affiliates for Electric Generation                            195,527               157,346                     -
Purchased Electricity for Resale                                        373,388               211,358               127,816
Purchased Electricity from AEP Affiliates                                19,097                23,406                58,641
Other Operation                                                         297,878               304,094               321,227
Maintenance                                                              71,361                63,392                71,212
Depreciation and Amortization                                           189,130               214,162               168,341
Taxes Other Than Income Taxes                                            92,109                95,500                90,916
Income Taxes                                                             98,092               139,014               112,896
                                                                     -----------            ----------           -----------
TOTAL                                                                 1,425,971             1,296,760             1,443,106
                                                                     -----------            ----------           -----------

OPERATING INCOME                                                        321,540               393,733               295,731

Nonoperating Income                                                      54,172                53,141                22,552
Nonoperating Expenses                                                    17,273                41,910                21,486
Nonoperating Income Tax Expense (Credit)                                  7,080                 3,152                (1,749)
Interest Charges                                                        133,812               125,871               116,268
                                                                     -----------            ----------           -----------

Income Before Cumulative Effect of Accounting Change                    217,547               275,941               182,278
Cumulative Effect of Accounting Change (Net of Tax)                         122                     -                     -
                                                                     -----------            ----------           -----------

NET INCOME                                                              217,669               275,941               182,278

Gain on Reacquired Preferred Stock                                            -                     4                     -
Preferred Stock Dividend Requirements                                       241                   241                   242
                                                                     -----------            ----------           -----------

EARNINGS APPLICABLE TO COMMON STOCK                                    $217,428              $275,704              $182,036
                                                                     ===========            ==========           ===========
</TABLE>


The common stock of TCC is owned by a wholly-owned subsidiary of AEP.

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


<PAGE>
<TABLE>
<CAPTION>


                                              AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                    CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                  EQUITY AND COMPREHENSIVE INCOME
                                       For the Years Ended December 31, 2003, 2002 and 2001
                                                      (in thousands)


                                                                                                 Accumulated Other
                                                 Common          Paid-in        Retained           Comprehensive
                                                  Stock          Capital        Earnings           Income (Loss)        Total
                                                 -------         -------        --------         -----------------      -----

<C>                                              <C>             <C>            <C>                  <C>             <C>
DECEMBER 31, 2000                                $168,888        $405,015         $792,219                 $-        $1,366,122

Common Stock Dividends Declared                                                   (148,057)                            (148,057)
Preferred Stock Dividends Declared                                                    (242)                                (242)
Other                                                                                   (1)                                  (1)
                                                                                                                     -----------
TOTAL                                                                                                                 1,217,822
                                                                                                                     -----------

       COMPREHENSIVE INCOME
-------------------------------------
NET INCOME                                                                         182,278                              182,278
                                                                                                                     -----------
TOTAL COMPREHENSIVE INCOME                                                                                              182,278
                                                  --------       ---------      -----------         ----------       -----------

DECEMBER 31, 2001                                $168,888        $405,015         $826,197                 $-        $1,400,100

Redemption of Common Stock                       (113,596)       (272,409)                                             (386,005)
Common Stock Dividends                                                            (115,505)                            (115,505)
Preferred Stock Dividends                                                             (241)                                (241)
Gain on Reacquired Preferred Stock                                                       4                                    4
                                                                                                                     -----------
TOTAL                                                                                                                   898,353
                                                                                                                     -----------

       COMPREHENSIVE INCOME
-------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                    (36)              (36)
   Minimum Pension Liability                                                                          (73,124)          (73,124)
NET INCOME                                                                         275,941                              275,941
                                                                                                                     -----------
TOTAL COMPREHENSIVE INCOME                                                                                              202,781
                                                  --------       ---------      -----------         ----------       -----------

DECEMBER 31, 2002                                 $55,292        $132,606         $986,396           $(73,160)       $1,101,134

Common Stock Dividends                                                            (120,801)                            (120,801)
Preferred Stock Dividends                                                             (241)                                (241)
                                                                                                                     -----------
TOTAL                                                                                                                   980,092
                                                                                                                     -----------

       COMPREHENSIVE INCOME
-------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                 (1,792)           (1,792)
   Minimum Pension Liability                                                                           13,080            13,080
NET INCOME                                                                         217,669                              217,669
                                                                                                                     -----------
TOTAL COMPREHENSIVE INCOME                                                                                              228,957
                                                  --------       ---------      -----------         ----------       -----------

DECEMBER 31, 2003                                 $55,292        $132,606       $1,083,023           $(61,872)       $1,209,049
                                                  ========       =========      ===========          =========       ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>




                                                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                         CONSOLIDATED BALANCE SHEETS
                                                                    ASSETS
                                                         December 31, 2003 and 2002
                                                                                                     2003                   2002
                                                                                                     ----                   ----
                                                                                                           (in thousands)
                ELECTRIC UTILITY PLANT
----------------------------------------------------------
<C>                                                                                              <C>                    <C>
Production                                                                                               $-                     $-
Transmission                                                                                        767,970                682,780
Distribution                                                                                      1,376,761              1,296,731
General                                                                                             221,354                202,418
Construction Work in Progress                                                                        58,953                152,865
                                                                                                 -----------            -----------
TOTAL                                                                                             2,425,038              2,334,794
Accumulated Depreciation and Amortization                                                           695,359                662,345
                                                                                                 -----------            -----------
TOTAL - NET                                                                                       1,729,679              1,672,449
                                                                                                 -----------            -----------

              OTHER PROPERTY AND INVESTMENTS
----------------------------------------------------------
Non-Utility Property, Net                                                                             1,302                  2,385
Other Investments                                                                                     4,639                    354
                                                                                                 -----------            -----------
TOTAL                                                                                                 5,941                  2,739
                                                                                                 -----------            -----------

                      CURRENT ASSETS
----------------------------------------------------------
Cash and Cash Equivalents                                                                            65,882                 85,420
Advances to Affiliates                                                                               60,699                      -
Accounts Receivable:
   Customers                                                                                        146,630                113,014
   Affiliated Companies                                                                              78,484                121,324
   Accrued Unbilled Revenues                                                                         23,077                 27,150
   Miscellaneous                                                                                          -                    529
   Allowance for Uncollectible Accounts                                                              (1,710)                  (346)
Materials and Supplies                                                                               11,708                 14,376
Risk Management Assets                                                                               22,051                 22,493
Margin Deposits                                                                                       3,230                    121
Prepayments and Other Current Assets                                                                  6,770                  2,012
                                                                                                 -----------            -----------
TOTAL                                                                                               416,821                386,093
                                                                                                 -----------            -----------

             DEFERRED DEBITS AND OTHER ASSETS
----------------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                      3,249                  9,950
  Wholesale Capacity Auction True-up                                                                480,000                262,000
  Unamortized Loss on Reacquired Debt                                                                 9,086                  8,661
  Designated for Securitization                                                                   1,253,289                330,960
  Deferred Debt - Restructuring                                                                      12,015                 13,324
  Other                                                                                             133,913                170,101
Securitized Transition Assets                                                                       689,399                734,591
Long-term Risk Management Assets                                                                      7,627                  4,392
Deferred Charges                                                                                     55,554                 43,890
                                                                                                 -----------            -----------
TOTAL                                                                                             2,644,132              1,577,869
                                                                                                 -----------            -----------

Assets Held for Sale - Texas Generation Plants                                                    1,028,134              1,814,810
                                                                                                 -----------            -----------

TOTAL ASSETS                                                                                     $5,824,707             $5,453,960
                                                                                                 ===========            ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                 AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                      CONSOLIDATED BALANCE SHEETS
                                                     CAPITALIZATION AND LIABILITIES
                                                       December 31, 2003 and 2002
                                                                                                      2003                2002
                                                                                                      ----                ----
                                                                                                           (in thousands)

                      CAPITALIZATION
----------------------------------------------------------
<C>                                                                                               <C>                 <C>
Common Shareholder's Equity:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
    Outstanding - 2,211,678 Shares                                                                   $55,292             $55,292
    Paid-in Capital                                                                                  132,606             132,606
    Retained Earnings                                                                              1,083,023             986,396
    Accumulated Other Comprehensive Income (Loss)                                                    (61,872)            (73,160)
                                                                                                  -----------         -----------
Total Common Shareholder's Equity                                                                  1,209,049           1,101,134
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                         5,940               5,942
                                                                                                  -----------         -----------
Total Shareholder's Equity                                                                         1,214,989           1,107,076
CPL - Obligated Mandatorily Redeemable Preferred Securities of
   Subsidiary Trust Holding Solely Junior Subordinated Debentures of TCC                                   -             136,250
Long-term Debt                                                                                     2,053,974           1,209,434
                                                                                                  -----------         -----------
TOTAL                                                                                              3,268,963           2,452,760
                                                                                                  -----------         -----------

                      CURRENT LIABILITIES
----------------------------------------------------------
Short-term Debt - Affiliates                                                                               -             650,000
Long-term Debt Due Within One Year                                                                   237,651             229,131
Advances from Affiliates                                                                                   -             126,711
Accounts Payable:
  General                                                                                             90,004              72,199
  Affiliated Companies                                                                                74,209              36,242
Customer Deposits                                                                                      1,517                 666
Taxes Accrued                                                                                         67,018              24,791
Interest Accrued                                                                                      43,196              51,205
Risk Management Liabilities                                                                           17,888              19,811
Obligation Under Capital Leases                                                                          407                   -
Other                                                                                                 23,248              36,698
                                                                                                  -----------         -----------
TOTAL                                                                                                555,138           1,247,454
                                                                                                  -----------         -----------

             DEFERRED CREDITS AND OTHER LIABILITIES
----------------------------------------------------------
Deferred Income Taxes                                                                              1,244,912           1,261,252
Long-term Risk Management Liabilities                                                                  2,660               1,713
Regulatory Liabilities:
  Asset Removal Costs                                                                                 95,415                   -
  Deferred Investment Tax Credits                                                                    112,479             117,686
  Deferred Fuel Costs                                                                                 69,026              69,026
  Retail Clawback                                                                                     45,527              51,926
  Other                                                                                               56,984              76,547
Obligation Under Capital Leases                                                                          636                   -
Deferred Credits and Other                                                                           144,833             166,711
                                                                                                  -----------         -----------
TOTAL                                                                                              1,772,472           1,744,861
                                                                                                  -----------         -----------

Liabilities Held for Sale - Texas Generation Plants                                                  228,134               8,885
                                                                                                  -----------         -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                              $5,824,707          $5,453,960
                                                                                                  ===========         ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>

                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                  For the Years Ended 2003, 2002 and 2001

                                                                                    2003                2002              2001
                                                                                    ----                ----              ----
                                                                                                  (in thousands)
                   OPERATING ACTIVITIES
-----------------------------------------------------------
<C>                                                                                <C>                <C>               <C>
Net Income                                                                         $217,669           $275,941          $182,278
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                    189,130            214,162           168,341
   Deferred Income Taxes                                                             19,393            113,655           (72,568)
   Deferred Investment Tax Credits                                                   (5,207)            (5,206)           (5,208)
   Cumulative Effect of Accounting Change                                              (122)                 -                 -
   Mark-to-Market of Risk Management Contracts                                       (6,341)            (1,558)          (12,048)
   Wholesale Capacity Auction True-up                                              (218,000)          (262,000)                -
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                          15,190           (217,149)           52,862
   Fuel, Materials and Supplies                                                      15,850             (4,899)          (18,215)
   Interest Accrued                                                                  (8,009)            27,490            (2,502)
   Accounts Payable                                                                  55,772             (6,167)          (55,311)
   Taxes Accrued                                                                     42,227            (58,721)           27,986
Fuel Recovery                                                                             -             16,455           179,866
Change in Other Assets                                                               30,341               (534)           13,276
Change in Other Liabilities                                                          19,330             56,024            11,163
                                                                                   ---------          ---------         ---------
Net Cash Flows From Operating Activities                                            367,223            147,493           469,920
                                                                                   ---------          ---------         ---------

                     INVESTING ACTIVITIES
-----------------------------------------------------------
Construction Expenditures                                                          (141,771)          (151,645)         (193,732)
Other                                                                                 7,455                143              (354)
                                                                                   ---------          ---------         ---------
Net Cash Flows Used For Investing Activities                                       (134,316)          (151,502)         (194,086)
                                                                                   ---------          ---------         ---------

                     FINANCING ACTIVITIES
-----------------------------------------------------------
Change in Short-term Debt - Affiliates                                             (650,000)           650,000                 -
Issuance of Long-term Debt                                                          953,136            797,335           260,162
Retirement of Long-term Debt                                                       (247,127)          (639,492)         (475,606)
Change in Advances to/from Affiliates, Net                                         (187,410)          (227,566)           84,565
Retirement of Common Stock                                                                -           (386,005)                -
Retirement of Preferred Stock                                                            (2)                (6)                -
Dividends Paid on Common Stock                                                     (120,801)          (115,505)         (148,057)
Dividends Paid on Cumulative Preferred Stock                                           (241)              (241)             (242)
                                                                                   ---------          ---------         ---------
Net Cash Flows From (Used For) Financing Activities                                (252,445)            78,520          (279,178)
                                                                                   ---------          ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                (19,538)            74,511            (3,344)
Cash and Cash Equivalents at Beginning of Period                                     85,420             10,909            14,253
                                                                                   ---------          ---------         ---------
Cash and Cash Equivalents at End of Period                                          $65,882            $85,420           $10,909
                                                                                   =========          =========         =========
</TABLE>


SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $129,491,000, $93,120,000
and $109,835,000 and for income taxes was $49,630,000, $95,600,000 and
$161,529,000 in 2003, 2002 and 2001, respectively.

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

<PAGE>
<TABLE>
<CAPTION>




                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                    CONSOLIDATED STATEMENTS OF CAPITALIZATION
                           December 31, 2003 and 2002

                                                                                     2003            2002
                                                                                     ----            -----
                                                                                         (in thousands)

<C>                                                                               <C>              <C>
TOTAL COMMON SHAREHOLDER'S EQUITY (a)                                             $1,209,049       $1,101,134
                                                                                  -----------      -----------

PREFERRED STOCK - 3,035,000 authorized shares, $100 par value

Not Subject to Mandatory Redemption:

                                                               Shares
          Call Price         Number of Shares Redeemed       Outstanding
Series   December 31,        Year Ended December 31,         December 31,
------   ------------      ---------------------------       ------------
             2003          2003       2002        2001          2003
             ----          ----       ----        ----          ----

4.00%      $105.75          11         100           -          41,927                 4,192            4,194
4.20%       103.75           -           -           -          17,476                 1,748            1,748
                                                                                  -----------      -----------
Total Preferred Stock                                                                  5,940            5,942
                                                                                  -----------      -----------

TRUST PREFERRED SECURITIES:
TCC-Obligated, Mandatorily Redeemable Preferred
  Securities of Subsidiary Trust Holding Solely
  Junior Subordinated Debentures of TCC, 8.00%,
  due April 30, 2037 (b)                                                                   -          136,250
                                                                                  -----------      -----------

LONG-TERM (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                 117,939          152,353
Securitization Bonds (a)                                                             745,680          796,635
Note Payable to Trust (b)                                                            140,889                -
Installment Purchase Contracts                                                       489,585          489,577
Senior Unsecured Notes                                                               797,532                -
Less Portion Due Within One Year                                                    (237,651)        (229,131)
                                                                                  -----------      -----------

Long-term Debt Excluding Portion Due Within One Year                               2,053,974        1,209,434
                                                                                  -----------      -----------

TOTAL CAPITALIZATION                                                              $3,268,963       $2,452,760
                                                                                  ===========      ===========

</TABLE>

(a) In February 2002, TCC issued securitization bonds. $386 million of the
    proceeds was used to retire 4,543,857 shares of common stock.
(b) See Note 16 for discussion of Notes Payable to Trust.

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


<PAGE>
<TABLE>
<CAPTION>



                    AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                                          2003                  2002
                                                          ----                  ----
            %Rate            Due                                (in thousands)
            -----            ---
            <C>              <C>                        <C>                   <C>
            6.875            2003 - February 1                $-               $16,418
            7.25             2004 - October 1             27,400                27,400
            7-1/8            2008 - February 1            18,581                18,581
            7.50             2023 - April 1                    -                17,996
            6-5/8            2005 - July 1                71,958                71,958
                                                        ---------             ---------
            Total                                       $117,939              $152,353
                                                        =========             =========

</TABLE>

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Securitization Bonds outstanding were as follows:

<TABLE>
<CAPTION>


                                       Final                               2003                  2002
                                      Payment        Maturity              ----                  ----
                   %Rate               Date            Date                        (in thousands)
                   -----           -----------     --------------
                   <C>                 <C>          <C>                   <C>                  <C>
                   3.54                1/15/2005    1/15/2007             $77,937              $128,950
                   5.01                1/15/2008    1/15/2010             154,507               154,507
                   5.56                1/15/2010    1/15/2012             107,094               107,094
                   5.96                7/15/2013    7/15/2015             214,927               214,927
                   6.25                1/15/2016    1/15/2017             191,857               191,857
                   Unamortized Discount                                      (642)                 (700)
                                                                         ---------             ---------
                   Total                                                 $745,680              $796,635
                                                                         =========             =========
</TABLE>

In February 2002, CPL Transition Funding LLC, a special purpose subsidiary of
TCC, issued $797 million of Securitization Bonds, Series 2002-1. The
Securitization Bonds mature at different times through 2017 and have a weighted
average interest rate of 5.4 percent.

Senior Unsecured Notes outstanding were as follows:

<TABLE>
<CAPTION>

                                                                    2003              2002
                                                                    ----              ----
                   %Rate            Due                                  (in thousands)
                   -----            ---
                   <C>              <C>                           <C>                   <C>
                   5.50             2013 - February 15            $275,000              $-
                   6.65             2033 - February 15             275,000               -
                   3.00             2005 - February 15             150,000               -
                   (a)              2005 - February 15             100,000               -
                   Unamortized Discount                             (2,468)              -
                                                                  ---------             ---
                   Total                                          $797,532              $-
                                                                  =========             ===

</TABLE>

                   (a)   A floating interest rate is determined quarterly. The
                         rate on December 31, 2003 was 2.43%.





Installment Purchase Contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

<TABLE>
<CAPTION>

                                                                             2003             2002
                                                                             ----             ----
                 %Rate              Due                                           (in thousands)
                 -----              ---
Matagorda County Navigation District, Texas:
                 <C>                <C>                                     <C>             <C>
                 6.00               2028 - July 1                           $120,265        $120,265
                 6-1/8              2030 - May 1                              60,000          60,000
                 3.75               2003 - November 1                              -         111,700
                 2.15               2030 - May 1 (a)                         111,700               -
                 4.00               2030 - May 1                                   -          50,000
                 4.55               2029 - November 1 (b)                    100,635         100,635
                 2.35               2030 - May 1 (a)                          50,000               -

Guadalupe-Blanco River Authority District, Texas:
                                    2015 - November 1 (c)                     40,890          40,890

Red River Authority of Texas:
                 6.00               2020 - June 1                              6,330           6,330
                 Unamortized Discount                                           (235)           (243)
                                                                            ---------       ---------
                 Total                                                      $489,585        $489,577
                                                                            =========       =========
</TABLE>


(a) Installment Purchase Contract provides for bonds to be tendered in 2004 for
    2.15% and 2.35% series. Therefore, these installment purchase contracts
    have been classified for payment in 2004.
(b) Installment Purchase Contract provides for bonds to be tendered in 2006 for
    4.55% series. Therefore, this installment purchase contract has been
    classified for payment in 2006.
(c) A floating interest rate is determined daily. The rate on December 31, 2003
    was 1.30%.

Under the terms of the installment purchase contracts, TCC is required to pay
amounts sufficient to enable the payment of interest on and the principal (at
stated maturities and upon mandatory redemptions) of related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants. Interest payments range from monthly to semi-annually.

Notes Payable to Trust was outstanding as follows:

<TABLE>
<CAPTION>

                                                                            2003             2002
                                                                            ----             ----
                %Rate          Due                                             (in thousands)
                -----          ---
                <C>            <C>                                         <C>                <C>
                8.00           2037 - April 30                             $140,889           $-
                                                                           =========          ===

</TABLE>

                See Note 16 for discussion of Notes Payable to Trust.

At December 31, 2003, future annual long-term debt payments are as follows:

                                                                Amount
                                                                ------
                                                            (in thousands)
                2004                                           $237,651
                2005                                            371,938
                2006                                            152,900
                2007                                             52,729
                2008                                             68,688
                Later Years                                   1,411,064
                                                             -----------
                Total Principal Amount                        2,294,970
                Unamortized Discount                             (3,345)
                                                             -----------
                Total                                        $2,291,625
                                                             ===========


<PAGE>
<TABLE>
<CAPTION>

                                     AEP TEXAS CENTRAL COMPANY AND SUBSIDIARY
                                INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to TCC's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to TCC. The footnotes begin on page L-1.

                                                                                                                      Footnote
                                                                                                                      Reference
                                                                                                                      ---------

<C>                                                                                                                   <C>
Organization and Summary of Significant Accounting Policies                                                           Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                        Note 2

Rate Matters                                                                                                          Note 4

Effects of Regulation                                                                                                 Note 5

Customer Choice and Industry Restructuring                                                                            Note 6

Commitments and Contingencies                                                                                         Note 7

Guarantees                                                                                                            Note 8

Sustained Earnings Improvement Initiative                                                                             Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                Note 10

Benefit Plans                                                                                                         Note 11

Business Segments                                                                                                     Note 12

Derivatives, Hedging and Financial Instruments                                                                        Note 13

Income Taxes                                                                                                          Note 14

Leases                                                                                                                Note 15

Financing Activities                                                                                                  Note 16

Related Party Transactions                                                                                            Note 17

Jointly Owned Electric Utility Plant                                                                                  Note 18

Unaudited Quarterly Financial Information                                                                             Note 19

Subsequent Events (Unaudited)                                                                                         Note 20


</TABLE>


<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors
of AEP Texas Central Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of AEP Texas Central Company and subsidiary as of
December 31, 2003 and 2002, and the related consolidated statements of income,
changes in common shareholder's equity and comprehensive income and cash flows
for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of AEP Texas Central Company and
subsidiary as of December 31, 2003 and 2002, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2003 in conformity with accounting principles generally accepted in the United
States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective
January 1, 2003.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities," effective July 1,
2003.

/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004


<PAGE>

















                             AEP TEXAS NORTH COMPANY







<PAGE>
<TABLE>
<CAPTION>


                                                                   AEP TEXAS NORTH COMPANY
                                                                   SELECTED FINANCIAL DATA

                                               2003                2002              2001               2000               1999
                                               ----                ----              ----               ----               ----
                                                                                 (in thousands)
<C>                                          <C>               <C>               <C>                <C>                <C>
        INCOME STATEMENTS DATA
---------------------------------------
Operating Revenues                             $465,946          $450,740          $556,458           $571,064           $445,709
Operating Expenses                              397,919           442,869           523,068            518,723            391,910
                                             -----------       -----------       -----------        -----------        -----------
Operating Income                                 68,027             7,871            33,390             52,341             53,799
Nonoperating Items, Net                           9,685              (703)            2,195             (1,675)             2,488
Interest Charges                                 22,049            20,845            23,275             23,216             24,420
                                             -----------       -----------       -----------        -----------        -----------
Income (Loss) Before Extraordinary Item
 and Cumulative Effect of Accounting Change      55,663           (13,677)           12,310             27,450             31,867
                                             -----------       -----------       -----------        -----------        -----------
Extraordinary Loss                                 (177)                -                 -                  -             (5,461)
Cumulative Effect of Accounting Change            3,071                 -                 -                  -                  -
                                             -----------       -----------       -----------        -----------        -----------
Net Income (Loss)                                58,557           (13,677)           12,310             27,450             26,406
Gain on Reacquired Preferred Stock                    3                 -                 -                  -                  -
Preferred Stock Dividend Requirements               104               104               104                104                104
                                             -----------       -----------       -----------        -----------        -----------
Earnings (Loss) Applicable to Common Stock      $58,456          $(13,781)          $12,206            $27,346           $ 26,302
                                             ===========       ===========       ===========        ===========        ===========

          BALANCE SHEETS DATA
---------------------------------------
Electric Utility Plant                       $1,233,427        $1,201,747        $1,260,872         $1,229,339         $1,182,544
Accumulated Depreciation and Amortization       460,513           446,818           475,036            447,802            446,282
                                             -----------       -----------       -----------        -----------        -----------
Net Electric Utility Plant                     $772,914          $754,929          $785,836           $781,537           $736,262
                                             ===========       ===========       ===========        ===========        ===========

TOTAL ASSETS                                 $1,009,509          $952,149          $936,001         $1,154,743           $910,770
                                             ===========       ===========       ===========        ===========        ===========

Common Stock and
 Paid-in Capital                               $139,565          $139,565          $139,565           $139,565           $139,565
Retained Earnings                               125,428            71,942           105,970            122,588            113,242
Accumulated Other
 Comprehensive Income (Loss)                    (26,718)          (30,763)                -                  -                  -
                                             -----------       -----------       -----------        -----------        -----------
Total Common Shareholder's Equity              $238,275          $180,744          $245,535           $262,153           $252,807
                                             ===========       ===========       ===========        ===========        ===========

Cumulative Preferred Stock
 Not Subject to Mandatory Redemption             $2,357            $2,367            $2,367             $2,367             $2,367
                                             ===========       ===========       ===========        ===========        ===========
Long-term Debt (a)                             $356,754          $132,500          $255,967           $255,843           $303,686
                                             ===========       ===========       ===========        ===========        ===========

Obligations Under Capital Leases (a)               $473                $-                $-                 $-                 $-
                                             ===========       ===========       ===========        ===========        ===========

TOTAL CAPITALIZATION AND LIABILITIES         $1,009,509          $952,149          $936,001         $1,154,743           $910,770
                                             ===========       ===========       ===========        ===========        ===========
(a) Including portion due within one year.

</TABLE>

<PAGE>


                             AEP TEXAS NORTH COMPANY
               MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
               --------------------------------------------------------

AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation and purchase of electric
power, and the subsequent sale, transmission and distribution of that power in
west and central Texas. As a power pool member with AEP West companies, we share
in the revenues and expenses of the power pool's sales to neighboring utilities
and power marketers. TNC also sells electric power at wholesale to other
utilities, municipalities, rural electric cooperatives and retail electric
providers (REPs) in Texas.

Power pool members are compensated for energy delivered to other members based
upon the delivering members' incremental cost plus a portion of the savings
realized by the purchasing member that avoids the use of more costly
alternatives. The revenue and costs for sales to neighboring utilities and power
marketers made by AEPSC on behalf of the AEP West companies are shared among the
members based upon the relative magnitude of the energy each member provides to
make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

Net Income increased $72 million primarily due to a 2002 $43 million write-down
($28 million after tax) of gas power plants and increased risk management
margins of $20 million in 2003. Transactions with ERCOT also significantly
increased income in 2003.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
we sell our generation to the REPs and other market participants and provide
transmission and distribution services to retail customers of the REPs in our
service territory. As a result of the provision of retail electric service by
REPs effective January 1, 2002, we no longer supply electricity directly to
retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in our sales as further described below.

In December 2002, AEP sold Mutual Energy WTU to an unrelated third party, who
assumed the obligations of the affiliated REP, including the provision of
price-to-beat rates under the Texas Restructuring Legislation. Prior to the
sale, during 2002, sales to Mutual Energy WTU were classified as Sales to AEP
Affiliates. Subsequent to the sale, energy transactions and delivery charges
with Mutual Energy WTU are classified as Electric Generation, Transmission and
Distribution.

Operating Income
----------------

Operating Income increased by $60 million primarily due to:

  o     The 2002 asset impairment of $43 million. See Note 10
        "Acquisitions, Dispositions, Impairments, Assets Held for Sale and
        Assets Held and Used."
  o     Increased Reliability Must Run (RMR) revenues from ERCOT of $44
        million which include both fuel recovery and a fixed cost
        component of $13 million (see "Texas Plants" in Note 10 for
        discussion of RMR facilities).
  o     Increased revenues from risk management activities of $10 million.
  o     Increased  revenues  from ERCOT of $22  million or 91% for  various
        services,  due mainly to prior years adjustments made by ERCOT.
  o     Decreased fuel and purchased power on a net basis of $9 million.
        KWH generation decreased 27% mainly due to mothballing of plants
        while the per unit cost of fuel increased 14% due primarily to
        higher natural gas prices. KWH purchased declined 9%, but the
        average cost increased 2%.
  o     Reduced Other Operation expenses of $20 million due to several
        factors including $8 million of customer service, outside
        services, other administrative related expenses, ERCOT
        transmission charges of $4 million, distribution expenses of $2
        million, and a $2 million write-down of material and supplies to
        market value related to the deactivation of several power plants
        in 2002.
  o     Decreased  Maintenance  expense of $3 million due primarily to the
        deactivation of several power plants in 2002 (See Note 10).
  o     Reduced Depreciation and Amortization of $7 million due to the
        2002 impairment of several power plants resulting in approximately
        $4 million less depreciation expense. An additional decrease of $3
        million relates to adjustments to prior years' excess earnings
        accruals under the Texas restructuring legislation due to a
        favorable Appeals Court ruling (See Note 6).
  o     Decrease of Taxes Other Than Income Taxes of $2 million is due to
        reduced  gross  receipts tax as a result of the sale of the Texas REPs.

The increase in Operating Income was partially offset by:

  o     Decreased system sales, including those to REP's, of $7 million
        due mainly to both lower KWH sales of 17% and a decrease in the
        overall average price per KWH.
  o     The 2002 ICR adjustments decreased revenue by approximately $24
        million in 2003. This decrease was partially offset by a reduction
        in purchased power, due to these adjustments of $5 million.
  o     Decreased delivery revenues of $5 million, due partly to decreased
        cooling and heating degree-days.
  o     Reduced wholesale revenues of $8 million due to the loss of several
        large wholesale customers whose contracts expired and were not renewed.
  o     Increased provision for rate refunds of $20 million in 2003 due
        mainly to the final Texas fuel reconciliation (see "TNC Fuel
        Reconciliation" in Note 4).
  o     Increased Federal Income Taxes of $39 million due to the increase in
        pre-tax operating income.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $15 million primarily due to a $10 million
increase in net revenue from risk management activities, while revenue from
third party non-utility energy related construction projects increased $5
million.

Extraordinary (Loss) - (Net of Tax)
-----------------------------------

Extraordinary loss resulted from the cessation of SFAS 71 accounting for
wholesale generation assets due to the FERC settlement case (see Note 2).

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes is due to a one-time after-tax
impact of adopting SFAS 143 (see Note 2).

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Our current ratings are
as follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A
          Senior Unsecured Debt              Baa1          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. TNC had its secured debt downgraded from A2 to
A3 and unsecured debt downgraded from A3 to Baa1. The completion of this review
was a culmination of ratings action started during 2002. In March 2003, S&P
lowered AEP and our senior unsecured debt and mortgage bonds ratings from BBB+
to BBB.

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

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

<TABLE>
<CAPTION>

                                                                    Payments Due by Period
                                                                        (in thousands)

Contractual Cash Obligations                Less Than 1 year    2-3 years      4-5 years      After 5 years    Total
----------------------------                ----------------    ---------      ---------      -------------    -----

<C>                                              <C>              <C>           <C>             <C>           <C>
Long-term Debt                                   $42,505          $37,609        $8,151         $268,489      $356,754
Unconditional Purchase Obligations (a)            51,172           82,478        57,456          201,096       392,202
Capital Lease Obligations                            223              275             9                2           509
Noncancellable Operating Leases                    1,964            3,791         2,770            4,981        13,506
                                                 --------        ---------      --------        ---------     ---------
  Total                                          $95,864         $124,153       $68,386         $474,568      $762,971
                                                 ========        =========      ========        =========     =========

</TABLE>

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

In addition to the amounts disclosed in the contractual cash obligations table
above, we make additional commitments in the normal course of business. These
commitments include standby letters of credit and other commitments. Our
commitments outstanding at December 31, 2003 under these agreements are
summarized in the table below:

<TABLE>
<CAPTION>

                                                         Amount of Commitment Expiration Per Period
                                                                         (in thousands)

Other Commercial Commitments                    Less Than 1 year    2-3 years     4-5 years     After 5 years     Total
----------------------------                    ----------------    ---------     ---------     -------------     -----

<C>                                                <C>                <C>              <C>              <C>       <C>
Transmission Facilities for Third Parties (a)      $75,658            $15,621          $-               $-        $91,279

</TABLE>

 (a)  As construction agent for third party owners of transmission facilities,
      we have committed by contract terms to complete construction by dates
      specified in the contracts.

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effects.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

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

        Domestic Power
        --------------
        <C>                                                                                                  <C>
        Beginning Balance December 31, 2002                                                                  $2,043
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                       104
        Fair Value of New Contracts When Entered Into During the Period (b)                                       -
        Net Option Premiums Paid/(Received) (c)                                                                (110)
        Change in Fair Value Due to Valuation Methodology Changes                                                 -
        Effect of EITF 98-10 Rescission (d)                                                                      20
        Changes in Fair Value of Risk Management Contracts (e)                                                3,203
        Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)            (640)
                                                                                                             -------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                             4,620
        Net Cash Flow Hedge Contracts (g)                                                                      (926)
                                                                                                             -------
        Ending Balance December 31, 2003                                                                     $3,694
                                                                                                             =======
</TABLE>

         (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
             includes realized gains from risk management contracts and related
             derivatives that settled during 2003 that were entered into prior
             to 2003.
         (b) The "Fair Value of New Contracts When Entered Into During the
             Period" represents the fair value of long-term contracts entered
             into with customers during 2003. The fair value is calculated as of
             the execution of the contract. Most of the fair value comes from
             longer term fixed price contracts with customers that seek to limit
             their risk against fluctuating energy prices. The contract prices
             are valued against market curves associated with the delivery
             location.
         (c) "Net Option Premiums Paid/(Received)" reflects the net option
             premiums paid/(received) as they relate to unexercised and
             unexpired option contracts that were entered into in 2003.
         (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
             Cumulative Effect of Accounting Changes."
         (e) "Changes in Fair Value of Risk Management Contracts" represents the
             fair value change in the risk management portfolio due to market
             fluctuations during the current period. Market fluctuations are
             attributable to various factors such as supply/demand, weather,
             etc.
         (f) "Change in Fair Value of Risk Management Contracts Allocated to
             Regulated Jurisdictions" relates to the net gains (losses) of those
             contracts that are not reflected in the Consolidated Statements of
             Income. These net gains (losses) are recorded as regulatory
             liabilities/assets for those subsidiaries that operate in regulated
             jurisdictions.
         (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
             Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>

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

                                                                                                              After
                                                  2004          2005         2006       2007       2008       2008     Total (c)
                                                  ----          ----         ----       ----       ----       -----    ---------

                                                                                  (in thousands)
<C>                                             <C>             <C>          <C>         <C>       <C>         <C>      <C>
Prices Actually Quoted - Exchange Traded
 Contracts                                         $96          $(40)          $4         $24        $-          $-         $84
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)                   932           631          231         146        84           -       2,024
Prices Based on Models and Other
 Valuation Methods (b)                           1,323           223           45          95       199         627       2,512
                                                -------         -----        -----       -----     -----       -----     -------

Total                                           $2,351          $814         $280        $265      $283        $627      $4,620
                                                =======         =====        =====       =====     =====       =====     =======

</TABLE>

  (a)  "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
       information obtained from over-the-counter brokers, industry services, or
       multiple-party on-line platforms.
  (b)  "Prices Based on Models and Other Valuation Methods" is in absence of
       pricing information from external sources, modeled information is derived
       using valuation models developed by the reporting entity, reflecting when
       appropriate, option pricing theory, discounted cash flow concepts,
       valuation adjustments, etc. and may require projection of prices for
       underlying commodities beyond the period that prices are available from
       third-party sources. In addition, where external pricing information or
       market liquidity are limited, such valuations are classified as modeled.
       The determination of the point at which a market is no longer liquid for
       placing it in the Modeled category varies by market.
  (c) Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.


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

                                                                Domestic
                                                                  Power
                                                                --------
                                                             (in thousands)

       Beginning Balance December 31, 2002                        $(15)
       Changes in Fair Value (a)                                  (641)
       Reclassifications from AOCI to Net Income (b)                55
                                                                 ------
       Ending Balance December 31, 2003                          $(601)
                                                                 ======

  (a)    "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
  (b)    "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $435 thousand loss.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

VaR Associated with Risk Management Contracts

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
          End   High   Average   Low             End   High   Average   Low
         -----  ----   -------  -----           -----  ----   -------  -----
          $76   $294     $123    $29             $48   $146     $52     $11

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $33 million and $5 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                          AEP TEXAS NORTH COMPANY
                                                          STATEMENTS OF OPERATIONS
                                            For the Years Ended December 31, 2003, 2002 and 2001

                                                                             2003                    2002                  2001
                                                                             ----                    ----                  ----
                                                                                                (in thousands)
                   OPERATING REVENUES
-----------------------------------------------------------
<C>                                                                        <C>                     <C>                   <C>
Electric Generation, Transmission and Distribution                         $410,793                $210,315              $537,777
Sales to AEP Affiliates                                                      55,153                 240,425                18,681
                                                                           ---------               ---------             ---------
TOTAL                                                                       465,946                 450,740               556,458
                                                                           ---------               ---------             ---------

                   OPERATING EXPENSES
-----------------------------------------------------------
Fuel for Electric Generation                                                 39,082                  36,081               177,140
Fuel from Affiliates for Electric Generation                                 44,197                  64,385                     -
Purchased Electricity for Resale                                             87,006                  80,391                70,395
Purchased Electricity from AEP Affiliates                                    39,409                  37,582                56,656
Other Operation                                                              85,263                 104,960               111,248
Asset Impairments                                                                 -                  42,898                     -
Maintenance                                                                  18,961                  22,295                22,343
Depreciation and Amortization                                                36,242                  43,620                50,705
Taxes Other Than Income Taxes                                                20,570                  22,471                28,319
Income Tax Expense (Credit)                                                  27,189                 (11,814)                6,262
                                                                           ---------               ---------             ---------
TOTAL                                                                       397,919                 442,869               523,068
                                                                           ---------               ---------             ---------

OPERATING INCOME                                                             68,027                   7,871                33,390

Nonoperating Income                                                          68,451                  53,884                12,199
Nonoperating Expenses                                                        55,692                  54,876                10,695
Nonoperating Income Tax Expense (Credit)                                      3,074                    (289)                 (691)
Interest Charges                                                             22,049                  20,845                23,275
                                                                           ---------               ---------             ---------

Income (Loss) Before Extraordinary Items and
 Cumulative Effect of Accounting Changes                                     55,663                 (13,677)               12,310
Extraordinary (Loss) - (Net of Tax)                                            (177)                      -                     -
Cumulative Effect of Accounting Changes (Net of Tax)                          3,071                       -                     -
                                                                           ---------               ---------             ---------

NET INCOME (LOSS)                                                            58,557                 (13,677)               12,310

Gain on Reacquired Preferred Stock                                                3                       -                     -
Preferred Stock Dividend Requirements                                           104                     104                   104
                                                                           ---------               ---------             ---------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                                  $58,456                $(13,781)              $12,206
                                                                           =========               =========             =========

</TABLE>

The common stock of TNC is owned by a wholly-owned subsidiary of AEP.

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


<PAGE>
<TABLE>
<CAPTION>



                                                           AEP TEXAS NORTH COMPANY
                                               STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                       EQUITY AND COMPREHENSIVE INCOME
                                            For the Years Ended December 31, 2003, 2002 and 2001
                                                                (in thousands)


                                                                                                    Accumulated Other
                                                       Common         Paid-in        Retained         Comprehensive
                                                       Stock          Capital        Earnings         Income (Loss)          Total
                                                      -------         -------        --------       ----------------         -----
<C>                                                  <C>               <C>            <C>                <C>              <C>
DECEMBER 31, 2000                                    $137,214          $2,351         $122,588                 $-         $262,153

Common Stock Dividends Declared                                                        (28,824)                            (28,824)
Preferred Stock Dividends Declared                                                        (104)                               (104)
                                                                                                                          ---------
TOTAL                                                                                                                      233,225

           COMPREHENSIVE INCOME
--------------------------------------------
NET INCOME                                                                               12,310                             12,310
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  12,310
                                                     ---------         -------        ---------          ---------        ---------

DECEMBER 31, 2001                                    $137,214          $2,351         $105,970                 $-         $245,535

Common Stock Dividends                                                                 (20,247)                            (20,247)
Preferred Stock Dividends                                                                 (104)                               (104)
                                                                                                                          ---------
TOTAL                                                                                                                      225,184
                                                                                                                          ---------

           COMPREHENSIVE INCOME
--------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                        (15)             (15)
   Minimum Pension Liability                                                                              (30,748)         (30,748)
NET INCOME (LOSS)                                                                      (13,677)                            (13,677)
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 (44,440)
                                                     ---------         -------        ---------          ---------        ---------

DECEMBER 31, 2002                                    $137,214          $2,351          $71,942           $(30,763)        $180,744

Common Stock Dividends                                                                  (4,970)                             (4,970)
Preferred Stock Dividends                                                                 (104)                               (104)
Gain on Reacquired Preferred Stock                                                           3                                   3
                                                                                                                          ---------
TOTAL                                                                                                                      175,673
                                                                                                                          ---------

           COMPREHENSIVE INCOME
--------------------------------------------
Other Comprehensive Income (Loss),
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                       (586)            (586)
   Minimum Pension Liability                                                                                4,631            4,631
NET INCOME                                                                              58,557                              58,557
                                                                                                                          ---------
TOTAL COMPREHENSIVE INCOME                                                                                                  62,602
                                                     ---------         -------        ---------          ---------        ---------

DECEMBER 31, 2003                                    $137,214          $2,351         $125,428           $(26,718)        $238,275
                                                     =========         =======        =========          =========        =========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>



                                                         AEP TEXAS NORTH COMPANY
                                                              BALANCE SHEETS
                                                                  ASSETS
                                                  December 31, 2003 and December 31, 2002

                                                                                                 2003                   2002
                                                                                                 ----                   ----
                                                                                                        (in thousands)
               ELECTRIC UTILITY PLANT
------------------------------------------------------
<C>                                                                                          <C>                      <C>
Production                                                                                     $360,463                $353,087
Transmission                                                                                    268,695                 254,483
Distribution                                                                                    456,278                 445,486
General                                                                                         117,792                 111,679
Construction Work in Progress                                                                    30,199                  37,012
                                                                                             -----------              ----------
TOTAL                                                                                         1,233,427               1,201,747
Accumulated Depreciation and Amortization                                                       460,513                 446,818
                                                                                             -----------              ----------
TOTAL - NET                                                                                     772,914                 754,929
                                                                                             -----------              ----------

             OTHER PROPERTY AND INVESTMENTS
------------------------------------------------------
Non-Utility Property, Net                                                                         1,286                   1,086
Other Investments                                                                                     -                     127
                                                                                             -----------              ----------
TOTAL                                                                                             1,286                   1,213
                                                                                             -----------              ----------

                    CURRENT ASSETS
------------------------------------------------------
Cash and Cash Equivalents                                                                         2,863                   1,219
Advances to Affiliates                                                                           41,593                       -
Accounts Receivable:
  Customers                                                                                      56,670                  62,646
  Affiliated Companies                                                                           28,910                  43,632
  Accrued Unbilled Revenues                                                                       4,871                   6,829
  Miscellaneous                                                                                   3,411                      14
  Allowance for Uncollectible Accounts                                                             (175)                 (5,041)
Fuel Inventory                                                                                   10,925                  12,677
Materials and Supplies                                                                            8,866                   9,574
Risk Management Assets                                                                           10,340                   4,130
Margin Deposits                                                                                   1,285                      37
Prepayments and Other                                                                             1,834                   1,033
                                                                                             -----------               ---------
TOTAL                                                                                           171,393                 136,750
                                                                                             -----------               ---------

             DEFERRED DEBITS AND OTHER ASSETS
------------------------------------------------------
Regulatory Assets:
  Deferred Fuel Costs                                                                            26,680                  26,680
  Deferred Debt - Restructuring                                                                   6,579                  10,134
  Unamortized Loss on Reacquired Debt                                                             3,929                   3,283
  Other                                                                                           3,332                   5,000
Long-term Risk Management Assets                                                                  3,106                   2,248
Deferred Charges                                                                                 20,290                  11,912
                                                                                             -----------              ----------
TOTAL                                                                                            63,916                  59,257
                                                                                             -----------              ----------

TOTAL ASSETS                                                                                 $1,009,509                $952,149
                                                                                             ===========              ==========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                         AEP TEXAS NORTH COMPANY
                                                              BALANCE SHEETS
                                                      CAPITALIZATION AND LIABILITIES
                                                         December 31, 2003 and 2002

                                                                                             2003                    2002
                                                                                             ----                    ----
                                                                                                     (in thousands)
                  CAPITALIZATION
--------------------------------------------------
<C>                                                                                       <C>                       <C>
Common Shareholder's Equity:
   Common Stock - $25 Par Value:
     Authorized - 7,800,000 Shares
     Outstanding - 5,488,560 Shares                                                         $137,214                $137,214
      Paid-in Capital                                                                          2,351                   2,351
      Retained Earnings                                                                      125,428                  71,942
      Accumulated Other Comprehensive Income (Loss)                                          (26,718)                (30,763)
                                                                                          -----------               ---------
Total Common Shareholder's Equity                                                            238,275                 180,744
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                 2,357                   2,367
                                                                                          -----------               ---------
Total Shareholder's Equity                                                                   240,632                 183,111
Long-term Debt                                                                               314,249                 132,500
                                                                                          -----------               ---------
TOTAL                                                                                        554,881                 315,611
                                                                                          -----------               ---------

                CURRENT LIABILITIES
--------------------------------------------------
Short-term Debt - Affiliates                                                                      -                  125,000
Long-term Debt Due Within One Year                                                            42,505                      -
Advances from Affiliates                                                                           -                  80,407
Accounts Payable:
  General                                                                                     28,190                  32,714
  Affiliated Companies                                                                        40,601                  76,217
Customer Deposits                                                                                161                     117
Taxes Accrued                                                                                 22,877                   3,697
Interest Accrued                                                                               6,038                   2,776
Risk Management Liabilities                                                                    8,658                   3,801
Obligations Under Capital Leases                                                                 203                       -
Other                                                                                          9,419                  17,414
                                                                                          -----------               ---------
TOTAL                                                                                        158,652                 342,143
                                                                                          -----------               ---------

        DEFERRED CREDITS AND OTHER LIABILITIES
--------------------------------------------------
Deferred Income Taxes                                                                        113,019                 117,521
Long-term Risk Management Liabilities                                                          1,094                     557
Regulatory Liabilities:
  Asset Removal Costs                                                                         76,740                       -
  Deferred Investment Tax Credits                                                             19,990                  21,510
  Retail Clawback                                                                             11,804                  14,328
  Excess Earnings                                                                             14,262                  17,419
  SFAS 109 Regulatory Liability, Net                                                          13,655                  12,280
  Other                                                                                        1,826                   7,285
Obligations Under Capital Leases                                                                 270                       -
Deferred Credits and Other                                                                    43,316                 103,495
                                                                                          -----------               ---------
TOTAL                                                                                        295,976                 294,395
                                                                                          -----------               ---------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                      $1,009,509                $952,149
                                                                                          ===========               =========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                     AEP TEXAS NORTH COMPANY
                                                    STATEMENTS OF CASH FLOWS
                                        For the Years Ended December 31, 2003, 2002 and 2001

                                                                                 2003              2002               2001
                                                                                 ----              ----               ----
                                                                                              (in thousands)
                   OPERATING ACTIVITIES
--------------------------------------------------------
<C>                                                                             <C>              <C>                <C>
Net Income                                                                       $58,557         $(13,677)          $12,310
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                  36,242           43,620            50,705
   Extraordinary (Loss) - Net of Tax                                                 177                -                 -
   Write Down of Utility Plant Assets                                                  -           38,154                 -
   Write Down of Wind Farm Assets                                                      -            4,744                 -
   Deferred Income Taxes                                                          (3,493)         (12,275)          (11,891)
   Deferred Investment Tax Credits                                                (1,520)          (1,271)           (1,271)
   Cumulative Effect of Accounting Changes                                        (3,071)               -                 -
   Mark-to-Market of Risk Management Contracts                                    (2,558)          (1,127)           (3,506)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                       14,393          (80,900)           24,844
   Fuel, Materials and Supplies                                                    2,460           (2,754)            3,187
   Accounts Payable                                                              (40,140)          63,761           (42,604)
   Taxes Accrued                                                                  19,180          (13,661)           (1,543)
   Fuel Recovery                                                                       -           14,169            32,505
Change in Other Assets                                                            (8,955)         (16,928)           (1,432)
Change in Other Liabilities                                                        5,996           16,514            11,056
                                                                                ---------        ---------          --------
Net Cash Flows From Operating Activities                                          77,268           38,369            72,360
                                                                                ---------        ---------          --------

               INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                        (46,683)         (43,563)          (39,662)
Other                                                                                688              150              (127)
                                                                                ---------        ---------          --------
Net Cash Flows Used For Investing Activities                                     (45,995)         (43,413)          (39,789)
                                                                                ---------        ---------          --------

               FINANCING ACTIVITIES
--------------------------------------------------------
Change in Short-term Debt - Affiliates                                          (125,000)         125,000                 -
Issuance of Long-term Debt                                                       222,455                -                 -
Retirement of Long-term Debt                                                           -         (130,799)                -
Retirement of Preferred Stock                                                        (10)               -                 -
Change in Advances to/from Affiliates, Net                                      (122,000)          29,959            (8,130)
Dividends Paid on Common Stock                                                    (4,970)         (20,247)          (28,824)
Dividends Paid on Cumulative Preferred Stock                                        (104)            (104)             (104)
                                                                                ---------        ---------          --------
Net Cash Flows From (Used For) Financing Activities                              (29,629)           3,809           (37,058)
                                                                                ---------        ---------          --------

Net Increase (Decrease) in Cash and Cash Equivalents                               1,644           (1,235)           (4,487)
Cash and Cash Equivalents at Beginning of Period                                   1,219            2,454             6,941
                                                                                ---------        ---------          --------
Cash and Cash Equivalents at End of Period                                        $2,863           $1,219            $2,454
                                                                                =========        =========          ========

</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $16,384,000, $19,934,000
and $19,279,000 and for income taxes was $16,081,000, $15,544,000 and
$21,997,000 in 2003, 2002 and 2001 respectively.

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

<PAGE>
<TABLE>
<CAPTION>


                                                AEP TEXAS NORTH COMPANY
                                             STATEMENTS OF CAPITALIZATION
                                              December 31, 2003 and 2002

                                                                                                      2003          2002
                                                                                                      ----          ----
                                                                                                        (in thousands)

<C>                                                                                                 <C>           <C>
COMMON SHAREHOLDER'S EQUITY                                                                         $238,275      $180,744
                                                                                                    ---------     ---------

PREFERRED STOCK: $100 par value - authorized shares 810,000

                                                                           Shares
             Call Price            Number of Shares Redeemed             Outstanding
Series      December 31,             Year Ended December 31,             December 31,
------      ------------        -------------------------------          ------------
               2003             2003         2002          2001             2003
               ----             ----         ----          ----             ----

Not Subject to Mandatory Redemption:

4.40%           $107             102           -             -             23,570                      2,357         2,367
                                                                                                    ---------     ---------


LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                                  88,236        88,190
Installment Purchase Contracts                                                                        44,310        44,310
Senior Unsecured Notes                                                                               224,208             -
Less Portion Due Within One Year                                                                     (42,505)            -
                                                                                                    ---------     ---------

Long-term Debt Excluding Portion Due Within One Year                                                 314,249       132,500
                                                                                                    ---------     ---------

TOTAL CAPITALIZATION                                                                                $554,881      $315,611
                                                                                                    =========     =========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                               AEP TEXAS NORTH COMPANY
                                             SCHEDULE OF LONG-TERM DEBT
                                             December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                                                              2003                      2002
                                                                              ----                      ----
          %Rate                    Due                                                 (in thousands)
          -----                    ---
          <C>                      <C>            <C>                       <C>                       <C>
          7.00                     2004 - October 1                         $18,469                   $18,469
          6-1/8                    2004 - February 1                         24,036                    24,036
          6-3/8                    2005 - October 1                          37,609                    37,609
          7-3/4                    2007 - June 1                              8,151                     8,151
          Unamortized Discount                                                  (29)                      (75)
                                                                            --------                  --------
          Total                                                             $88,236                   $88,190
                                                                            ========                  ========
</TABLE>

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
<TABLE>
<CAPTION>

                                                                              2003                  2002
                                                                              ----                  ----
          %Rate                 Due                                                 (in thousands)
          ------                ---
<C>       <C>                   <C>                                        <C>                    <C>
Red River Authority of Texas:
          6.00                  2020 - June 1                              $44,310                $44,310
                                                                           =======                =======
</TABLE>

Under the terms of the Installment Purchase Contracts, TNC is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants. Interest payments are made semi-annually.

Senior Unsecured Notes outstanding were as follows:
<TABLE>
<CAPTION>

                                                                             2003                    2002
                                                                             ----                    ----
          %Rate                Due                                                  (in thousands)
          -----                ---
          <C>                  <C>          <C>                            <C>                        <C>
          5.50                 2013 - March 1                              $225,000                   $-
          Unamortized Discount                                                 (792)                   -
                                                                           ---------                  ---
          Total                                                            $224,208                   $-
                                                                           =========                  ===
</TABLE>

At December 31, 2003, future annual Long-term Debt payments are as follows:

                                                           Amount
                                                       (in thousands)
                       2004                                $42,505
                       2005                                 37,609
                       2006                                      -
                       2007                                  8,151
                       2008                                      -
                       Later Years                         269,310
                                                         ----------
                       Total Principal Amount              357,575
                       Unamortized Discount                   (821)
                                                       ------------
                       Total                              $356,754
                                                          =========



<PAGE>
<TABLE>
<CAPTION>


                                                 AEP TEXAS NORTH COMPANY
                                      INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to TNC's financial statements are combined with the notes to respective financial statements for other subsidiary
registrants. Listed below are the notes that apply to TNC. The footnotes begin on page L-1.

                                                                                                                    Footnote
                                                                                                                    Reference
                                                                                                                    ---------

<C>                                                                                                                 <C>
Organization and Summary of Significant Accounting Policies                                                         Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                      Note 2

Rate Matters                                                                                                        Note 4

Effects of Regulation                                                                                               Note 5

Customer Choice and Industry Restructuring                                                                          Note 6

Commitments and Contingencies                                                                                       Note 7

Guarantees                                                                                                          Note 8

Sustained Earnings Improvement Initiative                                                                           Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                              Note 10

Benefit Plans                                                                                                       Note 11

Business Segments                                                                                                   Note 12

Derivatives, Hedging and Financial Instruments                                                                      Note 13

Income Taxes                                                                                                        Note 14

Leases                                                                                                              Note 15

Financing Activities                                                                                                Note 16

Related Party Transactions                                                                                          Note 17

Jointly Owned Electric Utility Plant                                                                                Note 18

Unaudited Quarterly Financial Information                                                                           Note 19

</TABLE>

<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of AEP Texas North Company:

We have audited the accompanying balance sheets and statements of capitalization
of AEP Texas North Company as of December 31, 2003 and 2002, and the related
statements of operations, changes in common shareholder's equity and
comprehensive income, and cash flows for each of the three years in the period
ended December 31, 2003. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of AEP Texas North Company as of December 31,
2003 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted SFAS
143, "Accounting for Asset Retirement Obligations," effective January 1, 2003.


/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004

<PAGE>

















                            APPALACHIAN POWER COMPANY
                                AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>



                                                      APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                        SELECTED CONSOLIDATED FINANCIAL DATA


                                                  2003             2002               2001               2000            1999
                                                  ----             ----               ----               ----            ----
                                                                                 (in thousands)
     INCOME STATEMENTS DATA
---------------------------------
<C>                                           <C>               <C>                <C>                <C>             <C>
Operating Revenues                            $1,957,358        $1,814,470         $1,784,259         $1,759,253      $1,586,050
Operating Expenses                             1,638,547         1,512,407          1,509,273          1,558,099       1,344,814
                                              -----------      ------------        -----------       ------------     -----------
Operating Income                                 318,811           302,063            274,986            201,154         241,236
Nonoperating Items, Net                             (826)           20,106              6,868             11,752           8,096
Interest Charges                                 115,202           116,677            120,036            148,000         128,840
                                              -----------      ------------        -----------       ------------     -----------
Income Before Extraordinary Item and
 Cumulative Effect of Accounting Changes         202,783           205,492            161,818             64,906         120,492
Extraordinary Gain                                     -                 -                  -              8,938               -
                                              -----------      ------------        -----------       ------------     -----------
Income Before Cumulative Effect of
 Accounting Changes                              202,783           205,492            161,818             73,844         120,492
Cumulative Effect of Accounting Changes
 (Net of Tax)                                     77,257                 -                  -                  -               -
                                              -----------      ------------        -----------       ------------     -----------
Net Income                                       280,040           205,492            161,818             73,844         120,492
Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                 3,495             2,898              2,011              2,504           2,706
                                              -----------      ------------        -----------       ------------     -----------
Earnings Applicable to Common Stock             $276,545          $202,594           $159,807            $71,340        $117,786
                                              ===========      ============        ===========       ============     ===========


        BALANCE SHEETS DATA
---------------------------------
Electric Utility Plant                        $6,140,931        $5,895,303         $5,664,657         $5,418,278      $5,262,951
Accumulated Depreciation and Amortization      2,321,360         2,330,012          2,207,072          2,103,471       1,998,112
                                              -----------      ------------        -----------       ------------     -----------
Net Electric Utility Plant                    $3,819,571        $3,565,291         $3,457,585         $3,314,807      $3,264,839
                                              ===========      ============        ===========       ============     ===========

TOTAL ASSETS                                  $4,977,011        $4,722,442         $4,572,194         $6,657,920      $4,433,597
                                              ===========      ============        ===========       ============     ===========

Common Stock and Paid-in Capital                $980,357          $977,700           $976,244           $975,676        $974,717
Retained Earnings                                408,718           260,439            150,797            120,584         175,854
Accumulated Other
 Comprehensive Income (Loss)                     (52,088)          (72,082)              (340)                 -               -
                                              -----------      ------------        -----------       ------------     -----------
Total Common Shareholder's Equity             $1,336,987        $1,166,057         $1,126,701         $1,096,260      $1,150,571
                                              ===========      ============        ===========       ============     ===========

Cumulative Preferred Stock:
  Not Subject to Mandatory Redemption            $17,784           $17,790            $17,790            $17,790         $18,491
  Subject to Mandatory Redemption                  5,360            10,860             10,860             10,860          20,310
                                              -----------      ------------        -----------       ------------     -----------
Total Cumulative Preferred Stock                 $23,144           $28,650            $28,650            $28,650         $38,801
                                              ===========      ============        ===========       ============     ===========

Long-term Debt (a)                            $1,864,081        $1,893,861         $1,556,559         $1,605,818      $1,665,307
                                              ===========      ============        ===========       ============     ===========

Obligations Under Capital Leases (a)             $25,352           $33,589            $46,285            $63,160         $64,645
                                              ===========      ============        ===========       ============     ===========

TOTAL CAPITALIZATION AND LIABILITIES          $4,977,011        $4,722,442         $4,572,194         $6,657,920      $4,433,597
                                              ===========      ============        ===========       ============     ===========
</TABLE>

(a) Including portion due within one year.

<PAGE>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

APCo is a public utility engaged in the generation and purchase of electric
power, and the subsequent sale, transmission and distribution of that power to
929,000 retail customers in our service territory in southwestern Virginia and
southern West Virginia. As a member of the AEP Power Pool, we share the revenues
and the costs of the AEP Power Pool's sales to neighboring utilities and power
marketers. We also sell power at wholesale to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each member's prior twelve-month peak demand relative
to the sum of the peak demands of all members as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR),
which determines each member's percentage share of revenues and costs. In 2003
our relative share of the AEP Power Pool revenues and expenses increased over
the prior period as a result of our reaching a new peak demand in January 2003,
which increased our allocation factor.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

Net Income for 2003 increased $75 million over the prior year period primarily
due to the Cumulative Effect of Accounting Changes of $77 million recorded in
2003. See "Cumulative Effect of Accounting Changes" in Note 2 for further
information.

Income Before Cumulative Effect of Accounting Changes decreased slightly from
2002 as improvements in Operating Income were offset by reduced gains from risk
management activities included in Nonoperating Income (Expense). The improvement
in Operating Income was driven by increased earnings on system sales and reduced
employee related expenses partially offset by increased capacity charges
included in Purchased Electricity from AEP Affiliates.

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

Operating Income
----------------

Operating Income for 2003 increased by $17 million from 2002 primarily due to
the following:

  o     An increase in system sales and transmission revenues totaling $93
        million reflecting an increase in the volume of AEP Power Pool
        transactions, as well as our relative share based on the higher
        MLR.
  o     An increase  of $36  million in Sales to AEP  Affiliates due to
        strong  wholesale  sales by the AEP Power Pool.
  o     A decrease in Other Operation expense of $24 million due to
        severance expenses of $13 million incurred in 2002 related to the
        SEI initiative (see Note 9, "Sustained Earnings Improvement
        Initiative"), as well as reduced employee related expenses and
        insurance premiums in 2003. These decreases were partially offset
        by an increase in transmission equalization charges due to the
        increase in APCo's MLR as described above.
  o     A decrease in Depreciation and Amortization expense of $14 million
        primarily due to reduced amortization of generation related
        regulatory assets due to the return to SFAS 71 for the West
        Virginia jurisdiction in the first quarter of 2003 (see Note 5,
        "Effects of Regulation").
  o     An increase in gains from risk management activities of $10 million.

The increase in Operating Income for 2003 was partially offset by:

  o     An increase in purchased power expenses and fuel expense of $150
        million reflecting the $62 million increase in capacity charges
        resulting from the increase in APCo's MLR as described above, the
        increase in our relative share of the AEP Power Pool expenses and
        increased generation. Also, we accrued additional fuel expense to
        increase fuel costs to match fuel revenues billed to ratepayers
        (see "Deferred Fuel Costs" in Note 1, "Summary of Significant
        Accounting Policies").
  o     An increase in Maintenance expense of $13 million primarily due to
        increased maintenance of overhead lines required due to severe
        storm damage in the first quarter of 2003 and increased overhead
        line maintenance throughout the year.

Other Impacts on Earnings
-------------------------

Nonoperating income decreased $36 million in 2003 compared to 2002 primarily due
to lower profit from power sold outside AEP's traditional marketing area
resulting from AEP's plan to exit risk management activities in areas outside of
its traditional market area. The decrease in nonoperating income was partially
offset by a $12 million decrease in nonoperating income taxes resulting
primarily from the reduced pre-tax nonoperating book income.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes of $77 million is due to the
implementation of SFAS 143 and EITF 02-03 (see "Cumulative Effect" section of
Note 2).

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

Net Income
----------

Net Income for 2002 increased $44 million over the prior year due to higher
retail sales resulting from weather related electricity demands and reductions
in Maintenance expense. Most significantly the Mountaineer, Amos and Glen Lyn
plants, down for boiler maintenance in 2001, were back online in 2002 resulting
in increased availability of generation and decreased maintenance expense. In
addition, net nonoperating income increased $10 million as a result of a
reduction in incentive compensation partially offset by decreased gains from
risk management activities.

Operating Income
----------------

Operating Income for 2002 increased $27 million compared to the prior year
primarily due to the following:

  o     Retail sales increased $42 million primarily due to weather related
        electricity demands.
  o     An increase in Sales to AEP Affiliates of $15 million due to an
        increase in generation capacity and power available to be delivered to
        the AEP Power Pool.
  o     A decrease of $10 million in Maintenance expense due to the boiler
        maintenance incurred in 2001 as discussed above.
  o     A $97 million decrease in purchase power expense resulting from
        increased internal generation based on the higher plant availability
        partially offset by a $79 million increase in Fuel expense necessary
        to support the increased generation.
  o     A $5 million decrease in Taxes Other Than Income Taxes primarily
        due to the replacement of the municipal license tax imposed on
        APCo with the Virginia consumption tax that was imposed on the
        consumer.


These increases in Operating Income for 2002 were offset by:

  o     A net $32 million decrease in system sales partially offset by gains
        from risk management activities.
  o     An increase of $9 million in Other Operation expense mainly due to
        $13 million of severance expenses related to the SEI initiative, a
        reduction in gains recorded on the dispositions of SO2 emission
        allowances and increased insurance premiums and other employee benefit
        costs.
  o     An increase of $9 million in Depreciation and Amortization due to
        increased amortization for the net generation-related regulatory
        assets related to our West Virginia jurisdiction which were
        assigned to the distribution portion of our business and are being
        recovered through regulated rates.
  o     An increase of $18 million in Income Taxes due to an increase in
        pre-tax income.

Other Impacts on Earnings
-------------------------

Nonoperating income decreased $20 million for 2002, primarily due to a decrease
in gains from risk management activities driven by a decline in market prices.
Nonoperating Expenses decreased $30 million due to decreased incentives related
to risk management activities.

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:
                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               Baa1          BBB         A-
          Senior Unsecured Debt              Baa2          BBB         BBB+

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from Baa1 to Baa2 and a downgrade of secured
ratings from A3 to Baa1. The completion of this review was a culmination of
ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.

Cash Flow
---------

Cash flows for 2003, 2002 and 2001 were as follows:
<TABLE>
<CAPTION>

                                                                      2003             2002             2001
                                                                      ----             ----             ----
                                                                                  (in thousands)
<C>                                                                <C>              <C>              <C>
Cash and cash equivalents at beginning of period                     $4,285          $13,663           $5,847
                                                                   ---------        ---------        ---------
Cash flow from (used for):
  Operating activities                                              461,276          280,709          393,854
  Investing activities                                             (286,608)        (275,475)        (313,298)
  Financing activities                                             (133,072)         (14,612)         (72,740)
                                                                   ---------        ---------        ---------
Net increase (decrease) in cash and cash equivalents                 41,596           (9,378)           7,816
                                                                   ---------        ---------        ---------
Cash and cash equivalents at end of period                          $45,881           $4,285          $13,663
                                                                   =========        =========        =========
</TABLE>

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

Cash flow from operating activities in 2003 increased $181 million over the
prior year primarily due to decreases in various accounts receivable balances in
2003 and changes in Federal and state income tax accruals.

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

Construction expenditures in 2003 versus 2002 increased $12 million. The current
year expenditures of $289 million were focused primarily on projects to improve
service reliability for transmission and distribution, as well as environmental
upgrades.

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

In 2003, we issued two series of Senior Unsecured Notes, each in the amount of
$200 million which were used to call First Mortgage Bonds and Senior Unsecured
Notes and fund maturities. Additionally, we incurred obligations of $188 million
in Installment Purchase Contracts to redeem higher costing Installment Purchase
Contracts.

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

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

<TABLE>
<CAPTION>

                                                                     Payments Due by Period
                                                                         (in thousands)

Contractual Cash Obligations               Less Than 1 year     2-3 years     4-5 years      After 5 years       Total
----------------------------               ----------------     ---------     ---------      -------------       -----

<C>                                            <C>                <C>           <C>             <C>            <C>
Long-term Debt                                 $161,008           $677,521      $400,027        $625,525       $1,864,081
Advances from Affiliates                         82,994                  -             -               -           82,994
Preferred Stock Subject to
 Mandatory Redemption                                 -                  -         5,360               -            5,360
Capital Lease Obligations                        11,735             12,036         5,309           1,802           30,882
Unconditional Purchase Obligations (a)          311,826            351,760        90,163               -          753,749
Noncancellable Operating Leases                   5,998              9,609         5,696           6,094           27,397
                                               ---------        -----------     =========       =========      ===========
  Total                                        $573,561         $1,050,926      $506,555        $633,421       $2,764,463
                                               =========        ===========     =========       =========      ===========
</TABLE>

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

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                              MTM Risk Management Contract Net Assets
                                                  Year Ended December 31, 2003
                                                         (in thousands)
        Domestic Power
        --------------

        <C>                                                                                                        <C>
        Beginning Balance December 31, 2002                                                                        $96,852
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                          (33,846)
        Fair Value of New Contracts When Entered Into During the Period (b)                                              -
        Net Option Premiums Paid/(Received) (c)                                                                        143
        Change in Fair Value Due to Valuation Methodology Changes                                                        -
        Effect of EITF 98-10 Rescission (d)                                                                         (4,664)
        Changes in Fair Value of Risk Management Contracts (e)                                                       9,305
        Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                       276
                                                                                                                   --------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                   68,066
        Net Cash Flow Hedge Contracts (g)                                                                              553
        DETM Assignment (h)                                                                                        (32,287)
                                                                                                                   --------
        Ending Balance December 31, 2003                                                                           $36,332
                                                                                                                   ========
</TABLE>

        (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
            includes realized gains from risk management contracts and related
            derivatives that settled during 2003 that were entered into prior to
            2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value of long-term contracts entered
            into with customers during 2003. The fair value is calculated as of
            the execution of the contract. Most of the fair value comes from
            longer term fixed price contracts with customers that seek to limit
            their risk against fluctuating energy prices. The contract prices
            are valued against market curves associated with the delivery
            location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
            premiums paid/(received) as they relate to unexercised and unexpired
            option contracts that were entered into in 2003.
        (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
            Cumulative Effect of Accounting Changes." (e) "Changes in Fair
            Value of Risk Management Contracts" represents the fair value
            change in the risk management portfolio due to market fluctuations
            during the current period. Market fluctuations are attributable to
            various factors such as supply/demand, weather, etc.
        (f) "Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Operations. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.
        (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
            Accumulated Other Comprehensive Income (Loss).
        (h) See Note 17 "Related Party Transactions."


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

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

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

<TABLE>
<CAPTION>


                                                Maturity and Source of Fair Value of MTM
                                                  Risk Management Contract Net Assets
                                            Fair Value of Contracts as of December 31, 2003
                                                                                                                   After
                                                      2004          2005        2006       2007         2008       2008    Total (c)
                                                      ----          ----        ----       ----         ----       -----   ---------
                                                                  (in thousands)
<C>                                                 <C>           <C>        <C>          <C>         <C>        <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                    $1,219        $(245)        $29        $191          $-         $-      $1,194
Prices Provided by Other External Sources -
 OTC Broker Quotes (a)                               23,753        8,514       8,350       3,395       1,703          -      45,715
Prices Based on Models and Other Valuation
 Methods (b)                                             (7)          36       3,313       3,829       3,521      10,465     21,157
                                                    --------      -------    --------     -------     -------    --------   --------

Total                                               $24,965       $8,305     $11,692      $7,415      $5,224     $10,465    $68,066
                                                    ========      =======    ========     =======     =======    ========   ========
</TABLE>

   (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
       reflects information obtained from over-the-counter brokers, industry
       services, or multiple-party on-line platforms.
   (b) "Prices Based on Models and Other Valuation Methods" is in absence
       of pricing information from external sources, modeled information is
       derived using valuation models developed by the reporting entity,
       reflecting when appropriate, option pricing theory, discounted cash
       flow concepts, valuation adjustments, etc. and may require projection
       of prices for underlying commodities beyond the period that prices are
       available from third- party sources. In addition, where external pricing
       information or market liquidity are limited, such valuations are
       classified as modeled. The determination of the point at which a market
       is no longer liquid for placing it in the Modeled category varies by
       market.
   (c) Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

<TABLE>
<CAPTION>

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

                                                           Domestic          Foreign
                                                            Power            Currency          Interest Rate      Consolidated
                                                           --------          --------          -------------      ------------
                                                                                   (in thousands)
        <C>                                                 <C>              <C>                  <C>                <C>
        Beginning Balance December 31, 2002                 $(394)           $(190)               $(1,336)           $(1,920)
        Changes in Fair Value (a)                             272                -                   (720)              (448)
        Reclassifications from AOCI to Net Income (b)         481                7                    311                799
                                                             -----           ------               --------           --------
        Ending Balance December 31, 2003                     $359            $(183)               $(1,745)           $(1,569)
                                                             =====           ======               ========           ========
</TABLE>

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,325 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $596  $2,314    $969    $230          $1,289  $3,948   $1,412    $286

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $102 million and $87 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                    CONSOLIDATED STATEMENTS OF INCOME
                                          For the Years Ended December 31, 2003, 2002 and 2001

                                                                               2003                 2002                2001
                                                                               ----                 ----                ----
                                                                                               (in thousands)
                   OPERATING REVENUES
--------------------------------------------------------
<C>                                                                        <C>                  <C>                  <C>
Electric Generation, Transmission and Distribution                         $1,734,565           $1,627,993           $1,612,974
Sales to AEP Affiliates                                                       222,793              186,477              171,285
                                                                           -----------          -----------          -----------
TOTAL                                                                       1,957,358            1,814,470            1,784,259
                                                                           -----------          -----------          -----------

                   OPERATING EXPENSES
--------------------------------------------------------
Fuel for Electric Generation                                                  454,901              430,963              351,557
Purchased Electricity for Resale                                               66,084               57,091               42,092
Purchased Electricity from AEP Affiliates                                     351,210              234,597              346,878
Other Operation                                                               245,308              269,426              260,518
Maintenance                                                                   135,596              122,209              132,373
Depreciation and Amortization                                                 175,772              189,335              180,393
Taxes Other Than Income Taxes                                                  90,087               95,249               99,878
Income Taxes                                                                  119,589              113,537               95,584
                                                                           -----------          -----------          -----------
TOTAL                                                                       1,638,547            1,512,407            1,509,273
                                                                           -----------          -----------          -----------

OPERATING INCOME                                                              318,811              302,063              274,986

Nonoperating Income (Expense)                                                  (5,661)              30,020               50,268
Nonoperating Expenses                                                           9,534               12,525               42,261
Nonoperating Income Tax Expense (Credit)                                      (14,369)              (2,611)               1,139
Interest Charges                                                              115,202              116,677              120,036
                                                                           -----------          -----------          -----------

Income Before Cumulative Effect
 of Accounting Changes                                                        202,783              205,492              161,818
Cumulative Effect of Accounting Changes (Net of Tax)                           77,257                    -                    -
                                                                           -----------          -----------          -----------

NET INCOME                                                                    280,040              205,492              161,818

Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                                              3,495                2,898                2,011
                                                                           -----------          -----------          -----------

EARNINGS APPLICABLE TO COMMON STOCK                                          $276,545             $202,594             $159,807
                                                                           ===========          ===========          ===========
</TABLE>


The common stock of APCo is wholly-owned by AEP. See Notes to Respective
Financial Statements beginning on page L-1.


<PAGE>
<TABLE>
<CAPTION>


                                                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                           CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                        EQUITY AND COMPREHENSIVE INCOME
                                               For the Years Ended December 31, 2003, 2002 and 2001
                                                                 (in thousands)


                                                                                                 Accumulated Other
                                                      Common         Paid-in        Retained        Comprehensive
                                                      Stock          Capital        Earnings       Income (Loss)          Total
                                                      ------         -------        --------     -----------------        -----

<C>                                                   <C>            <C>             <C>                  <C>           <C>
DECEMBER 31, 2000                                     $260,458       $715,218        $120,584                   $-      $1,096,260

Common Stock Dividends                                                               (129,594)                            (129,594)
Preferred Stock Dividends                                                              (1,443)                              (1,443)
Capital Stock Expense                                                     568            (568)                                   -
                                                                                                                        -----------
TOTAL                                                                                                                      965,223
                                                                                                                        -----------

        COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),
 Net of Taxes:
  Unrealized Loss on Cash Flow Hedges                                                                         (340)           (340)
NET INCOME                                                                            161,818                              161,818
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 161,478
                                                      ---------      ---------       ---------            ---------     -----------

DECEMBER 31, 2001                                     $260,458       $715,786        $150,797                $(340)     $1,126,701

Common Stock Dividends                                                                (92,952)                             (92,952)
Preferred Stock Dividends                                                              (1,442)                              (1,442)
Capital Stock Expense                                                   1,456          (1,456)                                   -
                                                                                                                        -----------
TOTAL                                                                                                                    1,032,307
                                                                                                                        -----------

        COMPREHENSIVE INCOME
Other Comprehensive Income (Loss),
 Net of Taxes:
  Unrealized Loss on Cash Flow Hedges                                                                       (1,580)         (1,580)
  Minimum Pension Liability                                                                                (70,162)        (70,162)
NET INCOME                                                                            205,492                              205,492
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 133,750
                                                      ---------      ---------       ---------            ---------     -----------

DECEMBER 31, 2002                                     $260,458       $717,242        $260,439             $(72,082)     $1,166,057

Common Stock Dividends                                                               (128,266)                            (128,266)
Preferred Stock Dividends                                                              (1,001)                              (1,001)
Capital Stock Expense                                                   2,494          (2,494)                                   -
SFAS 71 Reapplication                                                     163                                                  163
                                                                                                                        -----------
TOTAL                                                                                                                    1,036,953
                                                                                                                        -----------

        COMPREHENSIVE INCOME
Other Comprehensive Income,
 Net of Taxes:
  Unrealized Gain on Cash Flow Hedges                                                                          351             351
  Minimum Pension Liability                                                                                 19,643          19,643
NET INCOME                                                                            280,040                              280,040
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 300,034
                                                      ---------      ---------       ---------            ---------     -----------

DECEMBER 31, 2003                                     $260,458       $719,899        $408,718             $(52,088)     $1,336,987
                                                      =========      =========       =========            =========     ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>

                                                    APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                    ASSETS
                                                           December 31, 2003 and 2002

                                                                                            2003                     2002
                                                                                            ----                     ----
                                                                                                   (in thousands)
                ELECTRIC UTILITY PLANT
--------------------------------------------------------
<C>                                                                                       <C>                     <C>
Production                                                                                $2,287,043              $2,245,945
Transmission                                                                               1,240,889               1,218,108
Distribution                                                                               2,006,329               1,951,804
General                                                                                      294,786                 272,901
Construction Work in Progress                                                                311,884                 206,545
                                                                                          -----------             -----------
TOTAL                                                                                      6,140,931               5,895,303
Accumulated Depreciation and Amortization                                                  2,321,360               2,330,012
                                                                                          -----------             -----------
TOTAL - NET                                                                                3,819,571               3,565,291
                                                                                          -----------             -----------

             OTHER PROPERTY AND INVESTMENTS
--------------------------------------------------------
Non-Utility Property, Net                                                                     20,574                  20,550
Other Investments                                                                             26,668                  34,103
                                                                                          -----------             -----------
TOTAL                                                                                         47,242                  54,653
                                                                                          -----------             -----------

                     CURRENT ASSETS
--------------------------------------------------------

Cash and Cash Equivalents                                                                     45,881                   4,285
Accounts Receivable:
  Customers                                                                                  133,717                 155,521
  Affiliated Companies                                                                       137,281                 122,665
  Accrued Unbilled Revenues                                                                   35,020                  30,948
  Miscellaneous                                                                                3,961                   5,374
  Allowance for Uncollectible Accounts                                                        (2,085)                (13,439)
Fuel Inventory                                                                                42,806                  53,646
Materials and Supplies                                                                        71,978                  59,886
Risk Management Assets                                                                        71,189                  94,010
Margin Deposits                                                                               11,525                   1,238
Prepayments and Other                                                                         13,301                  12,386
                                                                                          -----------             -----------
TOTAL                                                                                        564,574                 526,520
                                                                                          -----------             -----------

             DEFERRED DEBITS AND OTHER ASSETS
--------------------------------------------------------
Regulatory Assets:
  Transition Regulatory Assets                                                                30,855                 158,708
  SFAS 109 Regulatory Asset, Net                                                             325,889                 209,884
  Unamortized Loss on Reacquired Debt                                                         19,005                   9,147
  Other Regulatory Assets                                                                     41,447                  17,814
Long-term Risk Management Assets                                                              70,900                 115,748
Deferred Property Taxes                                                                       35,343                  35,323
Other Deferred Charges                                                                        22,185                  29,354
                                                                                          -----------             -----------
TOTAL                                                                                        545,624                 575,978
                                                                                          -----------             -----------

TOTAL ASSETS                                                                              $4,977,011              $4,722,442
                                                                                          ===========             ===========

</TABLE>


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


<PAGE>
<TABLE>
<CAPTION>


                                        APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                CONSOLIDATED BALANCE SHEETS
                                              CAPITALIZATION AND LIABILITIES
                                                December 31, 2003 and 2002



                                                                                                     2003               2002
                                                                                                     ----               ----
                                                                                                          (in thousands)
                     CAPITALIZATION
------------------------------------------------------------
<C>                                                                                              <C>                 <C>
Common Shareholder's Equity:
    Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                                                              $260,458            $260,458
      Paid-in Capital                                                                               719,899             717,242
      Retained Earnings                                                                             408,718             260,439
      Accumulated Other Comprehensive Income (Loss)                                                 (52,088)            (72,082)
                                                                                                 -----------         -----------
Total Common Shareholder's Equity                                                                 1,336,987           1,166,057
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                       17,784              17,790
                                                                                                 -----------         -----------
Total Shareholder's Equity                                                                        1,354,771           1,183,847
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption                              5,360              10,860
Long-term Debt                                                                                    1,703,073           1,738,854
                                                                                                 -----------         -----------
TOTAL                                                                                             3,063,204           2,933,561
                                                                                                 -----------         -----------

                   CURRENT LIABILITIES
------------------------------------------------------------
Long-term Debt Due Within One Year                                                                  161,008             155,007
Advances from Affiliates                                                                             82,994              39,205
Accounts Payable:
  General                                                                                           140,497             141,546
  Affiliated Companies                                                                               81,812              98,374
Customer Deposits                                                                                    33,930              26,186
Taxes Accrued                                                                                        50,259              29,181
Interest Accrued                                                                                     22,113              22,437
Risk Management Liabilities                                                                          51,430              69,001
Obligations Under Capital Leases                                                                      9,218               9,598
Other                                                                                                60,289              70,234
                                                                                                 -----------         -----------
TOTAL                                                                                               693,550             660,769
                                                                                                 -----------         -----------

         DEFERRED CREDITS AND OTHER LIABILITIES
------------------------------------------------------------
Deferred Income Taxes                                                                               803,355             701,801
Regulatory Liabilities:
  Asset Removal Costs                                                                                92,497                   -
  Deferred Investment Tax Credits                                                                    30,545              33,691
  WV Rate Stabilization Deferral                                                                          -              75,601
  Over Recovery of Fuel Cost                                                                         68,704                   -
  Other Regulatory Liabilities                                                                       17,326                  72
Long-term Risk Management Liabilities                                                                54,327              44,517
Obligations Under Capital Leases                                                                     16,134              23,991
Asset Retirement Obligation                                                                          21,776                   -
Deferred Credits and Other                                                                          115,593             248,439
                                                                                                 -----------         -----------
TOTAL                                                                                             1,220,257           1,128,112
                                                                                                 -----------         -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                             $4,977,011          $4,722,442
                                                                                                 ===========         ==========

</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                                APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             For the Years Ended December 31, 2003, 2002 and 2001

                                                                                     2003                2002                2001
                                                                                     ----                ----                ----
                                                                                                   (in thousands)
                 OPERATING ACTIVITIES
------------------------------------------------------
<C>                                                                                <C>                  <C>                <C>
Net Income                                                                         $280,040            $205,492            $161,818
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Cumulative Effect of Accounting Changes                                         (77,257)                  -                   -
    Depreciation and Amortization                                                   175,772             189,335             180,505
    Deferred Income Taxes                                                            24,563              16,777              42,498
    Deferred Investment Tax Credits                                                  (3,146)             (4,637)             (4,765)
    Deferred Power Supply Costs, Net                                                 74,071               6,365               1,411
    Mark to Market of Risk Management Contracts                                      56,409             (21,151)            (68,254)
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                         (6,825)            (83,453)            169,691
    Fuel, Materials and Supplies                                                     (1,252)              3,016             (19,957)
    Accounts Payable                                                                (17,611)             27,805             (45,073)
    Taxes Accrued                                                                    21,078             (26,402)             (7,675)
    Incentive Plan Accrued                                                           (7,210)               (858)             (2,451)
Rate Stabilization Deferral                                                         (75,601)                  -                   -
Change in Operating Reserves                                                        (46,984)             (3,190)             (5,358)
Change in Other Assets                                                              (17,813)            (43,338)             19,418
Change in Other Liabilities                                                          83,042              14,948             (27,954)
                                                                                   ---------           ---------           ---------
Net Cash Flows From Operating Activities                                            461,276             280,709             393,854
                                                                                   ---------           ---------           ---------

               INVESTING ACTIVITIES
------------------------------------------------------
Construction Expenditures                                                          (288,577)           (276,549)           (306,046)
Proceeds from Sale of Property and Other                                              1,969               1,074              (7,252)
                                                                                   ---------           ---------           ---------
Net Cash Flows Used For Investing Activities                                       (286,608)           (275,475)           (313,298)
                                                                                   ---------           ---------           ---------

               FINANCING ACTIVITIES
------------------------------------------------------
Issuance of Long-term Debt                                                          580,649             647,401             124,588
Retirement of Long-term Debt                                                       (622,737)           (315,007)           (175,000)
Retirement of Preferred Stock                                                        (5,506)                  -                   -
Change in Short-term Debt (net)                                                           -                   -            (191,495)
Change in Advances from Affiliates, Net                                              43,789            (252,612)            300,204
Dividends Paid on Common Stock                                                     (128,266)            (92,952)           (129,594)
Dividends Paid on Cumulative Preferred Stock                                         (1,001)             (1,442)             (1,443)
                                                                                   ---------           ---------           ---------
Net Cash Flows Used For Financing Activities                                       (133,072)            (14,612)            (72,740)
                                                                                   ---------           ---------           ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                 41,596              (9,378)              7,816
Cash and Cash Equivalents at Beginning of Period                                      4,285              13,663               5,847
                                                                                   ---------           ---------           ---------
Cash and Cash Equivalents at End of Period                                          $45,881              $4,285             $13,663
                                                                                   =========           =========           =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $108,045,000, $111,528,000
and $117,283,000 and for income taxes was $62,673,000, $125,120,000 and
$56,981,000 in 2003, 2002 and 2001, respectively.

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

<PAGE>
<TABLE>
<CAPTION>


                                          APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                          CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                  December 31, 2003 and 2002


                                                                                                        2003              2002
                                                                                                        ----              ----

                                                                                                             (in thousands)

<C>                                                                                                  <C>              <C>
COMMON SHAREHOLDER'S EQUITY                                                                          $1,336,987       $1,166,057

PREFERRED STOCK:
No Par Value - Authorized 8,000,000 shares

              Call Price                                             Shares
             December 31,         Number of Shares Redeemed        Outstanding
Series         2003 (a)            Year Ended December 31,       December 31, 2003
------      ------------        ----------------------------     -----------------
                                2003        2002        2001
                                ----        ----        ----

Not Subject to Mandatory Redemption - $100 Par:
4-1/2%          $110             60           6           -           177,839                            17,784           17,790
                                                                                                     -----------      -----------

Subject to Mandatory Redemption - $100 Par(b):

5.90%  (c)                   25,000           -           -            22,100                             2,210            4,710
5.92%  (c)                   30,000           -           -            31,500                             3,150            6,150
                                                                                                     -----------      -----------
Total                                                                                                     5,360           10,860
                                                                                                     -----------      -----------

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                                    340,269          489,697
Installment Purchase Contracts                                                                          276,477          235,027
Senior Unsecured Notes                                                                                1,244,813        1,166,609
Other Long-term Debt                                                                                      2,522            2,528
Less Portion Due Within One Year                                                                       (161,008)        (155,007)
                                                                                                     -----------      -----------

Long-term Debt Excluding Portion Due Within One Year                                                  1,703,073        1,738,854
                                                                                                     -----------      -----------

TOTAL CAPITALIZATION                                                                                 $3,063,204       $2,933,561
                                                                                                     ===========      ===========
</TABLE>

(a)  The cumulative preferred stock is callable at the price indicated plus
     accrued dividends. The involuntary liquidation preference is $100 per
     share. The aggregate involuntary liquidation price for all shares of
     cumulative preferred stock may not exceed $300 million. The unissued shares
     of the cumulative preferred stock may or may not possess mandatory
     redemption characteristics upon issuance.
(b)  The sinking fund provisions of each series subject to mandatory redemption
     have been met by shares purchased in advance of the due date.
(c)  Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
     share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
     series outstanding under sinking fund provisions at its option and all
     outstanding shares must be redeemed in 2008. Shares previously redeemed may
     be applied to meet the sinking fund requirement.

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


<PAGE>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                                      2003             2002
                                                      ----             ----
   %Rate            Due                                  (in thousands)
   -----            ---
   6.00             2003 - November 1                    $-          $30,000
   7.70             2004 - September 1               21,000           21,000
   7.85             2004 - November 1                50,000           50,000
   8.00             2005 - May 1                     50,000           50,000
   6.89             2005 - June 22                   30,000           30,000
   6.80             2006 - March 1                  100,000          100,000
   8.50             2022 - December 1                     -           70,000
   7.80             2023 - May 1                          -           30,237
   7.15             2023 - November 1                     -           20,000
   7.125            2024 - May 1                     45,000           45,000
   8.00             2025 - June 1                    45,000           45,000
   Unamortized Discount                                (731)          (1,540)
                                                   ---------        ---------
   Total                                           $340,269         $489,697
                                                   =========        =========

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment Purchase Contracts have been entered into, in connection with the
issuance of pollution control revenue bonds, by governmental authorities as
follows:


                                                        2003             2002
                                                        ----             ----
     %Rate            Due                                   (in thousands)
     -----            ---
Industrial Development Authority of Russell County, Virginia:
     7.70             2007 - November 1                    $-         $17,500
     (a)              2007 - November 1                17,500               -
     5.00             2021 - November 1                19,500          19,500

Putnam County, West Virginia:

     (b)              2019 - June 1                    40,000               -
     6.60             2019 - July 1                         -          30,000
     5.45             2019 - June 1                    40,000          40,000
     (c)              2019 - May 1                     30,000               -

Mason County, West Virginia:

     7-7/8            2013 - November 1                     -          10,000
     6.85             2022 - June 1                         -          40,000
     6.60             2022 - October 1                      -          50,000
     6.05             2024 - December 1                30,000          30,000
     5.50             2022 - October 1                100,000               -
     Unamortized Discount                                (523)         (1,973)
                                                     ---------       ---------
     Total                                           $276,477        $235,027
                                                     =========       =========


(a) Rate is an annual long-term fixed rate of 2.70% through November 1, 2006.
    After that date the rate may be daily, weekly, commercial paper, auction or
    other long-term rate as designated by APCo (fixed rate bonds).
(b) In December 2003 an auction rate was established. Auction rates are
    determined by standard procedures every 35 days. The rate on December 31,
    2003 was 1.10%. The proceeds from the issuance were used to redeem the
    5.45% Putnam County Installment Purchase Contracts on January 12, 2004.
(c) Rate is an annual long-term fixed rate of 2.80% through November 1, 2006.
    After that date the rate may be daily, weekly, commercial paper, auction or
    other long-term rate as designated by APCo (fixed rate bonds).

Under the terms of the installment purchase contracts, APCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior Unsecured Notes outstanding were as follows:


                                                   2003            2002
                                                   ----            ----
%Rate            Due                                   (in thousands)
-----            ---
(a)              2003 - August 20                     $-         $125,000
7.45             2004 - November 1                50,000           50,000
4.80             2005 - June 15                  450,000          450,000
4.32             2007 - November 12              200,000          200,000
3.60             2008 - May 15                   200,000                -
6.60             2009 - May 1                    150,000          150,000
5.95             2033 - May 15                   200,000                -
7.20             2038 - March 31                       -          100,000
7.30             2038 - June 30                        -          100,000
Unamortized Discount                              (5,187)          (8,391)
                                              -----------      -----------
Total                                         $1,244,813       $1,166,609
                                              ===========      ===========

(a) A floating interest rate was determined monthly. The rate on December 31,
2002 was 2.167%.

At December 31, 2003, future annual long-term debt payments are as follows:

                                                          Amount
                                                          ------
                                                       (in thousands)
          2004                                           $161,008
          2005                                            530,010
          2006                                            147,511
          2007                                            200,013
          2008                                            200,014
          Later Years                                     631,966
                                                       -----------
          Total Principal Amount                        1,870,522
          Unamortized Discount                             (6,441)
                                                       -----------
          Total                                        $1,864,081
                                                       ===========


<PAGE>
<TABLE>
<CAPTION>


                                         APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                      INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to APCo's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to APCo. The footnotes begin on page L-1.

                                                                                                                       Footnote
                                                                                                                       Reference
                                                                                                                       ---------
<C>                                                                                                                    <C>
Organization and Summary of Significant Accounting Policies                                                            Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                         Note 2

Rate Matters                                                                                                           Note 4

Effects of Regulation                                                                                                  Note 5

Customer Choice and Industry Restructuring                                                                             Note 6

Commitments and Contingencies                                                                                          Note 7

Guarantees                                                                                                             Note 8

Sustained Earnings Improvement Initiative                                                                              Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                 Note 10

Benefit Plans                                                                                                          Note 11

Business Segments                                                                                                      Note 12

Derivatives, Hedging and Financial Instruments                                                                         Note 13

Income Taxes                                                                                                           Note 14

Leases                                                                                                                 Note 15

Financing Activities                                                                                                   Note 16

Related Party Transactions                                                                                             Note 17

Unaudited Quarterly Financial Information                                                                              Note 19

</TABLE>


<PAGE>


     INDEPENDENT AUDITORS' REPORT



     To the Shareholders and Board of
     Directors of Appalachian Power Company:

     We have audited the accompanying consolidated balance sheets and
     consolidated statements of capitalization of Appalachian Power Company and
     subsidiaries as of December 31, 2003 and 2002, and the related consolidated
     statements of income, changes in common shareholder's equity and
     comprehensive income and cash flows for each of the three years in the
     period ended December 31, 2003. These financial statements are the
     responsibility of the Company's management. Our responsibility is to
     express an opinion on these financial statements based on our audits.

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

     In our opinion, such consolidated financial statements present fairly, in
     all material respects, the financial position of Appalachian Power Company
     and subsidiaries as of December 31, 2003 and 2002, and the results of its
     operations and its cash flows for each of the three years in the period
     ended December 31, 2003 in conformity with accounting principles generally
     accepted in the United States of America.

     As discussed in Note 2 to the consolidated financial statements, the
     Company adopted SFAS 143, "Accounting for Asset Retirement Obligations" and
     EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for
     Trading Purposes and Contracts Involved in Energy Trading and Risk
     Management Activities," effective January 1, 2003.

     /s/ Deloitte & Touche LLP


     Columbus, Ohio
     March 5, 2004

<PAGE>













                         COLUMBUS SOUTHERN POWER COMPANY
                                AND SUBSIDIARIES







<PAGE>
<TABLE>
<CAPTION>

                                                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                      SELECTED CONSOLIDATED FINANCIAL DATA

                                                   2003            2002                2001               2000             1999
                                                   ----            ----                ----               ----             ----
                                                                                  (in thousands)

           INCOME STATEMENTS DATA
-----------------------------------------
<C>                                             <C>               <C>               <C>               <C>               <C>
Operating Revenues                              $1,431,851        $1,400,160        $1,350,319        $1,304,409        $1,190,997
Operating Expenses                               1,206,365         1,180,381         1,098,142         1,108,532           968,207
                                                -----------       -----------       -----------       -----------       -----------
Operating Income                                   225,486           219,779           252,177           195,877           222,790
Nonoperating Items, Net                             (1,391)           15,263             7,738             5,153             2,709
Interest Charges                                    50,948            53,869            68,015            80,828            75,229
                                                -----------       -----------       -----------       -----------       -----------
Income Before Extraordinary Item
 and Cumulative Effect                             173,147           181,173           191,900           120,202           150,270
Extraordinary Loss (Net of Tax)                          -                 -           (30,024)          (25,236)                -

Cumulative Effect of Accounting
  Changes (Net of Tax)                              27,283                 -                 -                 -                 -
                                                -----------       -----------       -----------       -----------       -----------
Net Income                                         200,430           181,173           161,876            94,966           150,270
Preferred Stock Dividend Requirements
 (including Capital Stock Expense)                   1,016             1,365             1,890             1,783             2,131
                                                -----------       -----------       -----------       -----------       -----------
Earnings Applicable to Common Stock               $199,414          $179,808          $159,986           $93,183          $148,139
                                                ===========       ===========       ===========       ===========       ===========

           BALANCE SHEETS DATA
-----------------------------------------
Electric Utility Plant                          $3,570,443        $3,467,626        $3,354,320        $3,266,794        $3,151,619
Accumulated Depreciation                         1,389,586         1,369,153         1,283,712         1,211,728         1,129,007
                                                -----------       -----------       -----------       -----------       -----------
Net Electric Utility Plant                      $2,180,857        $2,098,473        $2,070,608        $2,055,066        $2,022,612
                                                ===========       ===========       ===========       ===========       ===========

TOTAL ASSETS                                    $2,838,366        $2,849,261        $2,815,708        $3,965,460        $2,890,610
                                                ===========       ===========       ===========       ===========       ===========

Common Stock and Paid-in Capital                  $617,426          $616,410          $615,395          $614,380          $613,899
Retained Earnings                                  326,782           290,611           176,103            99,069           246,584
Accumulated Other Comprehensive Income (Loss)      (46,327)          (59,357)                -                 -                 -
                                                -----------       -----------       -----------       -----------       -----------
Total Common Shareholder's Equity                 $897,881          $847,664          $791,498          $713,449          $860,483
                                                ===========       ===========       ===========       ===========       ===========

Cumulative Preferred Stock - Subject
 to Mandatory Redemption (a)                            $-                $-           $10,000           $15,000           $25,000
                                                ===========       ===========       ===========       ===========       ===========

Long-term Debt (a)                                $897,564          $621,626          $791,848          $899,615          $924,545
                                                ===========       ===========       ===========       ===========       ===========

Obligations Under Capital Leases (a)               $15,618           $27,610           $34,887           $42,932           $40,270
                                                ===========       ===========       ===========       ===========       ===========

TOTAL CAPITALIZATION AND LIABILITIES            $2,838,366        $2,849,261        $2,815,708        $3,965,460        $2,890,610
                                                ===========       ===========       ===========       ===========       ===========
</TABLE>

(a) Including portion due within one year.




<PAGE>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

CSPCo is a public utility engaged in the generation and purchase of electric
power, and the subsequent sale, transmission and distribution of that power to
698,000 retail customers in central and southern Ohio. As a member of the AEP
Power Pool, we share the revenues and the costs of the AEP Power Pool's sales to
neighboring utilities and power marketers.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each member's prior twelve-month peak demand relative
to the sum of the peak demands of all members as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR),
which determines each member's percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

The increase in Net Income of $19 million in 2003 compared to 2002 was primarily
due to a $32 million increase in operating revenues, a $37 million decrease in
income taxes (includes Operating Income Taxes and Nonoperating Income Tax
Expense) and a $27 million net-of-tax Cumulative Effect of Accounting Changes,
which were partially offset by a $48 million increase in fuel and purchased
power expenses and a $34 million decrease in results from risk management
activities.

Operating Income
----------------

Operating Income increased $6 million primarily due to:

  o     An increase of $27 million in Sales to AEP Affiliates and an
        increase of $34 million of wholesale sales to non-affiliates due
        primarily to an increase in sales of MWH.
  o     A decrease in Other Operation expense of $19 million primarily due
        to decreases in factored receivables expenses, AEP transmission
        equalization expenses and personal injuries and property damage
        expenses. Administrative and general salaries also decreased due
        to the impact of cost reduction efforts instituted in the fourth
        quarter of 2002 and related employment termination benefits
        recorded in 2002.
  o     Income Taxes decreased by $20 million primarily due to state income
        tax return and accrual adjustments.

The increase in Operating Income was partially offset by:

  o     A decrease of $34 million in retail revenues resulting from milder
        spring and summer weather and a sluggish economy. A decrease of
        42% in cooling degree days from the prior year was partially
        offset by a 7% increase in heating degree days.
  o     An increase of $18  million in fuel expense due to a 3% increase in
        coal costs and a 6% increase in MWH of power generation.
  o     An increase of $27 million in Purchased Electricity from AEP
        Affiliates to support wholesale sales to non-affiliated entities.
  o     An increase of $15 million in Maintenance expense due primarily to
        boiler overhaul work from scheduled and forced outages and
        increased maintenance of overhead lines resulting from severe
        storm damage.

Other Impacts on Earnings
-------------------------

Nonoperating Income decreased $36 million primarily due to lower profit from
power sold outside AEP's traditional marketing area resulting from AEP's plan to
exit risk management activities in areas outside of its traditional market area.

Nonoperating Income Tax Credit increased due to a decrease in pre-tax
nonoperating book income and changes related to consolidated tax savings.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                          Moody's         S&P       Fitch
                                          -------         ---       -----

         First Mortgage Bonds               A3            BBB         A
         Senior Unsecured Debt              A3            BBB         A-

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.

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

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

<TABLE>
<CAPTION>

                                                                        Payments Due by Period
                                                                            (in thousands)

Contractual Cash Obligations               Less Than 1 year    2-3 years      4-5 years      After 5 years       Total
----------------------------               ----------------    ---------      ---------      -------------       -----

<C>                                             <C>              <C>           <C>              <C>           <C>
Long-term Debt                                   $11,000         $36,000       $112,000         $738,564        $897,564
Advances from Affiliates                           6,517               -              -                -           6,517
Capital Lease Obligations                          4,959           6,701          3,823            2,096          17,579
Unconditional Purchase Obligations (a)            81,500           9,854              -                -          91,354
Noncancellable Operating Leases                    5,078           7,438          3,814            2,726          19,056
                                                ---------        --------      ---------        ---------     -----------
  Total                                         $109,054         $59,993       $119,637         $743,386      $1,032,070
                                                =========        ========      =========        =========     ===========
</TABLE>


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

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                            MTM Risk Management Contract Net Assets
                                                  Year Ended December 31, 2003
                                                        (in thousands)
        Domestic Power
        --------------
        <C>                                                                                                       <C>
        Beginning Balance December 31, 2002                                                                       $65,117
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                         (23,010)
        Fair Value of New Contracts When Entered Into During the Period (b)                                             -
        Net Option Premiums Paid/(Received) (c)                                                                        81
        Change in Fair Value Due to Valuation Methodology Changes                                                       -
        Effect of EITF 98-10 Rescission (d)                                                                        (3,135)
        Changes in Fair Value of Risk Management Contracts (e)                                                       (716)
        Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                        -
                                                                                                                  --------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                  38,337
        Net Cash Flow Hedge Contracts (g)                                                                             311
        DETM Assignment (h)                                                                                       (18,185)
                                                                                                                  --------
        Ending Balance December 31, 2003                                                                          $20,463
                                                                                                                  ========
</TABLE>


        (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
            includes realized gains from risk management contracts and related
            derivatives that settled during 2003 that were entered into prior to
            2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value of long-term contracts entered
            into with customers during 2003. The fair value is calculated as of
            the execution of the contract. Most of the fair value comes from
            longer term fixed price contracts with customers that seek to limit
            their risk against fluctuating energy prices. The contract prices
            are valued against market curves associated with the delivery
            location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
            premiums paid/(received) as they relate to unexercised and unexpired
            option contracts that were entered into in 2003.
        (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
            Cumulative Effect of Accounting Changes."
        (e) "Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management portfolio due to market
            fluctuations during the current period. Market fluctuations are
            attributable to various factors such as supply/demand, weather, etc.
        (f) "Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Income. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.
        (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
            Accumulated Other Comprehensive Income (Loss). (h)See Note 17
            "Related Party Transactions."

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

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

<TABLE>
<CAPTION>

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

                                                                                                                After
                                              2004           2005         2006          2007        2008        2008    Total (c)
                                              ----           ----         ----          ----        ----        -----   ---------
                                                                                   (in thousands)
<C>                                           <C>           <C>          <C>          <C>         <C>          <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                $687        $(138)         $16         $108          $-           $-        $673
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)               13,378        4,795        4,703        1,911         959            -      25,746
Prices Based on Models and Other
 Valuation Methods (b)                             (3)          20        1,866        2,157       1,984        5,894      11,918
                                              --------      -------      -------      -------     -------      -------    --------

Total                                         $14,062       $4,677       $6,585       $4,176      $2,943       $5,894     $38,337
                                              ========      =======      =======      =======     =======      =======    ========

</TABLE>

(a)  "Prices Provided by Other External Sources - OTC Broker Quotes" reflects
     information obtained from over-the-counter brokers, industry services, or
     multiple-party on-line platforms.
(b)  "Prices Based on Models and Other Valuation Methods" if there is absence of
     pricing information from external sources, modeled information is derived
     using valuation models developed by the reporting entity, reflecting when
     appropriate, option pricing theory, discounted cash flow concepts,
     valuation adjustments, etc. and may require projection of prices for
     underlying commodities beyond the period that prices are available from
     third-party sources. In addition, where external pricing information or
     market liquidity are limited, such valuations are classified as modeled.
     The determination of the point at which a market is no longer liquid for
     placing it in the Modeled category varies by market.
(c)  Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

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

                                                               Domestic
                                                                 Power
                                                               --------
                                                            (in thousands)
        Beginning Balance December 31, 2002                     $(267)
        Changes in Fair Value (a)                                 194
        Reclassifications from AOCI to Net Income (b)             275
                                                                ------
        Ending Balance December 31, 2003                        $ 202
                                                                ======

(a)      "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
(b)      "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $940 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

VaR Associated with Energy and Gas Risk Management Contracts
------------------------------------------------------------

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $336  $1,303    $546    $130           $867   $2,654    $949    $192


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $98 million and $33 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.

<PAGE>
<TABLE>
<CAPTION>


                                     COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                             CONSOLIDATED STATEMENTS OF INCOME
                                   For the Years Ended December 31, 2003, 2002 and 2001

                                                                         2003                2002                 2001
                                                                         ----                ----                 ----
                                                                                        (in thousands)
                OPERATING REVENUES
----------------------------------------------------
<C>                                                                   <C>                  <C>                   <C>
Electric Generation, Transmission and Distribution                    $1,347,482           $1,342,958            $1,282,808
Sales to AEP Affiliates                                                   84,369               57,202                67,511
                                                                      -----------          -----------           -----------
TOTAL                                                                  1,431,851            1,400,160             1,350,319
                                                                      -----------          -----------           -----------

                OPERATING EXPENSES
----------------------------------------------------
Fuel for Electric Generation                                             203,399              185,086               175,153
Purchased Electricity for Resale                                          17,730               15,023                10,957
Purchased Electricity from AEP Affiliates                                337,323              310,605               292,199
Other Operation                                                          218,466              237,802               219,497
Maintenance                                                               75,319               60,003                62,454
Depreciation and Amortization                                            135,964              131,624               127,364
Taxes Other Than Income Taxes                                            133,754              136,024               111,481
Income Taxes                                                              84,410              104,214                99,037
                                                                      -----------          -----------           -----------
TOTAL                                                                  1,206,365            1,180,381             1,098,142
                                                                      -----------          -----------           -----------

OPERATING INCOME                                                         225,486              219,779               252,177

Nonoperating Income (Loss)                                                (7,489)              28,280                34,656
Nonoperating Expenses                                                      4,650                6,228                22,995
Nonoperating Income Tax Expense (Credit)                                 (10,748)               6,789                 3,923
Interest Charges                                                          50,948               53,869                68,015
                                                                      -----------          -----------           -----------

Income Before Extraordinary Item and Cumulative Effect
 of Accounting Changes                                                   173,147              181,173               191,900
Extraordinary Loss - Discontinuance of Regulatory Accounting
 for Generation - Net of Tax (Note 2)                                          -                    -               (30,024)
Cumulative Effect of Accounting Changes (Net of Tax)                      27,283                    -                     -
                                                                      -----------          -----------           -----------

NET INCOME                                                               200,430              181,173               161,876

Preferred Stock Dividend Requirements (Including
 Capital Stock Expense)                                                    1,016                1,365                 1,890
                                                                      -----------          -----------           -----------

EARNINGS APPLICABLE TO COMMON STOCK                                     $199,414             $179,808              $159,986
                                                                      ===========          ===========           ===========

</TABLE>

The common stock of CSPCo is wholly-owned by AEP.

See Notes to Respective Financial Statements beginning on Page L-1.

<PAGE>
<TABLE>
<CAPTION>


                                            COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                        CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                   EQUITY AND COMPREHENSIVE INCOME
                                           For the Years Ended December 31, 2003, 2002 and 2001
                                                             (in thousands)


                                                                                                   Accumulated Other
                                                       Common       Paid-in          Retained        Comprehensive
                                                       Stock        Capital          Earnings        Income (Loss)         Total
                                                      -------       -------          --------      -----------------       -----
<C>                                                   <C>           <C>              <C>                <C>              <C>
DECEMBER 31, 2000                                     $41,026       $573,354          $99,069                  $-        $713,449

Common Stock Dividends Declared                                                       (82,952)                            (82,952)
Preferred Stock Dividends Declared                                                       (875)                               (875)
Capital Stock Expense                                                  1,015           (1,015)                                  -
                                                                                                                         ---------
TOTAL                                                                                                                     629,622
                                                                                                                         ---------

           COMPREHENSIVE INCOME
------------------------------------------
 NET INCOME                                                                           161,876                             161,876
                                                                                                                         ---------
 TOTAL COMPREHENSIVE INCOME                                                                                               161,876
                                                      --------      ---------        ---------         -----------       ---------

DECEMBER 31, 2001                                     $41,026       $574,369         $176,103                  $-        $791,498


Common Stock Dividends Declared                                                       (65,300)                            (65,300)
Preferred Stock Dividends Declared                                                       (350)                               (350)
Capital Stock Expense                                                  1,015           (1,015)                                  -
                                                                                                                         ---------
TOTAL                                                                                                                     725,848
                                                                                                                         ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income, Net of Taxes:
  Unrealized Loss on Cash Flow Power Hedges                                                                  (267)           (267)
  Minimum Pension Liability                                                                               (59,090)        (59,090)
 NET INCOME                                                                           181,173                             181,173
                                                                                                                         ---------
 TOTAL COMPREHENSIVE INCOME                                                                                               121,816
                                                      --------      ---------        ---------          ----------       ---------

DECEMBER 31, 2002                                     $41,026       $575,384         $290,611           $(59,357)        $847,664

Common Stock Dividends Declared                                                      (163,243)                           (163,243)
Capital Stock Expense                                                  1,016           (1,016)                                  -
                                                                                                                         ---------
TOTAL                                                                                                                     684,421
                                                                                                                         ---------

           COMPREHENSIVE INCOME
------------------------------------------
Other Comprehensive Income, Net of Taxes:
  Unrealized Gain on Cash Flow Power Hedges                                                                   469             469
  Minimum Pension Liability                                                                                12,561          12,561
 NET INCOME                                                                           200,430                             200,430
                                                                                                                         ---------
 TOTAL COMPREHENSIVE INCOME                                                                                               213,460
                                                      --------      ---------        ---------          ----------       ---------

DECEMBER 31, 2003                                     $41,026       $576,400         $326,782            $(46,327)       $897,881
                                                      ========      =========        =========          ==========       =========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                             COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                       CONSOLIDATED BALANCE SHEETS
                                                                ASSETS
                                                        December 31, 2003 and 2002

                                                                                                2003                  2002
                                                                                                ----                  ----
                                                                                                      (in thousands)
                ELECTRIC UTILITY PLANT
-----------------------------------------------------
<C>                                                                                          <C>                    <C>
Production                                                                                   $1,610,888             $1,582,627
Transmission                                                                                    425,512                413,286
Distribution                                                                                  1,253,760              1,208,255
General                                                                                         166,002                165,025
Construction Work in Progress                                                                   114,281                 98,433
                                                                                             -----------            -----------
TOTAL                                                                                         3,570,443              3,467,626
Accumulated Depreciation and Amortization                                                     1,389,586              1,369,153
                                                                                             -----------            -----------
TOTAL - NET                                                                                   2,180,857              2,098,473
                                                                                             -----------            -----------

             OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Non-Utility Property, Net                                                                        22,417                 23,680
Other Investments                                                                                 8,663                 12,079
                                                                                             -----------            -----------
TOTAL                                                                                            31,080                 35,759
                                                                                             -----------            -----------

                    CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                         4,142                  1,479
Advances to Affiliates, Net                                                                           -                 31,257
Accounts Receivable:
  Customers                                                                                      47,099                 70,704
  Affiliated Companies                                                                           68,168                 54,518
  Accrued Unbilled Revenues                                                                      23,723                 12,671
  Miscellaneous                                                                                   5,257                    867
  Allowance for Uncollectible Accounts                                                             (531)                  (634)
Fuel                                                                                             14,365                 24,844
Materials and Supplies                                                                           44,377                 40,339
Risk Management Assets                                                                           40,095                 63,197
Margin Deposits                                                                                   6,636                    824
Prepayments and Other                                                                            12,444                  6,635
                                                                                             -----------            -----------
TOTAL                                                                                           265,775                306,701
                                                                                             -----------            -----------

             DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Assets, Net                                                                16,027                 26,290
  Transition Regulatory Assets                                                                  188,532                204,961
  Unamortized Loss on Reacquired Debt                                                            13,659                  5,978
  Other                                                                                          24,966                 20,453
Long-term Risk Management Assets                                                                 39,932                 77,810
Deferred Property Taxes                                                                          62,262                 61,733
Deferred Charges                                                                                 15,276                 11,103
                                                                                             -----------            -----------
TOTAL                                                                                           360,654                408,328
                                                                                             -----------            -----------

TOTAL ASSETS                                                                                 $2,838,366             $2,849,261
                                                                                             ===========            ===========
</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                           COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED BALANCE SHEETS
                                                   CAPITALIZATION AND LIABILITIES
                                                      December 31, 2003 and 2002

                                                                                              2003                     2002
                                                                                              ----                     ----
                                                                                                      (in thousands)
                   CAPITALIZATION
-----------------------------------------------------
<C>                                                                                        <C>                     <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 24,000,000 Shares
     Outstanding - 16,410,426 Shares                                                          $41,026                 $41,026
     Paid-in Capital                                                                          576,400                 575,384
     Retained Earnings                                                                        326,782                 290,611
     Accumulated Other Comprehensive Income (Loss)                                            (46,327)                (59,357)
                                                                                           -----------             -----------
Total Common Shareholder's Equity                                                             897,881                 847,664
                                                                                           -----------             -----------
Long-term Debt:
  Nonaffiliated                                                                               886,564                 418,626
  Affiliated                                                                                        -                 160,000
                                                                                           -----------             -----------
Total Long-term Debt                                                                          886,564                 578,626
                                                                                           -----------             -----------
TOTAL                                                                                       1,784,445               1,426,290
                                                                                           -----------             -----------

                  CURRENT LIABILITIES
-----------------------------------------------------
Short-term Debt - Affiliates                                                                       -                  290,000
Long-term Debt Due Within One Year - Nonaffiliated                                             11,000                  43,000
Advances from Affiliates, Net                                                                   6,517                     -
Accounts Payable:
  General                                                                                      58,220                  89,736
  Affiliated Companies                                                                         53,572                  81,599
Customer Deposits                                                                              19,727                  14,719
Taxes Accrued                                                                                 132,853                 112,172
Interest Accrued                                                                               16,528                   9,798
Risk Management Liabilities                                                                    28,966                  46,375
Obligations Under Capital Leases                                                                4,221                   5,967
Other                                                                                          25,364                  16,104
                                                                                           -----------             -----------
TOTAL                                                                                         356,968                 709,470
                                                                                           -----------             -----------

         DEFERRED CREDITS AND OTHER LIABILITIES
-----------------------------------------------------
Deferred Income Taxes                                                                         458,498                 437,771
Regulatory Liabilities:
  Asset Removal Costs                                                                          99,119                       -
  Deferred Investment Tax Credits                                                              30,797                  33,907
Long-term Risk Management Liabilities                                                          30,598                  29,926
Obligations Under Capital Leases                                                               11,397                  21,643
Asset Retirement Obligations                                                                    8,740                       -
Deferred Credits and Other                                                                     57,804                 190,254
                                                                                           -----------             -----------
TOTAL                                                                                         696,953                 713,501
                                                                                           -----------             -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                       $2,838,366              $2,849,261
                                                                                           ===========             ===========

</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>


                                               COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             For the Years Ended December 31, 2003, 2002 and 2001

                                                                                    2003               2002                2001
                                                                                    ----               ----                ----
                                                                                                  (in thousands)
                 OPERATING ACTIVITIES
--------------------------------------------------------
<C>                                                                               <C>               <C>                   <C>
Net Income                                                                        $200,430          $181,173              $161,876
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
     Cumulative Effect of Accounting Changes                                       (27,283)               -                     -
     Depreciation and Amortization                                                 135,964           131,753               128,500
     Deferred Income Taxes                                                          (4,514)           23,292                24,108
     Deferred Investment Tax Credits                                                (3,110)           (3,269)               (4,058)
     Mark-to-Market of Risk Management Contracts                                    41,830           (16,667)              (44,680)
     Extraordinary Loss                                                                  -                -                 30,024
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                       (5,590)           (9,576)               22,538
     Fuel, Materials and Supplies                                                    6,441            (6,180)               (7,780)
     Accounts Payable                                                              (59,543)           26,949               (16,249)
     Taxes Accrued                                                                  20,681            (4,192)              (46,540)
     Interest Accrued                                                                6,730            (1,108)               (2,462)
     Deferred Property Tax                                                            (529)          (13,732)               22,920
Change in Other Assets                                                             (20,563)            5,705                   (14)
Change in Other Liabilities                                                         (8,762)          (17,148)              (34,739)
                                                                                  ---------         ---------             ---------
Net Cash Flows From Operating Activities                                           282,182           297,000               233,444
                                                                                  ---------         ---------             ---------

                  INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                         (136,291)         (136,800)             (132,532)
Proceeds from Sale of Property                                                       1,644               730                10,841
                                                                                  ---------         ---------             ---------
Net Cash Flows Used For Investing Activities                                      (134,647)         (136,070)             (121,691)
                                                                                  ---------         ---------             ---------

                 FINANCING ACTIVITIES
--------------------------------------------------------
Issuance of Long-term Debt - Affiliated                                                  -           160,000               200,000
Issuance of Long-term Debt - Nonaffiliated                                         643,097                 -                     -
Change in Advances to/from Affiliates, Net                                          37,774          (212,641)               92,652
Retirement of Long-term Debt - Nonaffiliated                                      (212,500)         (133,343)             (314,733)
Retirement of Long-term Debt - Affiliated                                         (160,000)         (200,000)                    -
Retirement of Cumulative Preferred Stock                                                 -           (10,000)               (5,000)
Change in Short-term Debt - Affiliates                                            (290,000)          290,000                     -
Dividends Paid on Common Stock                                                    (163,243)          (65,300)              (82,952)
Dividends Paid on Cumulative Preferred Stock                                             -              (525)                 (962)
                                                                                  ---------         ---------             ---------
Net Cash Flows Used For Financing Activities                                      (144,872)         (171,809)             (110,995)
                                                                                  ---------         ---------             ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                 2,663           (10,879)                  758
Cash and Cash Equivalents at Beginning of Period                                     1,479            12,358                11,600
                                                                                  ---------         ---------             ---------
Cash and Cash Equivalents at End of Period                                          $4,142            $1,479               $12,358
                                                                                  =========         =========             =========
</TABLE>


SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $42,601,000, $53,514,000
and $68,596,000 and for income taxes was $63,907,000, $117,591,000 and
$80,485,000 in 2003, 2002 and 2001, respectively. Non-cash acquisitions under
capital leases was $1,019,000 in 2001. There were no non-cash capital lease
acquisitions in 2003 or 2002.

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

<PAGE>
<TABLE>
<CAPTION>



                                          COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                             CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                   December 31, 2003 and 2002



                                                                                           2003                2002
                                                                                           ----                ----
                                                                                                (in thousands)

<C>                                                                                     <C>                <C>
COMMON SHAREHOLDER'S EQUITY                                                               $897,881           $847,664
                                                                                        -----------         ----------

PREFERRED STOCK (a)

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                        10,944            222,797
Installment Purchase Contracts                                                              91,329             91,275
Senior Unsecured Notes                                                                     795,291            147,554
Notes - Affiliated                                                                               -            160,000
Less Portion Due Within One Year                                                           (11,000)           (43,000)
                                                                                        -----------        -----------

Total Long-term Debt Excluding Portion Due Within One Year                                 886,564            578,626
                                                                                        -----------        -----------

TOTAL CAPITALIZATION                                                                    $1,784,445         $1,426,290
                                                                                        ===========        ===========
</TABLE>


(a) At December 31, 2003 and 2002 there were no shares outstanding, 2,500,000
    authorized shares at $100 par value and 7,000,000 authorized shares at $25
    par value.


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

<PAGE>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                         2003             2002
                                         ----             ----
  %Rate        Due                           (in thousands)
  -----        ---
  6.80         2003 - May 1               $-             $13,000
  6.60         2003 - August 1             -              25,000
  6.10         2003 - November 1           -               5,000
  6.55         2004 - March 1              -              26,500
  6.75         2004 - May 1                -              26,000
  8.70         2022 - July 1               -               2,000
  8.55         2022 - August 1             -              15,000
  8.40         2022 - August 15            -              14,000
  8.40         2022 - October 15           -              13,000
  7.90         2023 - May 1                -              40,000
  7.75         2023 - August 1             -              33,000
  7.60         2024 - May 1 (a)       11,000              11,000
  Unamortized Discount                   (56)               (703)
                                     --------           ---------
  Total                              $10,944            $222,797
                                     ========           =========

(a) This bond will be redeemed in May 2004 and has been classified for payment
in 2004.

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into in connection with the
issuance of pollution control revenue bonds by the Ohio Air Quality Development
Authority:

                                            2003                     2002
                                            ----                     ----
   %Rate        Due                                 (in thousands)
   -----        ---
   6.375        2020 - December 1         $48,550                   $48,550
   6.25         2020 - December 1          43,695                    43,695
   Unamortized Discount                      (916)                     (970)
                                          --------                  --------
   Total                                  $91,329                   $91,275
                                          ========                  ========

Under the terms of the Installment Purchase Contracts, CSPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at the Zimmer Plant. Interest payments are made semi-annually.

Senior Unsecured Notes outstanding were as follows:

                                              2003              2002
                                              ----              ----
 %Rate        Due                                 (in thousands)
 -----        ---
 6.85         2005 - October 3              $36,000           $36,000
 6.51         2008 - February 1              52,000            52,000
 6.55         2008 - June 26                 60,000            60,000
 4.40         2010 - December 1             150,000                 -
 5.50         2013 - March 1                250,000                 -
 6.60         2033 - March 1                250,000                 -
 Unamortized Discount                        (2,709)             (446)
                                           ---------         ---------
 Total                                     $795,291          $147,554
                                           =========         =========

Notes Payable to parent company were as follows:

                                                2003               2002
                                                ----               ----
%Rate        Due                                    (in thousands)
-----        ---
6.501%       2006 - May 15                       $-             $160,000
                                                 ===            =========


At December 31, 2003, future annual long-term debt payments are as follows:

                                                           Amount
                                                           ------
                                                       (in thousands)
                  2004                                     $11,000
                  2005                                      36,000
                  2006                                           -
                  2007                                           -
                  2008                                     112,000
                  Later Years                              742,245
                                                          ---------
                  Total Principal Amount                   901,245
                  Unamortized Discount                      (3,681)
                                                          ---------
                  Total                                   $897,564
                                                          =========

<PAGE>
<TABLE>
<CAPTION>


                                       COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                       INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to CSPCo's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to CSPCo. The footnotes begin on page L-1.

                                                                                                                     Footnote
                                                                                                                     Reference
                                                                                                                     ---------
<C>                                                                                                                  <C>
Organization and Summary of Significant Accounting Policies                                                          Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                       Note 2

Rate Matters                                                                                                         Note 4

Effects of Regulation                                                                                                Note 5

Customer Choice and Industry Restructuring                                                                           Note 6

Commitments and Contingencies                                                                                        Note 7

Guarantees                                                                                                           Note 8

Sustained Earnings Improvement Initiative                                                                            Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                               Note 10

Benefit Plans                                                                                                        Note 11

Business Segments                                                                                                    Note 12

Derivatives, Hedging and Financial Instruments                                                                       Note 13

Income Taxes                                                                                                         Note 14

Leases                                                                                                               Note 15

Financing Activities                                                                                                 Note 16

Related Party Transactions                                                                                           Note 17

Jointly Owned Electric Utility Plant                                                                                 Note 18

Unaudited Quarterly Financial Information                                                                            Note 19

</TABLE>


<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholder and Board of Directors
of Columbus Southern Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Columbus Southern Power Company and subsidiaries
as of December 31, 2003 and 2002, and the related consolidated statements of
income, changes in common shareholder's equity and comprehensive income and cash
flows for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Columbus Southern Power Company and
subsidiaries as of December 31, 2003 and 2002, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2003 in conformity with accounting principles generally accepted in the United
States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," effective January 1, 2003.


/s/ Deloitte & Touche LLP

Columbus, Ohio
March 5, 2004

<PAGE>














                         INDIANA MICHIGAN POWER COMPANY
                                AND SUBSIDIARIES







<PAGE>
<TABLE>
<CAPTION>


                                                      INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                          SELECTED CONSOLIDATED FINANCIAL DATA

                                                    2003            2002               2001            2000             1999
                                                    ----            ----               ----            ----             ----
                                                                                  (in thousands)
      INCOME STATEMENTS DATA
----------------------------------
<C>                                              <C>              <C>                <C>             <C>              <C>
Operating Revenues                               $1,595,596       $1,526,764         $1,526,997      $1,488,209       $1,351,666
Operating Expenses                                1,409,529        1,375,575          1,367,292       1,522,911        1,243,014
                                                 -----------      -----------        -----------     -----------      -----------
Operating Income (Loss)                             186,067          151,189            159,705         (34,702)         108,652
Nonoperating Items, Net                             (13,465)          16,726              9,730           9,933            4,530
Interest Charges                                     83,054           93,923             93,647         107,263           80,406
                                                 -----------      -----------        -----------     -----------      -----------
Net Income (Loss) Before Cumulative Effect
 of Accounting Change                                89,548           73,992             75,788        (132,032)          32,776
Cumulative Effect of Accounting Change
 (Net of Tax)                                        (3,160)               -                  -               -                -
                                                 -----------      -----------        -----------     -----------      -----------
Net Income (Loss)                                    86,388           73,992             75,788        (132,032)          32,776
Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                    2,509            4,601              4,621           4,624            4,885
                                                 -----------      -----------        -----------     -----------      -----------
Earnings (Loss) Applicable to
  Common Stock                                      $83,879          $69,391            $71,167       $(136,656)         $27,891
                                                 ===========      ===========        ===========     ===========      ===========

        BALANCE SHEETS DATA
----------------------------------
Electric Utility Plant                           $5,306,182       $5,029,958         $4,923,721      $4,871,473       $4,770,027
Accumulated Depreciation and
  Amortization                                    2,490,912        2,318,063          2,198,524       2,057,542        1,981,430
                                                 -----------      -----------        -----------     -----------      -----------
Net Electric Utility Plant                       $2,815,270       $2,711,895         $2,725,197      $2,813,931       $2,788,597
                                                 ===========      ===========        ===========     ===========      ===========

TOTAL ASSETS                                     $4,659,071       $4,837,732         $4,632,510      $5,997,087       $4,788,177
                                                 ===========      ===========        ===========     ===========      ===========

Common Stock and Paid-in Capital                   $915,278         $915,144           $789,800        $789,656         $789,323
Retained Earnings                                   187,875          143,996             74,605           3,443          166,389
Accumulated Other Comprehensive
 Income (Loss)                                      (25,106)         (40,487)            (3,835)              -                -
                                                 -----------      -----------        -----------     -----------      -----------
Total Common Shareholder's Equity                $1,078,047       $1,018,653           $860,570        $793,099         $955,712
                                                 ===========      ===========        ===========     ===========      ===========

Cumulative Preferred Stock:
  Not Subject to Mandatory Redemption                $8,101           $8,101             $8,736          $8,736           $9,248
  Subject to Mandatory Redemption (a)                63,445           64,945             64,945          64,945           64,945
                                                 -----------      -----------        -----------     -----------      -----------
Total Cumulative Preferred Stock                    $71,546          $73,046            $73,681         $73,681          $74,193
                                                 ===========      ===========        ===========     ===========      ===========

Long-term Debt (a)                               $1,339,359       $1,617,062         $1,652,082      $1,388,939       $1,324,326
                                                 ===========      ===========        ===========     ===========      ===========

Obligations Under Capital Leases (a)                $37,843          $50,848            $61,933        $163,173         $187,965
                                                 ===========      ===========        ===========     ===========      ===========

TOTAL CAPITALIZATION AND
 LIABILITIES                                     $4,659,071       $4,837,732         $4,632,510      $5,997,087       $4,788,177
                                                 ===========      ===========        ===========     ===========      ===========
</TABLE>

(a) Including portion due within one year.



<PAGE>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

We are a public utility engaged in the generation and purchase of electric
power, and the subsequent sale, transmission and distribution of that power to
575,000 retail customers in our service territory in northern and eastern
Indiana and a portion of southwestern Michigan. As a member of the AEP Power
Pool, we share the revenues and the costs of the AEP Power Pool's sales to
neighboring utilities and power marketers. We also sell power at wholesale to
municipalities and electric cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity revenues. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each member's prior twelve-month peak demand relative
to the sum of the peak demands of all members as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR),
which determines each member's percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

During 2003, Net Income increased $12 million including an unfavorable $3
million Cumulative Effect of Accounting Change (see Note 2). During 2003, Net
Income Before Cumulative Effect of Accounting Change increased $15 million due
to reduced financing costs and an improvement in Operating Income resulting from
higher margins on wholesale sales and lower Other Operation expense.

During 2002, Net Income decreased by $2 million due to increased operations and
maintenance costs incurred as part of planned and unplanned outages at Cook and
Rockport plants.

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

Operating Income
----------------

Operating Income increased $35 million primarily due to:

  o     Increased wholesale sales of $69 million including system and
        power optimization sales, transmission revenues and risk
        management activities reflecting availability of AEP's generation
        and market conditions.
  o     Increased Sales to AEP Affiliates of $35 million due to increased
        capacity revenue.
  o     Decreased Other Operations expense of $45 million due primarily to
        the impact of cost reduction efforts instituted in the fourth
        quarter of 2002 and related employment termination benefits of $15
        million recorded in 2002.

The increase in Operating Income was partially offset by:

  o     Decreased retail revenues of $37 million due primarily to milder
        summer weather and economic pressures on industrial customers.
        Cooling degree days declined approximately 42% this year compared
        with last year. Industrial revenues dropped 3% from prior year.
  o     Increased Fuel for Electric Generation expense of $11 million
        reflecting an increase in the average cost of fuel and increased
        coal-fired generation in 2003 as Rockport's availability
        increased.
  o     Increased Purchased Electricity from AEP Affiliates of $41 million
        due to purchasing more power from the AEP Power Pool to support
        wholesale sales to unaffiliated entities.
  o     Increased Income Tax expense of $12 million reflecting an increase
        in pre-tax operating income partially offset by temporary
        differences accounted for on a flow-through basis and tax return
        adjustments.

Other Impacts on Earnings
-------------------------

Nonoperating Income decreased $30 million primarily due to lower margins for
power sold outside of AEP's traditional market reflecting AEP's plan to exit
those risk management activities.

Nonoperating Expenses increased $16 million primarily due to a $10 million
write-down of western coal lands (see Note 10).

Nonoperating Income Taxes decreased $16 million reflecting the decrease in
pre-tax nonoperating income.

Interest Charges decreased $11 million primarily due to a reduction in
outstanding long-term debt of $255 million which was retired in May 2003 using
lower rate short-term debt.

Cumulative Effect of Accounting Change
--------------------------------------

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Note 2).

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

Operating Income
----------------

Operating Income decreased $9 million primarily due to:

  o     Decreased Sales to AEP Affiliates of $41 million reflecting less
        energy to sell due to outages. In 2002, both units of Cook plant
        were shut down for refueling and both Rockport units were down for
        planned boiler maintenance.
  o     Increased Other Operation expense of $14 million due to increased
        costs for pensions, insurance and other benefits.
  o     Increased Maintenance expense of $24 million reflecting two nuclear
        refueling outages in 2002.

The decrease in Operating Income was partially offset by:

  o     Increased Retail revenues of $35 million reflecting a 4% increase in
        sales.
  o     Decreased Fuel for Electric Generation expense of $11 million
        reflecting a decline in the average cost of fuel and decreased
        nuclear generation.
  o     An $8 million decrease in Taxes Other Than Income Taxes reflects a
        favorable tax law change in Indiana effective March 2002.
  o     Decreased Income Taxes of $15 million reflecting a decrease in pre-tax
        operating income.

Other Impacts on Earnings
-------------------------

Nonoperating Expenses decreased $10 million due to a decrease in trading
overheads and traders' incentive compensation.

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               Baa1          BBB         BBB+
         Senior Unsecured Debt              Baa2          BBB         BBB

During the first quarter of 2003, Moody's Investors Service (Moody's), Standard
& Poors (S&P) and Fitch Rating Service completed their reviews of AEP and its
rated subsidiaries. The reviews resulted in downgrades of debt ratings. The
completion of these reviews was a culmination of ratings action started during
2002.

Cash Flow
---------

Cash flows for 2003, 2002 and 2001 were as follows:
<TABLE>
<CAPTION>

                                                                              2003                 2002               2001
                                                                              ----                 ----               ----
                                                                                              (in thousands)
           <C>                                                                <C>                <C>                <C>
           Cash and cash equivalents at beginning
            of period                                                           $3,237            $16,804            $14,835
                                                                              ---------          ---------          ---------
           Cash flow from (used for):
             Operating activities                                              222,773            228,234            236,207
             Investing activities                                             (182,703)          (165,725)          (182,594)
             Financing activities                                              (39,393)           (76,076)           (51,644)
                                                                              ---------          ---------          ---------
           Net increase (decrease) in cash and cash equivalents                    677            (13,567)             1,969
                                                                              ---------          ---------          ---------
           Cash and cash equivalents at end of period                           $3,914             $3,237            $16,804
                                                                              =========          =========          =========
</TABLE>

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

Operating activities during 2003 provided $5 million less cash than during 2002
which was $8 million less than during 2001 largely due to working capital
requirements and changes in mark-to-market of risk management contracts.

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

Cash flows used for investing activities during 2003 were $183 million compared
to $166 million during 2002. The primary reason for the year-over-year variance
was increased construction expenditures of $17 million. Construction
expenditures increased $76 million comparing 2002 with 2001. In 2001, we bought
out nuclear fuel leases using $93 million of operating cash. Construction
expenditures for the nuclear plant and transmission and distribution assets are
to upgrade or replace equipment and improve reliability.

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

Financing activities for 2003 used $39 million of cash from operations primarily
to pay common dividends. During 2003, we redeemed $285 million of long-term debt
using short-term debt and refinanced $65 million of our installment purchase
contracts at lower fixed rates until October 2006.


During 2002, we redeemed $340 million of long-term debt and $145 million of
short-term debt using cash from operations, a $125 million capital contribution
from our parent company and proceeds from the issuance of $300 million of
long-term debt.

During 2001, we issued $300 million of long-term debt to reduce short-term debt.

Financing Activity
------------------

Long-term debt issuances and retirements during 2003 were:

  Issuances
  ---------
                                       Principal         Interest          Due
        Type of Debt                    Amount            Rate             Date
  ------------------------------       ---------         --------          ----
                                     (in millions)         (%)
  Installment Purchase Contracts          $25              2.625(a)        2019
  Installment Purchase Contracts           40              2.625(a)        2025
  (a) Fixed Until October 1, 2006

  Retirements
  -----------
                                       Principal         Interest          Due
        Type of Debt                    Amount            Rate             Date
  ------------------------------       ---------         --------          ----
                                     (in millions)         (%)
 First Mortgage Bonds                     $30               6.10           2003
 First Mortgage Bonds                      75               8.50           2022
 First Mortgage Bonds                      15               7.35           2023
 Junior Debentures                         40               8.00           2026
 Junior Debentures                        125               7.60           2038
 Installment Purchase Contracts            25               7.00           2015
 Installment Purchase Contracts            40               7.60           2016


Off-Balance Sheet Arrangements
------------------------------

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

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

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

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

The gain from the sale was deferred and is being amortized over the term of the
lease, which expires in 2022. The Owner Trustee owns the plant and leases it to
AEGCo and I&M. The lease is accounted for as an operating lease with the payment
obligations included in the lease footnote. The lease term is for 33 years with
potential renewal options. At the end of the lease term, AEGCo and I&M have the
option to renew the lease or the Owner Trustee can sell the plant. Neither
AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and none of
these entities guarantee its debt.

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

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


                                                               Payments Due by Period
                                                                    (in millions)

Contractual Cash Obligations           Less Than 1 year      2-3 years    4-5 years      After 5 years    Total
----------------------------           ----------------      ---------    ---------      -------------    -----

<C>                                          <C>             <C>            <C>            <C>           <C>
Long-term Debt                               $205            $365           $100             $669        $1,339
Advances from Affiliates                       99              -              -                -             99
Preferred Stock Subject to
 Mandatory Redemption                          -               -              16               47            63
Capital Lease Obligations                      10              14             16                6            46
Unconditional Purchase Obligations (a)        107              89             82              161           439
Noncancellable Operating Leases               104             191            182            1,097         1,574
                                             -----           -----          -----          -------       -------
  Total                                      $525            $659           $396           $1,980        $3,560
                                             =====           =====          =====          =======       =======
</TABLE>

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

Some of the transactions, described under "Off-Balance Sheet Arrangements"
above, have been employed for a contractual cash obligation reported in the
above table. The lease of Rockport Unit 2 is reported in Noncancellable
Operating Leases.

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

                                             MTM Risk Management Contract Net Assets
                                                  Year Ended December 31, 2003
                                                         (in thousands)
        Domestic Power
        --------------
        <C>                                                                                                       <C>
        Beginning Balance December 31, 2002                                                                       $70,861
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                         (18,666)
        Fair Value of New Contracts When Entered Into During the Period (b)                                             -
        Net Option Premiums Paid/(Received) (c)                                                                        88
        Change in Fair Value Due to Valuation Methodology Changes                                                       -
        Effect of EITF 98-10 Rescission (d)                                                                        (4,861)
        Changes in Fair Value of Risk Management Contracts (e)                                                        765
        Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                   (6,192)
                                                                                                                  --------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                  41,995
        Net Cash Flow Hedge Contracts (g)                                                                             341
        DETM Assignment (h)                                                                                       (19,932)
                                                                                                                  --------
        Ending Balance December 31, 2003                                                                          $22,404
                                                                                                                  ========
</TABLE>

        (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
            includes realized gains from risk management contracts and related
            derivatives that settled during 2003 that were entered into prior to
            2003.
        (b) The "Fair Value of New Contracts When Entered Into During the
            Period" represents the fair value of long-term contracts entered
            into with customers during 2003. The fair value is calculated as of
            the execution of the contract. Most of the fair value comes from
            longer term fixed price contracts with customers that seek to limit
            their risk against fluctuating energy prices. The contract prices
            are valued against market curves associated with the delivery
            location.
        (c) "Net Option Premiums Paid/(Received)" reflects the net option
            premiums paid/(received) as they relate to unexercised and unexpired
            option contracts that were entered into in 2003.
        (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
            Cumulative Effect of Accounting Changes."
        (e) "Changes in Fair Value of Risk Management Contracts" represents the
            fair value change in the risk management
            portfolio due to market fluctuations during the current period.
            Market fluctuations are attributable to various factors such as
            supply/demand, weather, etc.
        (f) "Change in Fair Value of Risk Management Contracts Allocated to
            Regulated Jurisdictions" relates to the net gains (losses) of those
            contracts that are not reflected in the Consolidated Statements of
            Income. These net gains (losses) are recorded as regulatory
            liabilities/assets for those subsidiaries that operate in regulated
            jurisdictions.
        (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
            Accumulated Other Comprehensive Income (Loss).
        (h) See Note 17 "Related Party Transactions."


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

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

<TABLE>
<CAPTION>


                                                   Maturity and Source of Fair Value of MTM
                                                     Risk Management Contract Net Assets
                                                Fair Value of Contracts as of December 31, 2003
                                                                                                               After
                                                    2004         2005         2006       2007        2008      2008     Total (c)
                                                    ----         ----         ----       ----        ----      -----    ---------
                                                                                    (in thousands)
<C>                                                <C>          <C>         <C>         <C>        <C>         <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                     $753       $(151)        $18        $118         $-          $-        $738
Prices Provided by Other External  Sources -
 OTC Broker Quotes (a)                              14,786       5,256       5,154       2,095      1,051           -      28,342
Prices Based on Models and Other  Valuation
 Methods (b)                                          (151)         23       2,045       2,364      2,174       6,460      12,915
                                                   --------     -------     -------     -------    -------     -------    --------
Total                                              $15,388      $5,128      $7,217      $4,577     $3,225      $6,460     $41,995
                                                   ========     =======     =======     =======    =======     =======    ========
</TABLE>

(a)  "Prices  Provided by Other External  Sources"  reflects  information
     obtained from  over-the-counter brokers, industry services, or
     multiple-party on-line platforms.
(b)  "Prices Based on Models and Other Valuation Methods" is in absence of
     pricing information from external sources, modeled information is derived
     using valuation models developed by the reporting entity, reflecting when
     appropriate, option pricing theory, discounted cash flow concepts,
     valuation adjustments, etc. and may require projection of prices for
     underlying commodities beyond the period that prices are available from
     third-party sources. In addition, where external pricing information or
     market liquidity are limited, such valuations are classified as modeled.
     The determination of the point at which a market is no longer liquid for
     placing it in the Modeled category varies by market.
(c)  Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

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

                                                               Domestic
                                                                 Power
                                                               --------
                                                            (in thousands)
         Beginning Balance December 31, 2002                    $(286)
         Changes in Fair Value (a)                                209
         Reclassifications from AOCI to Net Income (b)            299
                                                                 -----
         Ending Balance December 31, 2003                        $222
                                                                 =====

  (a)    "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
  (b)    "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,031 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

VaR Associated with Risk Management Contracts

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $368  $1,429    $598    $142           $927   $2,840   $1,016    $206


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $79 million and $85 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                        INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                              CONSOLIDATED STATEMENTS OF INCOME
                                      For the Years Ended December 31, 2003, 2002 and 2001


                                                                             2003               2002                  2001
                                                                             ----               ----                  ----
                                                                                           (in thousands)
                    OPERATING REVENUES
-------------------------------------------------------
<C>                                                                      <C>                 <C>                  <C>
Electric Generation, Transmission and Distribution                       $1,346,393          $1,312,626           $1,271,958
Sales to AEP Affiliates                                                     249,203             214,138              255,039
                                                                         -----------         -----------          -----------
TOTAL                                                                     1,595,596           1,526,764            1,526,997
                                                                         -----------         -----------          -----------

                    OPERATING EXPENSES
-------------------------------------------------------
Fuel for Electric Generation                                                250,890             239,455              250,098
Purchased Electricity for Resale                                             28,327              23,443               18,707
Purchased Electricity from AEP Affiliates                                   274,400             233,724              238,237
Other Operation                                                             417,636             462,707              449,115
Maintenance                                                                 158,281             151,602              127,263
Depreciation and Amortization                                               171,281             168,070              164,230
Taxes Other Than Income Taxes                                                57,788              57,721               65,518
Income Taxes                                                                 50,926              38,853               54,124
                                                                         -----------         -----------          -----------
TOTAL                                                                     1,409,529           1,375,575            1,367,292
                                                                         -----------         -----------          -----------

OPERATING INCOME                                                            186,067             151,189              159,705

Nonoperating Income                                                          53,928              84,084               85,673
Nonoperating Expenses                                                        77,171              61,374               70,900
Nonoperating Income Tax Expense (Credit)                                     (9,778)              5,984                5,043
Interest Charges                                                             83,054              93,923               93,647
                                                                         -----------         -----------          -----------

Net Income Before Cumulative Effect of
 Accounting Change                                                           89,548              73,992               75,788
Cumulative Effect of Accounting Change (Net of Tax)                          (3,160)                  -                    -
                                                                         -----------         -----------          -----------

NET INCOME                                                                   86,388              73,992               75,788

Preferred Stock Dividend Requirements
 (Including Capital Stock Expense)                                            2,509               4,601                4,621
                                                                         -----------         -----------          -----------

EARNINGS APPLICABLE TO COMMON STOCK                                         $83,879             $69,391              $71,167
                                                                         ===========         ===========          ===========
</TABLE>

The common stock of I&M is wholly-owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>



                                              INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                         CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                       EQUITY AND COMPREHENSIVE INCOME
                                         For the Years Ended December 31, 2003, 2002 and 2001
                                                               (in thousands)


                                                                                                   Accumulated Other
                                                        Common        Paid-in         Retained       Comprehensive
                                                        Stock         Capital         Earnings       Income (Loss)        Total
                                                        ------        -------         --------     -----------------      -----

<C>                                                     <C>           <C>             <C>               <C>             <C>
DECEMBER 31, 2000                                       $56,584       $733,072          $3,443                $-          $793,099

Preferred Stock Dividends                                                               (4,487)                             (4,487)
Capital Stock Expense                                                      144            (139)                                  5
                                                                                                                        -----------
                                                                                                                           788,617
          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Cash Flow Interest Rate Hedge                                                                          (3,835)           (3,835)
NET INCOME                                                                              75,788                              75,788
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  71,953
                                                        --------      ---------       ---------         ---------       -----------

DECEMBER 31, 2001                                       $56,584       $733,216         $74,605           $(3,835)         $860,570

Capital Contributions from Parent Company                              125,000                                             125,000
Preferred Stock Dividends                                                               (4,467)                             (4,467)
Capital Stock Expense                                                      344            (134)                                210
                                                                                                                        -----------
                                                                                                                           981,313
          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Cash Flow Interest Rate Hedge                                                                           3,835             3,835
   Unrealized Loss on Cash Flow Power Hedges                                                                (286)             (286)
   Minimum Pension Liability                                                                             (40,201)          (40,201)
NET INCOME                                                                              73,992                              73,992
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                  37,340
                                                        --------      ---------       ---------         ---------       -----------

DECEMBER 31, 2002                                       $56,584       $858,560        $143,996          $(40,487)       $1,018,653

Common Stock Dividends                                                                 (40,000)                            (40,000)
Preferred Stock Dividends                                                               (2,375)                             (2,375)
Capital Stock Expense                                                      134            (134)                                  -
                                                                                                                        -----------
                                                                                                                           976,278
          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Gain on Cash Flow Power Hedges                                                                 508               508
   Minimum Pension Liability                                                                              14,873            14,873
NET INCOME                                                                              86,388                              86,388
                                                                                                                        -----------
TOTAL COMPREHENSIVE INCOME                                                                                                 101,769
                                                        --------      ---------       ---------         ---------       -----------

DECEMBER 31, 2003                                       $56,584       $858,694        $187,875          $(25,106)       $1,078,047
                                                        ========      =========       =========         =========       ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                          INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                   CONSOLIDATED BALANCE SHEETS
                                                            ASSETS
                                                   December 31, 2003 and 2002

                                                                                                2003                     2002
                                                                                                ----                     ----
                                                                                                        (in thousands)
               ELECTRIC UTILITY PLANT
------------------------------------------------------
<C>                                                                                          <C>                      <C>
Production                                                                                   $2,878,051               $2,768,463
Transmission                                                                                  1,000,926                  971,599
Distribution                                                                                    958,966                  921,835
General (including nuclear fuel)                                                                274,283                  220,137
Construction Work in Progress                                                                   193,956                  147,924
                                                                                             -----------              -----------
TOTAL                                                                                         5,306,182                5,029,958
Accumulated Depreciation and Amortization                                                     2,490,912                2,318,063
                                                                                             -----------              -----------
TOTAL - NET                                                                                   2,815,270                2,711,895
                                                                                             -----------              -----------

           OTHER PROPERTY AND INVESTMENTS
------------------------------------------------------
Nuclear Decommissioning and Spent Nuclear Fuel
 Disposal Trust Funds                                                                           982,394                  870,754
Non-Utility Property, Net                                                                        52,303                   69,252
Other Investments                                                                                43,797                   51,689
                                                                                             -----------              -----------
TOTAL                                                                                         1,078,494                  991,695
                                                                                             -----------              -----------

                 CURRENT ASSETS
------------------------------------------------------
Cash and Cash Equivalents                                                                         3,914                    3,237
Advances to Affiliates                                                                                -                  191,226
Accounts Receivable:
  Customers                                                                                      61,084                   92,929
  Affiliated Companies                                                                          124,826                  122,489
  Accrued Unbilled Revenues                                                                       2,000                    6,511
  Miscellaneous                                                                                   4,498                    4,872
  Allowance for Uncollectible Accounts                                                             (531)                    (578)
Fuel                                                                                             33,968                   32,731
Materials and Supplies                                                                          105,328                   95,552
Risk Management Assets                                                                           44,071                   67,985
Margin Deposits                                                                                   7,245                      890
Prepayments and Other                                                                            10,673                   11,172
                                                                                             -----------              -----------
TOTAL                                                                                           397,076                  629,016
                                                                                             -----------              -----------

           DEFERRED DEBITS AND OTHER ASSETS
------------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                151,973                  163,928
  Deferred Fuel Costs                                                                                 -                   37,501
  Cook Plant Restart Costs                                                                            -                   40,000
  Incremental Nuclear Refueling Outage Expenses, Net                                             57,326                   29,572
  Other                                                                                          66,978                   77,211
Long-term Risk Management Assets                                                                 43,768                   83,265
Deferred Property Taxes                                                                          21,916                   22,271
Deferred Charges and Other Assets                                                                26,270                   51,378
                                                                                             -----------              -----------
TOTAL                                                                                           368,231                  505,126
                                                                                             -----------              -----------

TOTAL ASSETS                                                                                 $4,659,071               $4,837,732
                                                                                             ===========              ===========
</TABLE>

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





<PAGE>
<TABLE>
<CAPTION>


                                                INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                         CONSOLIDATED BALANCE SHEETS
                                                       CAPITALIZATION AND LIABILITIES
                                                         December 31, 2003 and 2002

                                                                                              2003                   2002
                                                                                              ----                   ----
                                                                                                     (in thousands)
                CAPITALIZATION
-----------------------------------------------------
<C>                                                                                         <C>                     <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 2,500,000 Shares
     Outstanding - 1,400,000 Shares                                                            $56,584                 $56,584
     Paid-in Capital                                                                           858,694                 858,560
     Retained Earnings                                                                         187,875                 143,996
     Accumulated Other Comprehensive Income (Loss)                                             (25,106)                (40,487)
                                                                                            -----------             -----------
Total Common Shareholder's Equity                                                            1,078,047               1,018,653
Cumulative Preferred Stock - Not Subject to Mandatory Redemption                                 8,101                   8,101
                                                                                            -----------             -----------
Total Shareholder's Equity                                                                   1,086,148               1,026,754
Liability for Cumulative Preferred Stock - Subject to Mandatory Redemption                   1,134,359               1,587,062
                                                                                            -----------             -----------
TOTAL                                                                                        2,283,952               2,678,761
                                                                                            -----------             -----------

              CURRENT LIABILITIES
-----------------------------------------------------

Long-term Debt Due Within One Year                                                             205,000                  30,000
Advances from Affiliates                                                                        98,822                       -
Accounts Payable:
    General                                                                                    101,776                 125,048
    Affiliated Companies                                                                        47,484                  93,608
Customer Deposits                                                                               21,955                  16,660
Taxes Accrued                                                                                   42,189                  71,559
Interest Accrued                                                                                17,963                  21,481
Risk Management Liabilities                                                                     31,898                  48,568
Obligations Under Capital Leases                                                                 6,528                   8,229
Other                                                                                           57,675                  76,162
                                                                                            -----------             -----------
TOTAL                                                                                          631,290                 491,315
                                                                                            -----------             -----------

        DEFERRED CREDITS AND OTHER LIABILITIES
-----------------------------------------------------
Deferred Income Taxes                                                                          337,376                 356,197
Regulatory Liabilities:
  Asset Removal Costs                                                                          263,015                       -
  Deferred Investment Tax Credits                                                               90,278                  97,709
  Excess ARO for Nuclear Decommissioning                                                       215,715                       -
  Other                                                                                         61,268                  65,983
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2                                     70,179                  73,885
Long-term Risk Management Liabilities                                                           33,537                  32,261
Obligations Under Capital Leases                                                                31,315                  42,619
Asset Retirement Obligations                                                                   553,219                       -
Nuclear Decommissioning                                                                              -                 620,672
Deferred Credits and Other                                                                      87,927                 378,330
                                                                                            -----------             -----------
TOTAL                                                                                        1,743,829               1,667,656
                                                                                            -----------             -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                        $4,659,071              $4,837,732
                                                                                            ===========             ===========
</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>


                                           INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                               CONSOLIDATED STATEMENTS OF CASH FLOWS
                                        For the Years Ended December 31, 2003, 2002 and 2001

                                                                                 2003                 2002                 2001
                                                                                 ----                 ----                 ----
                                                                                                (in thousands)
                OPERATING ACTIVITIES
---------------------------------------------------------------
<C>                                                                            <C>                  <C>                 <C>
Net Income                                                                      $86,388              $73,992             $75,788
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
     Impairments                                                                 10,300                    -                   -
     Cumulative Effect of Accounting Change                                       3,160                    -                   -
     Depreciation and Amortization                                              171,281              168,070             166,360
     Amortization (Deferral) of Incremental Nuclear Refueling
      Outage Expenses, Net                                                      (27,754)             (26,577)                418
     Unrecovered Fuel and Purchased Power Costs                                  37,501               37,501              37,501
     Amortization of Nuclear Outage Costs                                        40,000               40,000              40,000
     Deferred Income Taxes                                                      (14,894)             (16,921)            (29,205)
     Deferred Investment Tax Credits                                             (7,431)              (7,740)             (8,324)
     Mark-to-Market of Risk Management Contracts                                 43,938               (9,517)            (62,647)
Changes in Certain Assets and Liabilities:
     Accounts Receivable, Net                                                    34,346             (106,683)             62,769
     Fuel, Materials and Supplies                                               (11,013)              (7,854)            (19,426)
     Accounts Payable                                                           (69,396)              87,934             (60,185)
     Taxes Accrued                                                              (29,370)               1,798               1,345
Change in Other Assets                                                          (24,302)             (29,264)              2,622
Change in Other Liabilities                                                     (19,981)              23,495              29,191
                                                                               ---------            ---------           ---------
Net Cash Flows From Operating Activities                                        222,773              228,234             236,207
                                                                               ---------            ---------           ---------

               INVESTING ACTIVITIES
---------------------------------------------------------------
Construction Expenditures                                                      (184,188)            (167,484)            (91,052)
Buyout of Nuclear Fuel Leases                                                         -                    -             (92,616)
Other                                                                             1,485                1,759               1,074
                                                                               ---------            ---------           ---------
Net Cash Flows Used For Investing Activities                                   (182,703)            (165,725)           (182,594)
                                                                               ---------            ---------           ---------

               FINANCING ACTIVITIES
---------------------------------------------------------------
Capital Contributions from Parent                                                     -              125,000                   -
Issuance of Long-term Debt                                                       64,434              288,732             297,656
Retirement of Cumulative Preferred Stock                                         (1,500)                (424)                  -
Retirement of Long-term Debt                                                   (350,000)            (340,000)            (44,922)
Change in Advances to/from Affiliates, Net                                      290,048             (144,917)           (299,891)
Dividends Paid on Common Stock                                                  (40,000)                   -                   -
Dividends Paid on Cumulative Preferred Stock                                     (2,375)              (4,467)             (4,487)
                                                                               ---------            ---------           ---------
Net Cash Flows Used For Financing Activities                                    (39,393)             (76,076)            (51,644)
                                                                               ---------            ---------           ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                677              (13,567)              1,969
Cash and Cash Equivalents at Beginning of Period                                  3,237               16,804              14,835
                                                                               ---------            ---------           ---------
Cash and Cash Equivalents at End of Period                                       $3,914               $3,237             $16,804
                                                                               =========            =========           =========
</TABLE>


SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $82,593,000, $89,984,000
and $92,140,000 and for income taxes was $94,440,000, $60,523,000 and
$100,470,000 in 2003, 2002 and 2001, respectively. Non-cash acquisitions under
capital leases were $1,023,000 and $22,218,000 in 2002 and 2001, respectively.
There were no non-cash capital lease acquisitions in 2003.

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



<PAGE>
<TABLE>
<CAPTION>


                                             INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                               CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                      December 31, 2003 and 2002


                                                                                                        2003                 2002
                                                                                                        ----                 ----
                                                                                                              (in thousands)

<C>                                                                                                  <C>              <C>
COMMON SHAREHOLDER'S EQUITY                                                                          $1,078,047       $1,018,653
                                                                                                     -----------      -----------
PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares

              Call Price                                                   Shares
             December 31,          Number of Shares Redeemed             Outstanding
Series         2003 (a)            Year Ended December 31,            December 31, 2003
------      ------------         ----------------------------         -----------------
                                    2003      2002      2001
                                    ----      ----      ----

Not Subject to Mandatory Redemption - $100 Par:
4-1/8%         106.125               -         20         -                  55,369                       5,537            5,537
4.56%          102                   -          -         -                  14,412                       1,441            1,441
4.12%          102.728               -      6,326         -                  11,230                       1,123            1,123
                                                                                                     -----------      -----------
Total                                                                                                     8,101            8,101
                                                                                                     -----------      -----------

Subject to Mandatory Redemption - $100 Par(b):
5.90%  (c)                           -          -         -                 152,000                      15,200           15,200
6-1/4% (c)                           -          -         -                 192,500                      19,250           19,250
6.30%  (c)                           -          -         -                 132,450                      13,245           13,245
6-7/8% (d)                      15,000          -         -                 157,500                      15,750           17,250
                                                                                                     -----------      -----------
Total                                                                                                    63,445           64,945
                                                                                                     -----------      -----------

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                                     54,725          174,245
Installment Purchase Contracts                                                                          310,676          310,336
Senior Unsecured Notes                                                                                  747,873          747,027
Other Long-term Debt (e)                                                                                226,085          223,736
Junior Debentures                                                                                            -           161,718
Less Portion Due Within One Year                                                                       (205,000)         (30,000)
                                                                                                     -----------      -----------

Long-term Debt Excluding Portion Due Within One Year                                                  1,134,359        1,587,062
                                                                                                     -----------      -----------

TOTAL CAPITALIZATION                                                                                 $2,283,952       $2,678,761
                                                                                                     ===========      ===========

</TABLE>

(a) The cumulative preferred stock is callable at the price indicated plus
    accrued dividends.
(b) Sinking fund provisions require the redemption of 67,500 shares in each of
    2004, 2005, 2006 and 2007 and 52,500 shares in 2008. The sinking fund
    provisions of each series subject to mandatory redemption have been met by
    purchase of shares in advance of these due dates. Shares previously
    purchased may be applied to meet the sinking fund requirement.
(c) Commencing in 2004 and continuing through 2008 I&M may redeem, at $100 per
    share, 20,000 shares of the 5.90% series, 15,000 shares of the 6-1/4%
    series and 17,500 shares of the 6.30% series outstanding under sinking fund
    provisions at its option and all remaining outstanding shares must be
    redeemed not later than 2009. The series are callable beginning November 1,
    2003 for the 5.90% series, December 1, 2003 for the 6-1/4% series and March
    1, 2004 for the 6.30% series at $100 plus accrued dividends.
(d) Commencing in 2003 and continuing through the year 2007, a sinking fund
    will require the redemption of 15,000 shares each year and the redemption
    of the remaining shares outstanding on April 1, 2008, in each case at $100
    per share. Callable at $100 per share plus accrued dividends beginning
    February 1, 2003.
(e) Represents a liability for SNF disposal including interest payable to the
    DOE. See Note 7.

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

<PAGE>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                                 2003                 2002
                                                 ----                 ----
  %Rate        Due                                    (in thousands)
  -----        ---
  6.10         2003 - November 1                   $-               $30,000
  8.50         2022 - December 15                   -                75,000
  7.35         2023 - October 1                     -                15,000
  7.20         2024 - February 1               30,000 (a)            30,000
  7.50         2024 - March 1                  25,000 (a)            25,000
  Unamortized Discount                           (275)                 (755)
                                              --------             ---------
  Total                                       $54,725              $174,245
                                              ========             =========


(a) These bonds will be redeemed in April 2004 and have been classified for
payment in 2004.

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered in connection with the issuance
of pollution control revenue bonds by governmental authorities as follows:

                                                2003                2002
                                                ----                ----
   %Rate              Due                            (in thousands)
   -----              ---
City of Lawrenceburg, Indiana:

   7.00            2015 - April 1                  $-              $25,000
   (a)             2019 - October 1            25,000                    -
   5.90            2019 - November 1           52,000               52,000

City of Rockport, Indiana:
   7.60            2016 - March 1                   -               40,000
   (a)             2025 - April 1              40,000                    -
   6.55            2025 - June 1               50,000               50,000
   (b)             2025 - June 1               50,000               50,000
   4.90(c)         2025 - June 1               50,000               50,000

City of Sullivan, Indiana:
   5.95            2009 - May 1                45,000               45,000
   Unamortized Discount                        (1,324)              (1,664)
                                             ---------            ---------
   Total                                     $310,676             $310,336
                                             =========            =========

(a)   Rate is an annual long-term fixed rate of 2.625% through October 1, 2006.
      After that date the rate may be a daily or weekly reset rate, commercial
      paper, auction or other long-term rate as designated by I&M (fixed rate
      bonds).
(b)   In 2001, an auction rate was established. Auction rates are determined by
      standard procedures every 35 days. The auction rate for 2003 ranged from
      0.85% to 1.35% and averaged 1.05%. The auction rate for 2002 ranged from
      1.3% to 1.7% and averaged 1.5%.
(c)   Rate is fixed until June 1, 2007 (term rate bonds).

The terms of the installment purchase contracts require I&M to pay amounts
sufficient for the cities to pay interest on and the principal of (at stated
maturities and upon mandatory redemptions) related pollution control revenue
bonds issued to finance the construction of pollution control facilities at
certain generating plants. The fixed rate bonds due 2019 and 2025 are subject to
mandatory tender for purchase on October 1, 2006. Consequently, the fixed rate
bonds have been classified for repayment purposes in 2006. The term rate bonds
due 2025 are subject to mandatory tender for purchase on the term maturity date
(June 1, 2007). Accordingly, the term rate bonds have been classified for
repayment purposes in 2007 (the term end date). Interest payments range from
every 35 days to semi-annually.

Senior Unsecured Notes outstanding were as follows:

                                                 2003                 2002
                                                 ----                 ----
  %Rate        Due                                    (in thousands)
  -----        ---
  6-7/8        2004 - July 1                  $150,000             $150,000
  6.125        2006 - December 15              300,000              300,000
  6.45         2008 - November 10               50,000               50,000
  6.375        2012 - November 1               100,000              100,000
  6.00         2032 - December 31              150,000              150,000
  Unamortized Discount                          (2,127)              (2,973)
                                              ---------            ---------
  Total                                       $747,873             $747,027
                                              =========            =========

Junior Debentures outstanding were as follows:

                                                 2003                 2002
                                                 ----                 ----
  %Rate        Due                                     (in thousands)
  -----        ---
  8.00         2026 - March 31                    $-                $40,000
  7.60         2038 - June 30                      -                125,000
  Unamortized Discount                             -                 (3,282)
                                                -----              ---------
  Total                                         $  -               $161,718
                                                =====              =========

At December 31, 2003 future annual long-term debt payments are as follows:

                                                   Amount
                                                   ------
                                               (in thousands)
    2004                                           $205,000
    2005                                                  -
    2006                                            365,000
    2007                                             50,000
    2008                                             50,000
    Later Years                                     673,085
                                                 -----------
    Total Principal Amount                        1,343,085
    Unamortized Discount                             (3,726)
                                                 -----------
    Total                                        $1,339,359
                                                 ===========



<PAGE>
<TABLE>
<CAPTION>


                                    INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                   INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to I&M's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to I&M. The footnotes begin on page L-1.

                                                                                                                       Footnote
                                                                                                                       Reference
                                                                                                                       ---------

<C>                                                                                                                    <C>
Organization and Summary of Significant Accounting Policies                                                            Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                         Note 2

Rate Matters                                                                                                           Note 4

Effects of Regulation                                                                                                  Note 5

Customer Choice and Industry Restructuring                                                                             Note 6

Commitments and Contingencies                                                                                          Note 7

Guarantees                                                                                                             Note 8

Sustained Earnings Improvement Initiative                                                                              Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                 Note 10

Benefit Plans                                                                                                          Note 11

Business Segments                                                                                                      Note 12

Derivatives, Hedging and Financial Instruments                                                                         Note 13

Income Taxes                                                                                                           Note 14

Leases                                                                                                                 Note 15

Financing Activities                                                                                                   Note 16

Related Party Transactions                                                                                             Note 17

Unaudited Quarterly Financial Information                                                                              Note 19

</TABLE>



<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Indiana Michigan Power Company and subsidiaries
as of December 31, 2003 and 2002, and the related consolidated statements of
income, changes in common shareholder's equity and comprehensive income and cash
flows for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Indiana Michigan Power Company and
subsidiaries as of December 31, 2003 and 2002, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2003 in conformity with accounting principles generally accepted in the United
States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations" and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," effective January 1, 2003.


/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004



<PAGE>















                                                  KENTUCKY POWER COMPANY



<PAGE>
<TABLE>
<CAPTION>
                                                                  KENTUCKY POWER COMPANY
                                                                 SELECTED FINANCIAL DATA

                                                         2003            2002            2001             2000             1999
                                                         ----            ----            ----             ----             ----
                                                                                    (in thousands)
           INCOME STATEMENTS DATA
--------------------------------------------
  <C>                                              <C>               <C>             <C>              <C>              <C>
  Operating Revenues                                  $416,470          $378,683        $379,025         $389,875         $358,757
  Operating Expenses                                   351,726           336,486         331,347          340,137          304,082
                                                    -----------       -----------     -----------      -----------      -----------
  Operating Income                                      64,744            42,197          47,678           49,738           54,675
  Nonoperating Items, Net                               (2,660)            5,206           1,248            2,070             (327)
  Interest Charges                                      28,620            26,836          27,361           31,045           28,918
                                                    -----------       -----------     -----------      -----------      -----------
  Income Before Cumulative Effect of
   Accounting Change                                    33,464            20,567          21,565           20,763           25,430
  Cumulative Effect of Accounting
   Change (Net of Tax)                                  (1,134)                -               -                -                -
                                                    -----------       -----------     -----------      -----------      -----------
  Net Income                                           $32,330           $20,567         $21,565          $20,763          $25,430
                                                    ===========       ===========     ===========      ===========      ===========

             BALANCE SHEETS DATA
--------------------------------------------
  Electric Utility Plant                            $1,349,746        $1,295,619      $1,128,415       $1,103,064       $1,079,048
  Accumulated Depreciation and Amortization            381,876           373,638         360,319          338,270          318,799
                                                    -----------       -----------     -----------      -----------      -----------
  Net Electric Utility Plant                          $967,870          $921,981        $768,096         $764,794         $760,249
                                                    ===========       ===========     ===========      ===========      ===========

  TOTAL ASSETS                                      $1,221,634        $1,188,342      $1,022,833       $1,516,921       $1,007,332
                                                    ===========       ===========     ===========      ===========      ===========

  Common Stock and Paid-in Capital                    $259,200          $259,200        $209,200         $209,200         $209,200
  Retained Earnings                                     64,151            48,269          48,833           57,513           67,110
  Accumulated Other Comprehensive
    Income (Loss)                                       (6,213)           (9,451)         (1,903)               -                -
                                                    -----------       -----------     -----------      -----------      -----------
  Total Common Shareholder's Equity                   $317,138          $298,018        $256,130         $266,713         $276,310
                                                    ===========       ===========     ===========      ===========      ===========

  Long-term Debt (a)                                  $487,602          $466,632        $346,093         $330,880         $365,782
                                                    ===========       ===========     ===========      ===========      ===========

  Obligations Under Capital Leases (a)                  $5,292            $7,248          $9,583          $14,184          $15,141
                                                    ===========       ===========     ===========      ===========      ===========

  TOTAL CAPITALIZATION AND LIABILITIES              $1,221,634        $1,188,342      $1,022,833       $1,516,921       $1,007,332
                                                    ===========       ===========     ===========      ===========      ===========
</TABLE>

  (a) Including portion due within one year.



<PAGE>


                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

KPCo is a public utility engaged in the generation and purchase of electric
power, and the subsequent sale, transmission and distribution of that power to
175,000 retail customers in our service territory in eastern Kentucky. As a
member of the AEP Power Pool, we share the revenues and the costs of the AEP
Power Pool's sales to neighboring utilities and power marketers. We also sell
power at wholesale to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each member's prior twelve-month peak demand relative
to the sum of the peak demands of all members as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR),
which determines each member's percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

Net Income for 2003 increased $12 million over 2002 primarily due to improved
earnings from system sales and transmission revenues, as well as decreased
employee related expenses and maintenance expenses. These improvements were
partially offset by net losses from risk management activities included in
Nonoperating Income (Expense) that exceeded net gains from risk management
activities included in Operating Income.

Operating Income
----------------

Operating Income for 2003 increased $23 million primarily due to:

  o     Increases in system sales and transmission revenues of $16 million
        and an increase in gains from risk management activities of $7 million.
  o     An increase in Sales to AEP Affiliates of $12 million due to strong
        wholesale sales by the AEP Power Pool.
  o     An increase in residential and commercial sales of $4 million over
        2002 due to the rate increase in mid 2003 to recover the cost of
        emission control equipment (see Note 4, "Rate Matters").
  o     An $8 million decrease in Maintenance expense due to planned plant
        outages in 2002. Big Sandy plant Unit 2 was down for the entire
        fourth quarter of 2002 for planned boiler and electric plant
        maintenance. In addition, Big Sandy Unit 1 was down for two months
        in 2002 for boiler maintenance.
  o     A $6 million decrease in Other Operation expense primarily due to
        the impact of cost reduction efforts instituted in the fourth
        quarter of 2002 and related employment termination benefits
        recorded in 2002, partially offset by reduced gains from emission
        allowances.

The increases in Operating Income were partially offset by:

  o     A decline in industrial sales of $2 million reflecting the weak
        economy and the reduced usage by a major customer in 2003.
  o     An increase in fuel expense of $9 million due to increased generation
        based on the increased plant availability at Big Sandy in 2003.
  o     An increase in purchased power expense of $10 million necessary to
        support system sales and Sales to AEP Affiliates. In addition,
        energy purchases increased from the Rockport Plant based on plant
        availability, as required by the unit power agreement with AEGCo,
        an affiliated company. The unit power agreement with AEGCo
        provides for our purchase of 15% of the total output of the two
        unit 2,600-MW capacity Rockport Plant.
  o     An increase in Depreciation and Amortization of $6 million
        reflecting the completion and implementation of new capital
        projects in the third quarter of 2003, as well as the
        implementation of emission control equipment at the Big Sandy
        plant in the second quarter of 2003.
  o     An increase in Income Taxes of $3 million due to an increase in
        pre-tax book operating income partially offset by federal and
        state tax return adjustments.

Other Impacts on Earnings
-------------------------
Nonoperating income decreased $12 million in 2003 compared to 2002 primarily due
to lower profit from power sold outside AEP's traditional marketing area
resulting from AEP's plan to exit risk management activities in areas outside of
its traditional market area. The decrease in nonoperating income was partially
offset by a $4 million decrease in nonoperating income taxes resulting primarily
from the reduced pre-tax nonoperating book income. Interest Charges increased $2
million primarily due to an increase in outstanding debt partially offset by
lower market interest rates on newly issued debt.

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         Senior Unsecured Debt              Baa2          BBB         BBB

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002.

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

<TABLE>
<CAPTION>

                                                                    Payments Due by Period
                                                                        (in thousands)

Contractual Cash Obligations               Less Than 1 year      2-3 years      4-5 years      After 5 years     Total
----------------------------               ----------------      ---------      ---------      -------------     -----

<C>                                              <C>              <C>           <C>              <C>           <C>
Long-term Debt                                        $-          $60,000       $352,964         $74,638       $487,602
Advances from Affiliates                          38,096               -              -                -         38,096
Capital Lease Obligations                          2,107            2,597          1,041             116          5,861
Unconditional Purchase Obligations (a)            39,658           16,636              -               -         56,294
Noncancellable Operating Leases                    1,209            1,877          1,246           1,785          6,117
                                                 --------         --------      ---------        --------      ---------
  Total                                          $81,070          $81,110       $355,251         $76,539       $593,970
                                                 ========         =======       =========        ========      =========
</TABLE>

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

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------

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

<TABLE>
<CAPTION>

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

        Domestic Power
        --------------
        <C>                                                                                                           <C>
        Beginning Balance December 31, 2002                                                                           $24,998
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                              (6,682)
        Fair Value of New Contracts When Entered Into During the Period (b)                                                 -
        Net Option Premiums Paid/(Received) (c)                                                                            32
        Change in Fair Value Due to Valuation Methodology Changes                                                           -
        Effect of EITF 98-10 Rescission (d)                                                                            (1,744)
        Changes in Fair Value of Risk Management Contracts (e)                                                            461
        Changes in Fair Value Risk Management Contracts Allocated to Regulated Jurisdictions (f)                       (1,575)
                                                                                                                      --------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                      15,490
        Net Cash Flow Hedge Contracts (g)                                                                                 126
        DETM Assignment (h)                                                                                            (7,349)
                                                                                                                      --------
        Ending Balance December 31, 2003                                                                               $8,267
                                                                                                                      ========
</TABLE>

      (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
          includes realized gains from risk management contracts and related
          derivatives that settled during 2003 that were entered into prior
          to 2003.
      (b) The "Fair Value of New Contracts When Entered Into During the
          Period" represents the fair value of long-term contracts entered
          into with customers during 2003. The fair value is calculated as of
          the execution of the contract. Most of the fair value comes from
          longer term fixed price contracts with customers that seek to limit
          their risk against fluctuating energy prices. The contract prices
          are valued against market curves associated with the delivery
          location.
      (c) "Net Option Premiums Paid/(Received)" reflects the net option
          premiums paid/(received) as they relate to unexercised and
          unexpired option contracts that were entered into in 2003.
      (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
          Cumulative Effect of Accounting Changes."
      (e) "Changes in Fair Value of Risk Management Contracts" represents the
          fair value change in the risk management portfolio due to market
          fluctuations during the current period. Market fluctuations are
          attributable to various factors such as supply/demand, weather,
          etc.
      (f) "Change in Fair Value of Risk Management Contracts Allocated to
          Regulated Jurisdictions" relates to the net gains (losses) of those
          contracts that are not reflected in the Statements of Income. These
          net gains (losses) are recorded as regulatory liabilities/assets
          for those subsidiaries that operate in regulated jurisdictions.
      (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
          Accumulated Other Comprehensive Income (Loss).
      (h) See Note 17 "Related Party Transactions."

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

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

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

<TABLE>
<CAPTION>

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

                                                                                                      After
                                          2004         2005         2006        2007        2008      2008        Total (c)
                                          ----         ----         ----        ----        ----      -----       ---------
                                                                           (in thousands)
<C>                                      <C>          <C>          <C>         <C>        <C>         <C>         <C>
Prices Actively Quoted - Exchange
 Traded Contracts                          $277         $(56)          $7         $43         $-          $-         $271
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)          5,405        1,937        1,899         772        388           -       10,401
Prices Based on Models and Other
 Valuation Methods (b)                       (1)          12          754         871        801       2,381        4,818
                                         -------      -------      -------     -------    -------     -------     --------

Total                                    $5,681       $1,893       $2,660      $1,686     $1,189      $2,381      $15,490
                                         =======      =======      =======     =======    =======     =======     ========

</TABLE>


  (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
      reflects information obtained from over-the-counter brokers, industry
      services, or multiple-party on-line platforms.
  (b) "Prices Based on Models and Other Valuation Methods" is in absence of
      pricing information from external sources, modeled information is
      derived using valuation models developed by the reporting entity,
      reflecting when appropriate, option pricing theory, discounted cash
      flow concepts, valuation adjustments, etc. and may require projection
      of prices for underlying commodities beyond the period that prices are
      available from third-party sources. In addition, where external pricing
      information or market liquidity are limited, such valuations are
      classified as modeled. The determination of the point at which a market
      is no longer liquid for placing it in the Modeled category varies by
      market.
  (c) Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

<TABLE>
<CAPTION>

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

                                                                 Domestic
                                                                  Power             Interest Rate           Consolidated
                                                                 --------           -------------           ------------
                                                                                   (in thousands)
     <C>                                                          <C>                   <C>                     <C>
     Beginning Balance December 31, 2002                          $(103)                $425                    $322
     Changes in Fair Value (a)                                       75                    -                      75
     Reclassifications from AOCI to Net Income (b)                  110                  (87)                     23
                                                                  ------                -----                   -----
     Ending Balance December 31, 2003                               $82                 $338                    $420
                                                                  ======                =====                   =====
</TABLE>

  (a) "Changes in Fair Value" shows changes in the fair value of derivatives
      designated as hedging instruments in cash flow hedges during the
      reporting period not yet reclassified into net income, pending the
      hedged item's affecting net income. Amounts are reported net of related
      income taxes.
  (b) "Reclassifications from AOCI to Net Income" represents gains or losses
      from derivatives used as hedging instruments in cash flow hedges that
      were reclassified into net income during the reporting period. Amounts
      are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $466 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $136   $527    $220     $52            $333   $1,019    $364     $74

VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $29 million and $30 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                     KENTUCKY POWER COMPANY
                                                      STATEMENTS OF INCOME
                                        For the Years Ended December 31, 2003, 2002 and 2001


                                                                          2003                 2002                  2001
                                                                          ----                 ----                  ----
                                                                                        (in thousands)
                OPERATING REVENUES
-----------------------------------------------------
<C>                                                                       <C>                  <C>                 <C>
Electric Generation, Transmission and Distribution                        $376,662             $350,719            $336,659
Sales to AEP Affiliates                                                     39,808               27,964              42,366
                                                                          ---------            ---------           ---------
TOTAL                                                                      416,470              378,683             379,025
                                                                          ---------            ---------           ---------

                OPERATING EXPENSES
-----------------------------------------------------
Fuel for Electric Generation                                                74,148               65,043              70,635
Purchased Electricity for Resale                                               963                   29                  86
Purchased Electricity from AEP Affiliates                                  141,690              133,002             130,204
Other Operation                                                             47,325               52,892              58,275
Maintenance                                                                 27,328               35,089              22,444
Depreciation and Amortization                                               39,309               33,233              32,491
Taxes Other Than Income Taxes                                                8,788                8,240               7,854
Income Taxes                                                                12,175                8,958               9,358
                                                                          ---------            ---------           ---------
TOTAL                                                                      351,726              336,486             331,347
                                                                          ---------            ---------           ---------

OPERATING INCOME                                                            64,744               42,197              47,678

Nonoperating Income (Expense)                                               (4,036)               7,950              10,979
Nonoperating Expenses                                                        1,124                  840               9,047
Nonoperating Income Tax Expense (Credit)                                    (2,500)               1,904                 684
Interest Charges                                                            28,620               26,836              27,361
                                                                          ---------            ---------           ---------
Income Before Cumulative Effect of Accounting Change                        33,464               20,567              21,565
Cumulative Effect of Accounting Change (Net of Tax)                         (1,134)                   -                   -
                                                                          ---------            ---------           ---------

NET INCOME                                                                 $32,330              $20,567             $21,565
                                                                          =========            =========           =========

</TABLE>

The common stock of KPCo is wholly-owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>


                                                           KENTUCKY POWER COMPANY
                                               STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                       EQUITY AND COMPREHENSIVE INCOME
                                            For the Years Ended December 31, 2003, 2002 and 2001
                                                                (in thousands)


                                                                                                   Accumulated Other
                                                            Common       Paid-in       Retained      Comprehensive
                                                            Stock        Capital       Earnings      Income (Loss)      Total
                                                            ------       -------       --------     --------------      -----
<C>                                                        <C>           <C>           <C>               <C>           <C>
DECEMBER 31, 2000                                          $50,450       $158,750      $57,513                $-       $266,713

Common Stock Dividends                                                                 (30,245)                         (30,245)
                                                                                                                       ---------
TOTAL                                                                                                                   236,468
                                                                                                                       ---------

          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                    (1,903)        (1,903)
NET INCOME                                                                              21,565                           21,565
                                                                                                                       ---------
TOTAL COMPREHENSIVE INCOME                                                                                               19,662
                                                           --------      ---------     --------          --------      ---------


DECEMBER 31, 2001                                          $50,450       $158,750      $48,833           $(1,903)      $256,130

Capital Contribution from Parent                                           50,000                                        50,000
Common Stock Dividends                                                                 (21,131)                         (21,131)
                                                                                                                       ---------
TOTAL                                                                                                                   284,999
                                                                                                                       ---------

          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
 Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                     2,225          2,225
   Minimum Pension Liability                                                                              (9,773)        (9,773)
NET INCOME                                                                              20,567                           20,567
                                                                                                                       ---------
TOTAL COMPREHENSIVE INCOME                                                                                               13,019
                                                           --------      ---------     --------          --------      ---------

DECEMBER 31, 2002                                          $50,450       $208,750      $48,269           $(9,451)      $298,018

Common Stock Dividends                                                                 (16,448)                         (16,448)
                                                                                                                    ------------
TOTAL                                                                                                                   281,570
                                                                                                                     ----------

          COMPREHENSIVE INCOME
----------------------------------------------
Other Comprehensive Income,
  Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                        98             98
   Minimum Pension Liability                                                                               3,140          3,140
NET INCOME                                                                              32,330                           32,330
                                                                                                                       ---------
TOTAL COMPREHENSIVE INCOME                                                                                               35,568
                                                           --------      ---------     --------          --------      ---------

DECEMBER 31, 2003                                          $50,450       $208,750      $64,151           $(6,213)      $317,138
                                                           ========      =========     ========          ========      =========
</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                         KENTUCKY POWER COMPANY
                                                             BALANCE SHEETS
                                                                 ASSETS
                                                      December 31, 2003 and 2002

                                                                                                 2003                 2002
                                                                                          -----------------    -----------
                                                                                                    (in thousands)
               ELECTRIC UTILITY PLANT
--------------------------------------------------
<C>                                                                                            <C>                    <C>
Production                                                                                       $457,341               $275,121
Transmission                                                                                      381,354                373,639
Distribution                                                                                      425,688                414,281
General                                                                                            68,041                 67,449
Construction Work in Progress                                                                      17,322                165,129
                                                                                               -----------            -----------
TOTAL                                                                                           1,349,746              1,295,619
Accumulated Depreciation and Amortization                                                         381,876                373,638
                                                                                               -----------            -----------
TOTAL - NET                                                                                       967,870                921,981
                                                                                               -----------            -----------

             OTHER PROPERTY AND INVESTMENTS
--------------------------------------------------
Non-Utility Property, Net                                                                           5,423                  5,477
Other Investments                                                                                   1,022                  1,427
                                                                                               -----------            -----------
TOTAL                                                                                               6,445                  6,904
                                                                                               -----------            -----------

                   CURRENT ASSETS
--------------------------------------------------
Cash and Cash Equivalents                                                                             886                  2,304
Accounts Receivable:
  Customers                                                                                        21,177                 24,716
  Affiliated Companies                                                                             25,327                 23,802
  Accrued Unbilled Revenues                                                                         5,534                  5,301
  Miscellaneous                                                                                        97                    217
  Allowance for Uncollectible Accounts                                                               (736)                  (192)
Fuel                                                                                                9,481                 10,817
Materials and Supplies                                                                             16,585                 16,127
Accrued Tax Benefit                                                                                  -                     1,253
Risk Management Assets                                                                             16,200                 24,261
Margin Deposits                                                                                     2,660                    320
Prepayments and Other                                                                               1,696                  1,866
                                                                                               -----------            -----------
TOTAL                                                                                              98,907                110,792
                                                                                               -----------            -----------

          DEFERRED DEBITS AND OTHER ASSETS
--------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                   99,828                 87,261
  Other Regulatory Assets                                                                          13,971                 14,715
Long-term Risk Management Assets                                                                   16,134                 29,871
Deferred Property Taxes                                                                             6,847                  6,300
Other Deferred Charges                                                                             11,632                 10,518
                                                                                               -----------            -----------
TOTAL                                                                                             148,412                148,665
                                                                                               -----------            -----------

TOTAL ASSETS                                                                                   $1,221,634             $1,188,342
                                                                                               ===========            ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                            KENTUCKY POWER COMPANY
                                                                BALANCE SHEETS
                                                        CAPATALIZATION AND LIABILITIES
                                                          December 31, 2003 and 2002

                                                                                                 2003                2002
                                                                                                 ----                ----
                                                                                                       (in thousands)
                CAPITALIZATION
--------------------------------------------------
<C>                                                                                         <C>                <C>
 Common Shareholder's Equity:
   Common Stock - $50 Par Value:
     Authorized - 2,000,000 Shares
     Outstanding - 1,009,000 Shares                                                            $50,450            $50,450
     Paid-in Capital                                                                           208,750            208,750
     Retained Earnings                                                                          64,151             48,269
     Accumulated Other Comprehensive Income (Loss)                                              (6,213)            (9,451)
                                                                                            -----------        -----------
 Total Common Shareholder's Equity                                                             317,138            298,018
                                                                                            -----------        -----------
 Long-term Debt:
     Nonaffiliated                                                                             427,602            391,632
     Affiliated                                                                                 60,000             60,000
                                                                                            -----------        -----------
 Total Long-term Debt                                                                          487,602            451,632
                                                                                            -----------        -----------
 TOTAL                                                                                         804,740            749,650
                                                                                            -----------        -----------

              CURRENT LIABILITIES
--------------------------------------------------
 Long-term Debt Due Within One Year - Affiliated                                                     -             15,000
 Advances from Affiliates                                                                       38,096             23,386
 Accounts Payable:
   General                                                                                      22,802             46,515
   Affiliated Companies                                                                         22,648             44,035
 Customer Deposits                                                                               9,894              8,048
 Taxes Accrued                                                                                   7,329                  -
 Interest Accrued                                                                                6,915              6,471
 Risk Management Liabilities                                                                    11,704             17,803
 Obligations Under Capital Leases                                                                1,743              2,155
 Other                                                                                           8,628             12,167
                                                                                            -----------        -----------
 TOTAL                                                                                         129,759            175,580
                                                                                            -----------        -----------

       DEFERRED CREDITS AND OTHER LIABILITIES
--------------------------------------------------
 Deferred Income Taxes                                                                         212,121            178,313
 Regulatory Liabilities:
   Asset Removal Costs                                                                          26,140                  -
   Deferred Investment Tax Credits                                                               7,955              9,165
   Other Regulatory Liabilities                                                                 10,591             12,152
 Long-term Risk Management Liabilities                                                          12,363             11,488
 Obligations Under Capital Leases                                                                3,549              5,093
 Deferred Credits and Other                                                                     14,416             46,901
                                                                                            -----------        -----------
 TOTAL                                                                                         287,135            263,112
                                                                                            -----------        -----------

 Commitments and Contingencies (Note 7)

 TOTAL CAPITALIZATION AND LIABILITIES                                                       $1,221,634         $1,188,342
                                                                                            ===========        ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                  KENTUCKY POWER COMPANY
                                                 STATEMENTS OF CASH FLOWS
                                   For the Years Ended December 31, 2003, 2002 and 2001

                                                                                  2003            2002           2001
                                                                                  ----            ----           ----
                                                                                             (in thousands)
                 OPERATING ACTIVITIES
--------------------------------------------------------
<C>                                                                              <C>            <C>              <C>
Net Income                                                                       $32,330         $20,567         $21,565
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Cumulative Effect of Accounting Change                                          1,134               -               -
   Depreciation and Amortization                                                  39,309          33,233          32,491
   Deferred Income Taxes                                                          20,107           9,839           6,293
   Deferred Investment Tax Credits                                                (1,210)         (1,240)         (1,251)
   Deferred Fuel Costs, Net                                                          233           2,998          (4,707)
   Mark-to-Market of Risk Management Contracts                                    15,112         (12,267)         (1,454)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                        2,445          (9,332)         24,799
   Fuel, Materials and Supplies                                                      878             882          (7,658)
   Accounts Payable                                                              (45,100)         44,529         (22,942)
   Taxes Accrued                                                                   8,582         (11,558)         (1,580)
Change in Other Assets                                                           (16,588)        (21,491)         (2,762)
Change in Other Liabilities                                                        4,565          16,161          (9,446)
                                                                                 --------       ---------        --------
Net Cash Flows From Operating Activities                                          61,797          72,321          33,348
                                                                                 --------       ---------        --------

                INVESTING ACTIVITIES
--------------------------------------------------------
Construction Expenditures                                                        (81,707)       (178,700)        (37,206)
Proceeds from Sales of Property and Other                                            967             217             216
                                                                                 --------       ---------        --------
Net Cash Flow Used for Investing Activities                                      (80,740)       (178,483)        (36,990)
                                                                                 --------       ---------        --------

                FINANCING ACTIVITIES
--------------------------------------------------------
Capital Contributions from Parent Company                                              -          50,000               -
Issuance of Long-term Debt - Nonaffiliated                                        74,263         274,964               -
Issuance of Long-term Debt - Affiliated                                                -               -          75,000
Retirement of Long-term Debt - Nonaffiliated                                     (40,000)       (154,500)        (60,000)
Retirement of Long-term Debt - Affiliated                                        (15,000)              -               -
Change in Advances to/from Affiliates, Net                                        14,710         (42,814)         18,564
Dividends Paid                                                                   (16,448)        (21,131)        (30,245)
                                                                                 --------       ---------        --------
Net Cash Flows From Financing Activities                                          17,525         106,519           3,319
                                                                                 --------       ---------        --------

Net Increase (Decrease) in Cash and Cash Equivalents                              (1,418)            357            (323)
Cash and Cash Equivalents at Beginning of Period                                   2,304           1,947           2,270
                                                                                 --------       ---------        --------
Cash and Cash Equivalents at End of Period                                          $886          $2,304          $1,947
                                                                                 ========       =========        ========
</TABLE>


SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $26,988,000, $25,176,000
and $27,090,000 in 2003, 2002 and 2001, respectively. Cash (received) paid for
income taxes was $(17,574,000), $13,041,000 and $7,549,000 in 2003, 2002 and
2001, respectively. Noncash acquisitions under capital leases were $22,000 and
$817,000 in 2002 and 2001, respectively. There were no non-cash capital lease
acquisitions in 2003.

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


<PAGE>
<TABLE>
<CAPTION>



                                                       KENTUCKY POWER COMPANY
                                                    STATEMENTS OF CAPITALIZATION
                                                     December 31, 2003 and 2002




                                                                                             2003                 2002
                                                                                             ----                 ----
                                                                                                  (in thousands)

<C>                                                                                         <C>                 <C>
COMMON SHAREHOLDER'S EQUITY                                                                 $317,138            $298,018
                                                                                            ---------           ---------

LONG-TERM DEBT (See Schedule of Long-term Debt):

Senior Unsecured Notes                                                                       427,602             352,508
Notes Payable                                                                                 60,000              75,000
Junior Debentures                                                                                  -              39,124
Less Portion Due Within One Year                                                                   -             (15,000)
                                                                                            ---------           ---------

Long-term Debt Excluding Portion Due Within One Year                                         487,602             451,632
                                                                                            ---------           ---------

TOTAL CAPITALIZATION                                                                        $804,740            $749,650
                                                                                            =========           =========

</TABLE>

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

<PAGE>


                             KENTUCKY POWER COMPANY
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

Senior Unsecured Notes outstanding were as follows:

                                                    2003          2002
                                                    ----          ----
 %Rate               Due                              (in thousands)
 -----               ---
 6.91                2007 - October 1             $48,000        $48,000
 6.45                2008 - November 10            30,000         30,000
 5.50                2007 - July 1                125,000        125,000
 4.31                2007 - November 12            80,400         80,400
 4.37                2007 - December 12            69,564         69,564
 5.625               2032 - December 31            75,000              -
 Unamortized Discount                                (362)          (456)
                                                 ---------      ---------
 Total                                           $427,602       $352,508
                                                 =========      =========

Notes Payable to parent company were as follows:

                                                    2003           2002
                                                    ----           ----
 %Rate               Due                              (in thousands)
 -----               ---
 4.336               2003 - May 15                     $-        $15,000
 6.501               2006 - May 15                 60,000         60,000
                                                  --------       --------
 Total                                            $60,000        $75,000
                                                  ========       ========

Junior Debentures outstanding were as follows:

                                                     2003          2002
                                                     ----          ----
 %Rate               Due                               (in thousands)
 -----               ---
 8.72                2025 - June 30                    $-        $40,000
 Unamortized Discount                                   -           (876)
                                                       ---       --------
 Total                                                 $-        $39,124
                                                       ===       ========

Interest may be deferred and payment of principal and interest on the junior
debentures is subordinated and subject in right to the prior payment in full of
all senior indebtedness of the Company.


At December 31, 2003, future annual long-term debt payments are as follows:

                                                          Amount
                                                          ------
                                                      (in thousands)
            2004                                              $-
            2005                                               -
            2006                                          60,000
            2007                                         322,964
            2008                                          30,000
            Later Years                                   75,000
                                                        ---------
            Total Principal Amount                       487,964
            Unamortized Discount                            (362)
                                                        ---------
            Total                                       $487,602
                                                        =========
<PAGE>
<TABLE>
<CAPTION>



                                                    KENTUCKY POWER COMPANY
                                      INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to KPCo's financial statements are combined with the notes to respective financial statements for other subsidiary
registrants. Listed below are the notes that apply to KPCo. The footnotes begin on page L-1.

                                                                                                                       Footnote
                                                                                                                       Reference
                                                                                                                       ---------
<C>                                                                                                                    <C>
Organization and Summary of Significant Accounting Policies                                                            Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                         Note 2

Rate Matters                                                                                                           Note 4

Effects of Regulation                                                                                                  Note 5

Commitments and Contingencies                                                                                          Note 7

Guarantees                                                                                                             Note 8

Sustained Earnings Improvement Initiative                                                                              Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                 Note 10

Benefit Plans                                                                                                          Note 11

Business Segments                                                                                                      Note 12

Derivatives, Hedging and Financial Instruments                                                                         Note 13

Income Taxes                                                                                                           Note 14

Leases                                                                                                                 Note 15

Financing Activities                                                                                                   Note 16

Related Party Transactions                                                                                             Note 17

Unaudited Quarterly Financial Information                                                                              Note 19

</TABLE>


<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholder and Board of
Directors of Kentucky Power Company:

We have audited the accompanying balance sheets and statements of capitalization
of Kentucky Power Company as of December 31, 2003 and 2002, and the related
statements of income, changes in common shareholder's equity and comprehensive
income and cash flows for each of the three years in the period ended December
31, 2003. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2003 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted EITF
02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," effective January 1, 2003.


/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004



<PAGE>















                                              OHIO POWER COMPANY CONSOLIDATED



<PAGE>
<TABLE>
<CAPTION>

                                                              OHIO POWER COMPANY CONSOLIDATED
                                                           SELECTED CONSOLIDATED FINANCIAL DATA

                                                 2003                2002              2001             2000              1999
                                                 ----                ----              ----             ----              ----
                                                                                  (in thousands)
   INCOME STATEMENTS DATA
-------------------------------
<C>                                           <C>                <C>               <C>                <C>               <C>
Operating Revenues                            $2,244,653         $2,113,125        $2,098,105         $2,140,331        $1,978,826
Operating Expenses                             1,884,986          1,814,796         1,857,395          1,913,504         1,689,997
                                              -----------        -----------       -----------        -----------       -----------
Operating Income                                 359,667            298,329           240,710            226,827           288,829
Nonoperating Items, Net                           (2,172)             5,376            18,686             (5,004)            7,000
Interest Charges                                 106,464             83,682            93,603            119,210            83,672
                                              -----------        -----------       -----------        -----------       -----------
Income Before Extraordinary Item
 And Cumulative Effect                           251,031            220,023           165,793            102,613           212,157
Extraordinary Loss (Net of Tax)                        -                 -            (18,348)           (18,876)                -
Cumulative Effect of Accounting
 Changes (Net of Tax)                            124,632                 -                  -                  -                 -
                                              -----------        -----------       -----------        -----------       -----------
Net Income                                       375,663            220,023           147,445             83,737           212,157
Preferred Stock Dividend Requirements              1,098              1,258             1,258              1,266             1,417
                                              -----------        -----------       -----------        -----------       -----------
Earnings Applicable To Common Stock             $374,565           $218,765          $146,187            $82,471          $210,740
                                              ===========        ===========       ===========        ===========       ===========

       BALANCE SHEETS DATA
-------------------------------
Electric Utility Plant                        $6,531,315         $5,685,826        $5,390,576         $5,577,631        $5,400,917
Accumulated Depreciation                       2,485,947          2,469,837         2,360,857          2,678,606         2,540,445
                                              -----------        -----------       -----------        -----------       -----------
Net Electric Utility Plant                    $4,045,368         $3,215,989        $3,029,719         $2,899,025        $2,860,472
                                              ===========        ===========       ===========        ===========       ===========

TOTAL ASSETS                                  $5,374,518         $4,554,023        $4,485,787         $6,279,499        $4,756,425
                                              ===========        ===========       ===========        ===========       ===========

Common Stock and Paid-in Capital                $783,685           $783,684          $783,684           $783,684          $783,577
Retained Earnings                                729,147            522,316           401,297            398,086           587,424
Accumulated Other
 Comprehensive Income (Loss)                     (48,807)           (72,886)             (196)                 -                 -
                                              -----------        -----------       -----------        -----------       -----------
Total Common Shareholder's Equity             $1,464,025         $1,233,114        $1,184,785         $1,181,770        $1,371,001
                                              ===========        ===========       ===========        ===========       ===========

Cumulative Preferred Stock:
 Not Subject to Mandatory Redemption             $16,645            $16,648           $16,648            $16,648           $16,937
 Subject to Mandatory Redemption (a)               7,250              8,850             8,850              8,850             8,850
                                              -----------        -----------       -----------        -----------       -----------
Total Cumulative Preferred Stock                 $23,895            $25,498           $25,498            $25,498           $25,787
                                              ===========        ===========       ===========        ===========       ===========

Long-term Debt (a)                            $2,039,940         $1,067,314        $1,203,841         $1,195,493        $1,151,511
                                              ===========        ===========       ===========        ===========       ===========

Obligations Under Capital Leases (a)             $34,688            $65,626           $80,666           $116,581          $136,543
                                              ===========        ===========       ===========        ===========       ===========

TOTAL CAPITALIZATION AND LIABILITIES          $5,374,518         $4,554,023        $4,485,787         $6,279,499        $4,756,425
                                              ===========        ===========       ===========        ===========       ===========
</TABLE>


(a) Including portion due within one year.



<PAGE>


                         OHIO POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

OPCo is a public utility engaged in the generation and purchase of electric
power and the subsequent sale, transmission and distribution of that power to
approximately 704,000 retail customers in the northwestern, east central,
eastern and southern sections of Ohio. We also supply and market electric power
at wholesale to other electric utility companies, municipalities and electric
cooperatives. We, as a member of the AEP Power Pool, share in the revenues and
the costs of the AEP Power Pool's wholesale sales to neighboring utilities.

The cost of the AEP Power Pool's generating capacity is allocated among its
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each member's prior twelve-month peak demand relative
to the sum of the peak demands of all members as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR),
which determines each member's percentage share of revenues and costs.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Effective July 1, 2003, we consolidated JMG Funding, LP (JMG) as a result of the
implementation of FIN 46. OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's operating
lease expenses. While there was no effect to net income as a result of
consolidation, some individual income statement captions were affected. See Note
2, "New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of
Accounting Changes," and Note 15, "Leases," for further discussion of the
effects of FIN 46.

Results of Operations
---------------------

During 2003, Net Income increased $156 million including a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note
2). Income Before Cumulative Effect of Accounting Changes increased $31 million
primarily due to increased revenues which were allocated to us from sales made
to third parties by the AEP Power Pool.

During 2002, Income Before Extraordinary Item increased $54 million due to
reductions in operating expenses, predominantly fuel, and interest charges.

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

Operating Income
----------------

Operating Income increased $61 million for the year 2003 compared with 2002 due
to:

  o     A $22 million increase in revenues from non-affiliated system
        sales and a $119 million increase in Sales to AEP Affiliates. The
        increase in non-affiliated system sales is primarily the result of
        an 8.9% increase in the price per MWH in 2003. The increase in
        affiliated sales is the result of optimizing our generation
        capacity and selling our excess generated power to the AEP Power
        Pool.
  o     A $47 million decrease in Other Operation expense. This decrease
        was primarily due to a $23 million decrease in rent expense
        associated with the OPCo consolidation of JMG. OPCo now records
        the depreciation, interest and other expenses of JMG and
        eliminates operating lease expense against JMG's lease revenues
        (there was no change in overall net income due to the
        consolidation of JMG). In addition, operation expenses decreased
        due to a $7 million pre-tax adjustment to the workers'
        compensation reserve related to coal companies sold in July 2001,
        a $9 million decrease in expense related to post-employment
        benefits and an $8 million reduction in employee salary expenses.

The increase in Operating Income was partially offset by:

  o     An increase in Fuel for Electric Generation of $32 million as a
        result of a 9.7% increase in MWH generated.
  o     An increase in Purchased Electricity from AEP Affiliates of $20
        million resulting  from a 31% volume increase in MWHs purchased
        from the AEP Power Pool.
  o     A $30 million increase in Maintenance expenses. The increase in
        2003 is primarily due to increased boiler overhaul costs for
        planned and forced outages coupled with increased expense in
        maintaining overhead lines due to storm damage in Southern Ohio.
  o     An increase in Depreciation and Amortization associated with the
        OPCo consolidation of JMG. Depreciation expense related to the
        assets owned by JMG are now consolidated with OPCo.
  o     An increase in Income Taxes of $32 million as a result of an
        increase in pre-tax operating book income and tax return
        adjustments.

Other Impacts of Earnings
-------------------------

Nonoperating Income decreased $34 million for the year 2003 compared to 2002
primarily due to lower profit from power sold outside AEP's traditional
marketing area resulting from AEP's plan to exit risk management activities in
areas outside of its traditional market area.

Nonoperating Income Tax Expense decreased $26 million as a result of a decrease
in pre-tax nonoperating book income and changes related to consolidated tax
savings.

Interest charges increased $23 million due primarily to the consolidation of JMG
and its associated debt along with replacement of lower cost floating-rate
short-term debt with higher cost fixed-rate longer-term debt.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes is due to the one-time after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

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

Operating Income
----------------

Operating Income increased $58 million from the year 2001 to the year 2002
primarily due to:

  o     A $61 million increase in nonaffiliated revenues resulting from a
        39% increase in cooling degree days during the summer months along
        with a 32% increase in the heating degree days during the fall
        season. This reflects a return to more normal weather conditions
        since 2001 weather was abnormally mild.
  o     A $102 million decrease in Fuel for Electric Generation expense.
        This reflects a reduction of 19% in average cost of fuel for
        generation, offset in part by a slight increase in MWH generated.
        The decrease in fuel costs are the result of purchasing coal at
        lower prices on the open market in 2002 instead of affiliated
        company coal.

The increase in Operating Income was partially offset by:

  o     A $46 million decrease in Sales to AEP Affiliates. This decrease
        is due to a 15% decrease in price, reflective of lower average
        fuel cost, while MWH sales rose slightly.
  o     A $13 million increase in Purchased Electricity for Resale and
        Purchased Electricity from AEP Affiliates expenses. This was the
        result of an 11% increase in MWH sales and an 18% increase of MWH
        purchased from affiliates, partially offset by a decrease in
        price.
  o     A $16 million increase in Taxes Other Than Income Taxes as a
        result of increases in state excise tax created from a change in
        the base tax calculation.
  o     A $12 million increase in both federal and state tax expenses.
        Federal taxes increased due to higher pre-tax operating income
        offset in part by changes in certain book/tax timing differences
        accounted for on a flow-thru basis. State taxes increased
        predominately as a result of the State of Ohio's tax legislation
        revision involving utility deregulation.

Other Impacts on Earnings
-------------------------

Nonoperating Expenses decreased $25 million during 2002 due to reductions in
variable incentive compensation expenses associated with risk management
activities.

Nonoperating Income Tax Expense increased $20 million as a result of a favorable
tax benefit recognized in 2001 from the sale of the Ohio Coal companies.

Interest Charges decreased $10 million due primarily to a decrease in the
outstanding balances of long-term debt, the refinancing of debt at favorable
interest rates and a reduction in short-term interest rates.

Extraordinary Loss
------------------

In the second quarter of 2001, an extraordinary loss of $18 million net of tax
was recorded to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation (see Note 2).

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A-
          Senior Unsecured Debt              A3            BBB         BBB+

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The completion of this review was a culmination
of ratings action started during 2002. In March 2003, S&P lowered AEP and its
subsidiaries senior unsecured ratings from BBB+ to BBB along with the first
mortgage bonds of AEP subsidiaries.

Cash Flow
---------

Cash flows years ended December 31, 2003, 2002 and 2001 were as follows:

<TABLE>
<CAPTION>

                                                                             2003              2002               2001
                                                                             ----              ----               ----
                                                                                           (in thousands)
       <C>                                                                 <C>               <C>                <C>
       Cash and cash equivalents at beginning of period                      $5,285            $8,848            $31,393
                                                                           ---------         ---------          ---------
       Cash flows from (used for):
         Operating activities                                               373,443           478,973             86,756
         Investing activities                                              (237,011)         (348,298)          (359,908)
         Financing activities                                               (83,467)         (134,238)           250,607
                                                                           ---------         ---------          ---------
       Net increase (decrease) in cash and cash equivalents                  52,965            (3,563)           (22,545)
                                                                           ---------         ---------          ---------

       Cash and cash equivalents at end of period                           $58,250            $5,285             $8,848
                                                                           =========         =========          =========
</TABLE>


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

Cash flows from operating activities for the year 2003 decreased $106 million
compared to the year 2002 as they were adversely impacted primarily by
significant reductions of accounts payable balances partially associated with a
wind down of risk management activities in the current year.

Cash flows from operating activities for the year 2002 compared to the year 2001
increased $392 million as they were adversely impacted primarily by significant
increases in Employee Benefits and Other Noncurrent Liabilities.

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

Cash flows used for investing activities were reduced in the year 2003 compared
with the year 2002 due primarily to a $110 million decrease in construction
expenditures.

Cash flows used for investing activities remained relatively consistent from the
year 2001 to the year 2002.

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

Cash flows used for financing activities for the year of 2003 compared to the
year 2002 used $51 million less primarily due to the retirement and
restructuring of our long-term and short-term debt during 2003. We retired $300
million of Long-term Debt to Affiliated Companies and $275 million of Short-term
Debt to Affiliated Companies with the proceeds of two Senior Unsecured Notes at
$250 million each. In addition we issued two series of Senior Unsecured Notes,
each in the amount of $225 million in July 2003.

Cash flows used for financing activities for the year 2002 compared to the year
2001 increased $385 million. This is primarily due to a decrease in the change
in Advances to/from Affiliates, net during 2002.

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

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

<TABLE>
<CAPTION>


                                                                      Payments Due by Period
                                                                           (in millions)

Contractual Cash Obligations                    Less Than 1 year      2-3 years    4-5 years      After 5 years      Total
----------------------------                    ----------------      ---------    ---------      -------------      -----

<C>                                                  <C>                <C>            <C>            <C>           <C>
Long-term Debt                                         $432              $25            $73           $1,510        $2,040
Short-term Debt                                          26                -              -                -            26
Preferred Stock Subject to Mandatory Redemption           2                4              1                -             7
Capital Lease Obligations                                11               16              9                5            41
Unconditional Purchase Obligations (a)                  626              917            511              578         2,632
Noncancellable Operating Leases                          13               23             22               67           125
                                                     -------            -----          -----          -------       -------
  Total                                              $1,110             $985           $616           $2,160        $4,871
                                                     =======            =====          =====          =======       =======
</TABLE>

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

In addition to the amounts disclosed in the contractual cash obligations table
above, we make additional commitments in the normal course of business. These
commitments include standby letters of credit and other commitments. Our
commitments outstanding at December 31, 2003 under these agreements are
summarized in the table below:

<TABLE>
<CAPTION>

                                                              Amount of Commitment Expiration Per Period
                                                                            (in millions)
Other Commercial Commitments                Less Than 1 year    2-3 years     4-5 years     After 5 years     Total
----------------------------                ----------------    ---------     ---------     -------------     -----

<C>                                               <C>              <C>             <C>           <C>            <C>
Standby Letters of Credit (a)                      $5               $-             $-            $-              $5
Other Commercial Commitments (b)                   14               14              -             -              28
                                                  ----             ----            ---           ---            ----
Total Commercial Commitments                      $19              $14             $-            $-             $33
                                                  ====             ====            ===           ===            ====
</TABLE>

(a)  We have issued standby letters of credit to third parties. These letters of
     credit cover gas and electricity risk management contracts, construction
     contracts, insurance programs, security deposits, debt service reserves and
     credit enhancements for issued bonds. All of these letters of credit were
     issued in the ordinary course of business. AEP holds all assets of OPCo as
     collateral. There is no recourse to third parties in the event these
     letters of credit are drawn.
(b)  We have entered into a 30-year power purchase agreement for electricity
     produced by an unaffiliated entity's three-unit natural gas fired plant.
     The plant was completed in 2002 and the agreement will terminate in 2032.
     Under the terms of the agreement, we have the option to run the plant
     until December 31, 2005, taking 100% of the power generated and making
     monthly capacity payments. The capacity payments are fixed through
     December 2005 at $1.2 million per month. For the remainder of the 30-year
     contract term, we will pay the variable costs to generate the electricity
     it purchases which could be up to 20% of the plant's capacity.

Other
-----

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

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

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

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

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

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

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

OPCo entered into an agreement with an affiliate that eliminates OPCo's market
exposure related to the PPA. AEP has guaranteed this affiliate's performance
under the agreement.

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

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

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

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

Roll-Forward of MTM Risk Management Contract Net Assets
-------------------------------------------------------

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

<TABLE>
<CAPTION>

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

        Domestic Power
        --------------

        <C>                                                                                                      <C>
        Beginning Balance December 31, 2002                                                                      $94,106
        (Gain) Loss from Contracts Realized/Settled During the Period (a)                                        (38,249)
        Fair Value of New Contracts When Entered Into During the Period (b)                                            -
        Net Option Premiums Paid/(Received) (c)                                                                      106
        Change in Fair Value Due to Valuation Methodology Changes                                                      -
        Effect of EITF 98-10 Rescission (d)                                                                       (4,159)
        Changes in Fair Value of Risk Management Contracts (e)                                                     2,134
        Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)                    -
                                                                                                                 --------
        Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                 53,938
        Net Cash Flow Hedge Contracts (g)                                                                            412
        DETM Assignment (h)                                                                                      (24,055)
                                                                                                                 --------
        Ending Balance December 31, 2003                                                                         $30,295
                                                                                                                 ========
</TABLE>


     (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
         includes realized gains from risk management contracts and related
         derivatives that settled during 2003 that were entered into prior to
         2003.
     (b) The "Fair Value of New Contracts When Entered Into During the
         Period" represents the fair value of long-term contracts entered into
         with customers during 2003. The fair value is calculated as of the
         execution of the contract. Most of the fair value comes from longer
         term fixed price contracts with customers that seek to limit their
         risk against fluctuating energy prices. The contract prices are
         valued against market curves associated with the delivery location.
     (c) "Net Option Premiums Paid/(Received)" reflects the net option
         premiums paid/(received) as they relate to unexercised and unexpired
         option contracts that were entered into in 2003.
     (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
         Cumulative Effect of Accounting Changes."
     (e) "Changes in Fair Value of Risk Management Contracts" represents the
         fair value change in the risk management portfolio due to market
         fluctuations during the current period. Market fluctuations are
         attributable to various factors such as supply/demand, weather,
         storage, etc.
     (f) "Change in Fair Value of Risk Management Contracts Allocated to
         Regulated Jurisdictions" relates to the net gains (losses) of those
         contracts that are not reflected in the Consolidated Statements of
         Income. These net gains (losses) are recorded as regulatory
         liabilities/assets for those subsidiaries that operate in regulated
         jurisdictions.
     (g) "Net Cash Flow Hedge Contracts" (pre-tax) are discussed below in
         Accumulated Other Comprehensive Income (Loss).
     (h) See Note 17 "Related Party Transactions."

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
----------------------------------------------------------------------------
The table presenting maturity and source of fair value of MTM risk management
contract net assets provides two fundamental pieces of information:

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

<TABLE>
<CAPTION>


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

                                                                                                         After
                                          2004           2005        2006        2007         2008        2008       Total (c)
                                          ----           ----        ----        ----         ----       -----       ---------
                                                                            (in thousands)
<C>                                      <C>            <C>         <C>         <C>          <C>          <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                           $908         $(183)        $22        $142           $-           $-        $889
Prices Provided by Other External
 Sources - OTC Broker Quotes (a)          20,921         6,344       6,221       2,530        1,269            -      37,285
Prices Based on Models and Other
 Valuation Methods (b)                        (4)           26       2,468       2,853        2,623        7,798      15,764
                                         --------       -------     -------     -------      -------      -------    --------

Total                                    $21,825        $6,187      $8,711      $5,525       $3,892       $7,798     $53,938
                                         ========       =======     =======     =======      =======      =======    ========
</TABLE>



 (a)     "Prices Provided by Other External Sources - OTC Broker Quotes"
         reflects information obtained from over-the-counter brokers, industry
         services, or multiple-party on-line platforms.
 (b)     "Prices Based on Models and Other Valuation Methods" is in absence of
         pricing information from external sources, modeled information is
         derived using valuation models developed by the reporting entity,
         reflecting when appropriate, option pricing theory, discounted cash
         flow concepts, valuation adjustments, etc. and may require projection
         of prices for underlying commodities beyond the period that prices are
         available from third-party sources. In addition, where external pricing
         information or market liquidity are limited, such valuations are
         classified as modeled. The determination of the point at which a market
         is no longer liquid for placing it in the Modeled category varies by
         market.
 (c)     Amounts exclude Cash Flow Hedges.


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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

<TABLE>
<CAPTION>

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

                                                       Domestic           Foreign
                                                         Power            Currency          Consolidated
                                                       --------           --------          ------------
                                                                       (in thousands)
    <C>                                                 <C>                <C>                 <C>
    Beginning Balance December 31, 2002                 $(354)             $(384)              $(738)
    Changes in Fair Value (a)                             256                  -                 256
    Reclassifications from AOCI to Net Income (b)         366                 13                 379
                                                        ------             ------              ------
    Ending Balance December 31, 2003                     $268              $(371)              $(103)
                                                        ======             ======              ======
</TABLE>


 (a)     "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
 (b)     "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $1,231 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $444  $1,724    $722    $172          $1,150   $3,521  $1,259    $255


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $214 million and $34 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                               OHIO POWER COMPANY CONSOLIDATED
                                             CONSOLIDATED STATEMENTS OF INCOME
                                   For the Years Ended December 31, 2003, 2002 and 2001

                                                                                   2003               2002              2001
                                                                                   ----               ----              ----
                                                                                                 (in thousands)
                OPERATING REVENUES
----------------------------------------------------
<C>                                                                             <C>                 <C>              <C>
Electric Generation, Transmission and Distribution                              $1,660,375          $1,647,923       $1,586,739
Sales to AEP Affiliates                                                            584,278             465,202          511,366
                                                                                -----------         -----------      -----------
TOTAL                                                                            2,244,653           2,113,125        2,098,105
                                                                                -----------         -----------      -----------

                OPERATING EXPENSES
----------------------------------------------------
Fuel for Electric Generation                                                       616,680             584,730          686,568
Purchased Electricity for Resale                                                    63,486              67,385           63,441
Purchased Electricity from AEP Affiliates                                           90,821              71,154           62,585
Other Operation                                                                    369,087             416,533          400,790
Maintenance                                                                        166,438             136,609          142,878
Depreciation and Amortization                                                      257,417             248,557          239,982
Taxes Other Than Income Taxes                                                      175,043             176,247          159,778
Income Taxes                                                                       146,014             113,581          101,373
                                                                                -----------         -----------      -----------
TOTAL                                                                            1,884,986           1,814,796        1,857,395
                                                                                -----------         -----------      -----------

OPERATING INCOME                                                                   359,667             298,329          240,710

Nonoperating Income                                                                 24,495              58,289           76,341
Nonoperating Expenses                                                               34,282              34,903           60,035
Nonoperating Income Tax Expense (Credit)                                            (7,615)             18,010           (2,380)
Interest Charges                                                                   106,464              83,682           93,603
                                                                                -----------         -----------      -----------

Income Before Extraordinary Item and Cumulative Effect                             251,031             220,023          165,793
Extraordinary Loss (Net of Tax)                                                          -                   -          (18,348)
Cumulative Effect of Accounting Changes (Net of Tax)                               124,632                   -                -
                                                                                -----------         -----------      -----------

NET INCOME                                                                         375,663             220,023          147,445

Preferred Stock Dividend Requirements                                                1,098               1,258            1,258
                                                                                -----------         -----------      -----------

EARNINGS APPLICABLE TO COMMON STOCK                                               $374,565            $218,765         $146,187
                                                                                ===========         ===========      ===========
</TABLE>

The common stock of OPCo is wholly-owned by AEP.

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

<PAGE>
<TABLE>
<CAPTION>


                                                    OHIO POWER COMPANY CONSOLIDATED
                                         CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                    EQUITY AND COMPREHENSIVE INCOME
                                         For the Years Ended December 31, 2003, 2002 and 2001
                                                              (in thousands)


                                                                                                  Accumulated Other
                                                     Common        Paid-in          Retained        Comprehensive
                                                     Stock         Capital          Earnings        Income (Loss)          Total
                                                     ------        -------          --------      ---------------          -----

<C>                                                  <C>           <C>              <C>                 <C>            <C>
DECEMBER 31, 2000                                    $321,201      $462,483         $398,086                  $-       $1,181,770

Common Stock Dividends                                                              (142,976)                            (142,976)
Preferred Stock Dividends                                                             (1,258)                              (1,258)
                                                                                                                       -----------
TOTAL                                                                                                                   1,037,536
                                                                                                                       -----------

       COMPREHENSIVE INCOME
----------------------------------------
Other Comprehensive Income (Loss)
  Net of Taxes:
    Unrealized Loss on Cash Flow Hedges                                                                     (196)            (196)
NET INCOME                                                                           147,445                              147,445
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                147,249
                                                     ---------     ---------        ---------           ---------      -----------

DECEMBER 31, 2001                                    $321,201      $462,483         $401,297               $(196)      $1,184,785
                                                     =========     =========        =========           =========      ===========

Common Stock Dividends                                                               (97,746)                             (97,746)
Preferred Stock Dividends                                                             (1,258)                              (1,258)
                                                                                                                       -----------
TOTAL                                                                                                                   1,085,781
                                                                                                                       -----------

       COMPREHENSIVE INCOME
----------------------------------------
Other Comprehensive Income (Loss)
  Net of Taxes:
    Unrealized Loss on Cash Flow Hedges                                                                     (542)            (542)
    Minimum Pension Liability                                                                            (72,148)         (72,148)
NET INCOME                                                                           220,023                              220,023
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                147,333
                                                     ---------     ---------        ---------           ---------      -----------

DECEMBER 31, 2002                                    $321,201      $462,483         $522,316            $(72,886)      $1,233,114
                                                     =========     =========        =========           =========      ===========

Common Stock Dividends                                                              (167,734)                            (167,734)
Preferred Stock Dividends                                                             (1,098)                              (1,098)
Capital Stock Gains                                                       1                                                     1
                                                                                                                       -----------
TOTAL                                                                                                                   1,064,283
                                                                                                                       -----------

       COMPREHENSIVE INCOME
----------------------------------------
Other Comprehensive Income (Loss)
  Net of Taxes:
    Unrealized Gain on Cash Flow Hedges                                                                      635              635
    Minimum Pension Liability                                                                             23,444           23,444
NET INCOME                                                                           375,663                              375,663
                                                                                                                       -----------
TOTAL COMPREHENSIVE INCOME                                                                                                399,742
                                                     ---------     ---------        ---------           ---------      -----------

DECEMBER 31, 2003                                    $321,201      $462,484         $729,147            $(48,807)      $1,464,025
                                                     =========     =========        =========           =========      ===========

</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>



                                               OHIO POWER COMPANY CONSOLIDATED
                                                 CONSOLIDATED BALANCE SHEETS
                                                          ASSETS
                                                  December 31, 2003 and 2002

                                                                                         2003                     2002
                                                                                         ----                     ----
                                                                                                (in thousands)

              ELECTRIC UTILITY PLANT
-----------------------------------------------------
<C>                                                                                   <C>                      <C>
Production                                                                            $4,029,515               $3,116,825
Transmission                                                                             938,805                  905,829
Distribution                                                                           1,156,886                1,114,600
General                                                                                  245,434                  260,153
Construction Work in Progress                                                            160,675                  288,419
                                                                                      -----------              -----------
Total                                                                                  6,531,315                5,685,826
Accumulated Depreciation and Amortization                                              2,485,947                2,469,837
                                                                                      -----------              -----------
TOTAL - NET                                                                            4,045,368                3,215,989
                                                                                      -----------              -----------

           OTHER PROPERTY AND INVESTMENTS
-----------------------------------------------------
Non-Utility Property, Net                                                                 29,291                   29,037
Other                                                                                     24,264                   32,649
                                                                                      -----------              -----------
TOTAL                                                                                     53,555                   61,686
                                                                                      -----------              -----------

                   CURRENT ASSETS
-----------------------------------------------------
Cash and Cash Equivalents                                                                 58,250                    5,285
Advances to Affiliates                                                                    67,918                        -
Accounts Receivable:
   Customers                                                                             100,960                  113,207
   Affiliated Companies                                                                  120,532                  124,244
   Miscellaneous                                                                             736                    1,174
   Allowance for Uncollectible Accounts                                                     (789)                    (909)
Fuel                                                                                      77,725                   87,409
Materials and Supplies                                                                    92,136                   85,379
Risk Management Assets                                                                    56,265                   91,872
Margin Deposits                                                                            9,296                    1,636
Prepayments and Other                                                                     33,104                   10,683
                                                                                      -----------              -----------
TOTAL                                                                                    616,133                  519,980
                                                                                      -----------              -----------

           DEFERRED DEBITS AND OTHER ASSETS
-----------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                         169,605                  165,106
  Transition Regulatory Assets                                                           310,035                  375,409
  Unamortized Loss on Reacquired Debt                                                     10,172                    4,899
  Other                                                                                   22,506                   23,227
Long-term Risk Management Assets                                                          52,825                  103,230
Deferred Property Taxes                                                                   67,469                   66,621
Deferred Charges and Other Assets                                                         26,850                   17,876
                                                                                      -----------              -----------
TOTAL                                                                                    659,462                  756,368
                                                                                      -----------              -----------

TOTAL ASSETS                                                                          $5,374,518               $4,554,023
                                                                                      ===========              ===========
</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>


                                              OHIO POWER COMPANY CONSOLIDATED
                                                CONSOLIDATED BALANCE SHEETS
                                              CAPITALIZATION AND LIABILITIES
                                                December 31, 2003 and 2002

                                                                                            2003                    2002
                                                                                            ----                    ----
                                                                                                   (in thousands)
                       CAPITALIZATION
------------------------------------------------------------------
<C>                                                                                      <C>                    <C>
Common Shareholder's Equity:
  Common Stock - No Par Value:
     Authorized - 40,000,000 Shares
     Outstanding - 27,952,473 Shares                                                       $321,201               $321,201
    Paid-in Capital                                                                         462,484                462,483
    Retained Earnings                                                                       729,147                522,316
    Accumulated Other Comprehensive Income (Loss)                                           (48,807)               (72,886)
                                                                                         -----------            -----------
Total Common Shareholder's Equity                                                         1,464,025              1,233,114
Cumulative Preferred Stock Not Subject to Mandatory Redemption                               16,645                 16,648
                                                                                         -----------            -----------
Total Shareholder's Equity                                                                1,480,670              1,249,762
Liability for Cumulative Preferred Stock Subject to Mandatory Redemption                      7,250                  8,850
Long-term Debt:
    Nonaffiliated                                                                         1,608,086                677,649
    Affiliated                                                                                    -                240,000
                                                                                         -----------            -----------
Total Long-term Debt                                                                      1,608,086                917,649
                                                                                         -----------            -----------
TOTAL                                                                                     3,096,006              2,176,261
                                                                                         -----------            -----------

Minority Interest                                                                            16,314                      -
                                                                                         -----------            -----------

                   CURRENT LIABILITIES
------------------------------------------------------------------
Short-term Debt - General                                                                    25,941                      -
Short-term Debt - Affiliates                                                                      -                275,000
Long-term Debt Due Within One Year - Nonaffiliated                                          431,854                 89,665
Long-term Debt Due Within One Year - Affiliated                                                   -                 60,000
Advances from Affiliates                                                                          -                129,979
Accounts Payable:
  General                                                                                   104,874                170,563
  Affiliated Companies                                                                      101,758                145,718
Customer Deposits                                                                            17,308                 12,969
Taxes Accrued                                                                               132,793                111,778
Interest Accrued                                                                             45,679                 18,809
Risk Management Liabilities                                                                  38,318                 61,839
Obligations Under Capital Leases                                                              9,624                 14,360
Other                                                                                        71,642                 80,608
                                                                                         -----------            -----------
TOTAL                                                                                       979,791              1,171,288
                                                                                         -----------            -----------

             DEFERRED CREDITS AND OTHER LIABILITIES
------------------------------------------------------------------
Deferred Income Taxes                                                                       933,582                794,387
Regulatory Liabilities:
  Asset Removal Costs                                                                       101,160                      -
  Deferred Investment Tax Credits                                                            15,641                 18,748
  Other                                                                                           3                  1,237
Long-term Risk Management Liabilities                                                        40,477                 39,702
Deferred Credits                                                                             23,222                 27,719
Obligations Under Capital Leases                                                             25,064                 51,266
Asset Retirement Obligations                                                                 42,656                      -
Other                                                                                       100,602                273,415
                                                                                         -----------            -----------
TOTAL                                                                                     1,282,407              1,206,474
                                                                                         -----------            -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                     $5,374,518             $4,554,023
                                                                                         ===========            ===========
</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                                     OHIO POWER COMPANY CONSOLIDATED
                                                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                                             For the Years Ended December 31, 2003, 2002 and 2001

                                                                                   2003              2002              2001
                                                                                   ----              ----              ----
                                                                                                (in thousands)
                  OPERATING ACTIVITIES
-----------------------------------------------------------
<C>                                                                              <C>               <C>               <C>
Net Income                                                                       $375,663          $220,023          $147,445
Adjustments to Reconcile Net Income to Net Cash Flows
   From Operating Activities:
      Cumulative Effect of Accounting Changes                                    (124,632)                -                 -
      Depreciation and Amortization                                               257,417           248,557           252,123
      Deferred Income Taxes                                                        24,482            46,010           215,833
      Deferred Investment Tax Credits                                              (3,107)           (3,177)           (3,289)
      Extraordinary Loss                                                                -                 -            18,348
      Mark-to-Market of Risk Management Contracts                                  60,064           (28,693)          (59,833)
Changes in Certain Assets and Liabilities:
      Accounts Receivable, Net                                                     16,335            14,571            51,640
      Fuel, Materials and Supplies                                                  2,927               704             4,852
      Accrued Utility Revenues                                                    (20,301)            3,081               264
      Prepayments and Other                                                       (13,096)            8,783            12,017
      Accounts Payable                                                           (173,218)            8,704             9,887
      Customer Deposits                                                             4,339             7,517           (34,284)
      Taxes Accrued                                                                21,015           (14,992)          (96,331)
      Interest Accrued                                                             21,533             1,130            (2,779)
      Employee Benefits and Other Noncurrent Liabilities                          (75,822)          110,298          (392,026)
      Deferred Property Taxes                                                        (855)           (1,818)           21,652
Change in Other Assets                                                            (23,302)           (7,441)           46,162
Change in Other Liabilities                                                        24,001          (134,284)         (104,925)
                                                                                 ---------         ---------         ---------
Net Cash Flows From Operating Activities                                          373,443           478,973            86,756
                                                                                 ---------         ---------         ---------

                  INVESTING ACTIVITIES
-----------------------------------------------------------
Construction Expenditures                                                        (244,312)         (354,797)         (344,571)
Proceeds from Sale of Property and Other                                            7,301             6,499            16,778
Investment in Coal Companies                                                            -                 -           (32,115)
                                                                                 ---------         ---------         ---------
Net Cash Flows Used For Investing Activities                                     (237,011)         (348,298)         (359,908)
                                                                                 ---------         ---------         ---------

                 FINANCING ACTIVITIES
-----------------------------------------------------------
Issuance of Long-term Debt                                                        988,914                 -                 -
Issuance of Long-term Debt - Affiliated                                                 -                 -           300,000
Change in Advances to/from Affiliates, Net                                       (197,897)         (170,234)          392,699
Change in Short-term Debt, Net                                                       (671)                -                 -
Change in Short-term Debt - Affiliates Net                                       (275,000)          275,000                 -
Retirement of Long-term Debt - Nonaffiliated                                     (128,378)         (140,000)         (297,858)
Retirement of Long-term Debt - Affiliated                                        (300,000)                -                 -
Retirement of Cumulative Preferred Stock                                           (1,603)                -                 -
Dividends Paid on Common Stock                                                   (167,734)          (97,746)         (142,976)
Dividends Paid on Cumulative Preferred Stock                                       (1,098)           (1,258)           (1,258)
                                                                                 ---------         ---------         ---------
Net Cash Flows From (Used For) Financing Activities                               (83,467)         (134,238)          250,607
                                                                                 ---------         ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                               52,965            (3,563)          (22,545)
Cash and Cash Equivalents at Beginning of Period                                    5,285             8,848            31,393
                                                                                 ---------         ---------         ---------
Cash and Cash Equivalents at End of Period                                        $58,250            $5,285            $8,848
                                                                                 =========         =========         =========
</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $77,170,000,
$81,041,000 and $94,747,000 and for income taxes was $98,923,000, $105,058,000
and $(22,417,000) in 2003, 2002 and 2001, respectively.

Noncash acquisitions under capital leases were $106,000 and $2,380,000 in 2002
and 2001, respectively. There were no noncash capital lease acquisitions in
2003. Noncash activity in 2003 included an increase in assets and liabilities of
$469.6 million resulting from the consolidation of JMG (see Note 2).

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

<PAGE>
<TABLE>
<CAPTION>

                                             OHIO POWER COMPANY CONSOLIDATED
                                         CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                December 31, 2003 and 2002


                                                                                                        2003              2002
                                                                                                        ----              ----

                                                                                                            (in thousands)

<C>                                                                                                  <C>              <C>
COMMON SHAREHOLDER'S EQUITY                                                                          $1,464,025       $1,233,114

PREFERRED STOCK:
$100 Par Value - Authorized 3,762,403 shares
$25 Par Value - Authorized 4,000,000 shares

                 Call Price                                                 Shares
                December 31,            Number of Shares Redeemed         Outstanding
Series            2003 (a)               Year Ended December 31,       December 31, 2003
------         ------------           ----------------------------     -----------------
                                         2003      2002      2001
                                         ----      ----      ----

Not Subject to Mandatory Redemption-$100 Par:
4.08%              $103                   -          -         -             14,595                       1,460            1,460
4.20%               103.20                -          -         -             22,824                       2,282            2,282
4.40%               104                   -          -         -             31,512                       3,151            3,151
4-1/2%              110                  23          -         -             97,523                       9,752            9,755
                                                                                                     -----------      -----------
Total                                                                                                    16,645           16,648
                                                                                                     -----------      -----------

Subject to Mandatory Redemption-$100 Par (b):
5.90% (c)           $-                    -          -         -             72,500                       7,250            7,250
6.02%                -               11,000          -         -                  -                           -            1,100
6.35%                -                5,000          -         -                  -                           -              500
                                                                                                     -----------      -----------
Total                                                                                                     7,250            8,850
                                                                                                     -----------      -----------

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                                      9,950          136,633
Installment Purchase Contracts                                                                          539,406          233,340
Senior Unsecured Notes                                                                                1,343,706          397,341
Notes Payable - Nonaffiliated                                                                           146,878                -
Notes Payable - Affiliated                                                                                    -          300,000
Less Portion Due Within One Year                                                                       (431,854)        (149,665)
                                                                                                     -----------      -----------

Long-term Debt Excluding Portion Due Within One Year                                                  1,608,086          917,649
                                                                                                     -----------      -----------

 TOTAL CAPITALIZATION                                                                                $3,096,006       $2,176,261
                                                                                                     ===========      ===========
</TABLE>


 (a) The cumulative preferred stock is callable at the price indicated plus
     accrued dividends.
 (b) Sinking fund provisions require the redemption of 35,000 shares in 2003
     and 57,500 shares in each of 2004, 2005, 2006 and 2007. The sinking fund
     provisions of each series subject to mandatory redemption have been met
     by purchase of shares in advance of the due dates. Shares previously
     purchased may be applied to the sinking fund requirement. At the company's
     option, all shares are redeemable at $100 per share plus accrued and
     unpaid dividends with at least 30 days notice beginning on or after
     November 1, 2003 for the 5.90% series, October 1, 2003 for the 6.02%
     series, and April 1, 2003 for the 6.35% series.
 (c) Commencing in 2004 and continuing through the year 2008, a sinking fund for
     the 5.90% cumulative preferred stock will require the redemption of 22,500
     shares each year and the redemption of the remaining shares outstanding on
     January 1, 2009, in each case at $100 per share. Shares previously redeemed
     may be applied to meet sinking fund requirements.

See Notes to Respective Financial Statements beginning on page L-1.
<PAGE>


                         OHIO POWER COMPANY CONSOLIDATED
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                              2003                   2002
                                              ----                   ----
 %Rate           Due                                 (in thousands)
 -----           ---
 6.75            2003 - April 1                  $-                $29,850
 6.55            2003 - October 1                 -                 27,315
 6.00            2003 - November 1                -                 12,500
 6.15            2003 - December 1                -                 20,000
 7.75            2023 - April 1                   -                  5,000
 7.375           2023 - October 1                 -                 20,250
 7.10            2023 - November 1                -                 12,000
 7.30            2024 - April 1 (a)          10,000                 10,000
 Unamortized Discount                           (50)                  (282)
                                             -------              ---------
 Total                                       $9,950               $136,633
                                             =======              =========

(a) This bond will be redeemed in April 2004 and has been classified for payment
    in 2004.

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. Certain supplemental indentures to the first mortgage lien contain
maintenance and replacement provisions requiring the deposit of cash or bonds
with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                                                  2003               2002
                                                  ----               ----
 %Rate         Due                                     (in thousands)
 -----         ---
Mason County, West Virginia:
 5.45          2016 - December 1                $50,000             $50,000

Marshall County, West Virginia:
 5.45          2014 - July 1                     50,000              50,000
 5.90          2022 - April 1                    35,000              35,000
 6.85          2022 - June 1                     50,000 (a)          50,000
 (b)           2022 - June 1                     50,000                   -

Ohio Air Quality Development Authority:
 5.15          2026 - May 1                      50,000              50,000
 5.5625        2022 - October 1                  19,565 (c)               -
 5.5625        2023 - January 1                  19,565 (c)               -
 (d)           2028 - April 1                    40,000 (c)               -
 (e)           2028 - April 1                    40,000 (c)               -
 6.3750        2029 - January 1                  51,000 (c)               -
 6.3750        2029 - April 1                    51,000 (c)               -
 (d)           2029 - April 1                    18,000 (c)               -
 (e)           2029 - April 1                    18,000 (c)               -
 Unamortized Discount                            (2,724)             (1,660)
                                               ---------           ---------
 Total                                         $539,406            $233,340
                                               =========           =========


 (a) This amount was redeemed in January 2004 using the proceeds from the
     variable interest Marshall County Installment Purchase Contract issued in
     December 2003. As a result of the early redemption, this amount is shown
     as due within one year in the debt maturity schedule.
 (b) A floating interest rate is determined daily. The rate on December 31, 2003
     was 1.29%.
 (c) Due to FIN 46, OPCo was required to consolidate JMG during the third
     quarter of 2003 (see Note 2). Prior to consolidation, payments for an
     operating lease were made to JMG based on JMG's cost of financing (both
     debt and equity). As a result of the consolidation, operating lease
     payments were not recognized and OPCo recorded JMG's debt along with
     other balance sheet and income statement items. See Note 15, "Leases,"
     for further discussion of JMG.
 (d) A floating interest rate is determined weekly. The rate on December 31,
     2003 was 1.13%.
 (e) A floating interest rate is determined weekly. The
     rate on December 31, 2003 was 1.20%

Under the terms of the installment purchase contracts, OPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants. Interest payments range from monthly to semi-annually.

Senior Unsecured Notes outstanding were as follows:

                                                   2003             2002
                                                   ----             ----
 %Rate             Due                                 (in thousands)
 -----             ---
 6.75              2004 - July 1                 $100,000         $100,000
 7.00              2004 - July 1                   75,000           75,000
 6.73              2004 - November 1               48,000           48,000
 6.24              2008 - December 4               37,225           37,225
 7-3/8             2038 - June 30 (a)             140,000          140,000
 5.50              2013 - February 15             250,000                -
 4.85              2014 - January 15              225,000                -
 6.60              2033 - February 15             250,000                -
 6.375             2033 - July 15                 225,000                -
 Unamortized Discount                              (6,519)          (2,884)
                                               -----------        ---------
 Total                                         $1,343,706         $397,341
                                               ===========        =========

(a) This note was redeemed on March 1, 2004 and has been classified for payment
in 2004.

Notes Payable to parent company were as follows:

                                                    2003             2002
                                                    ----             ----
 %Rate           Due                                    (in thousands)
 -----           ---
 4.336           2003 - May 15                         $-           $60,000
 6.501           2006 - May 15                          -           240,000
                                                    ------        ---------
 Total                                                 $-          $300,000
                                                     =====         ========

Notes Payable to third parties outstanding were as follows:

                                                    2003             2002
                                                    ----             ----
 %Rate           Due                                     (in thousands)
 -----           ---
 6.81            2008 - March 31 (a)              $24,878 (d)            $-
 6.27            2009 - March 31 (b)               41,000 (d)             -
 7.49            2009 - April 15                   70,000 (d)             -
 7.21            2009 - June 15 (c)                11,000 (d)             -
                                                 ---------               ---
 Total                                           $146,878                $-
                                                 =========               ===




(a)  The terms of this note require quarterly principal payments of $5,853,659
     per year through 2007 with the remaining $1,463,415 due at maturity. These
     payments are reflected in the debt maturity schedule.
(b)  The terms of this note require semi-annual principal payments of $3 million
     per year for the year 2004, $6.5 million per year for the years 2005 and
     2006, $12 million per year for the years 2007 and 2008 with the remaining
     amount of $1 million due at maturity. These payments are reflected in the
     debt maturity schedule.
(c)  The terms of this note require a principal payment of $4.5 million in 2008
     and the remaining amount of $6.5 million due in the year of maturity which
     is reflected in the debt maturity schedule.
(d)  Due to FIN 46, OPCo was required to consolidate JMG during the third
     quarter of 2003 (see Note 2). Prior to consolidation, payments for an
     operating lease were made to JMG based on JMG's cost of financing (both
     debt and equity). As a result of the consolidation, operating lease
     payments were not recognized and OPCo recorded JMG's debt along with other
     balance sheet and income statement items. See Note 15, "Leases," for
     further discussion of JMG.

At December 31, 2003, future annual long-term debt payments are as follows:

                                                           Amount
                                                           ------
                                                       (in thousands)
          2004                                            $431,854
          2005                                              12,354
          2006                                              12,354
          2007                                              17,853
          2008                                              55,188
          Later Years                                    1,519,630
                                                        -----------
          Total Principal Amount                         2,049,233
          Unamortized Discount                              (9,293)
                                                        -----------
          Total                                         $2,039,940
                                                        ===========



<PAGE>
<TABLE>
<CAPTION>



                                                   OHIO POWER COMPANY CONSOLIDATED
                                          INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to OPCo's financial statements are combined with the notes to respective financial statements for other subsidiary
registrants. Listed below are the notes that apply to OPCo. The footnotes begin on page L-1.

                                                                                                                       Footnote
                                                                                                                       Reference
                                                                                                                       ---------
<C>                                                                                                                    <C>
Organization and Summary of Significant Accounting Policies                                                            Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                         Note 2

Rate Matters                                                                                                           Note 4

Effects of Regulation                                                                                                  Note 5

Customer Choice and Industry Restructuring                                                                             Note 6

Commitments and Contingencies                                                                                          Note 7

Guarantees                                                                                                             Note 8

Sustained Earnings Improvement Initiative                                                                              Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                 Note 10

Benefit Plans                                                                                                          Note 11

Business Segments                                                                                                      Note 12

Derivatives, Hedging and Financial Instruments                                                                         Note 13

Income Taxes                                                                                                           Note 14

Leases                                                                                                                 Note 15

Financing Activities                                                                                                   Note 16

Related Party Transactions                                                                                             Note 17

Unaudited Quarterly Financial Information                                                                              Note 19

</TABLE>

<PAGE>




INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Ohio Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Ohio Power Company Consolidated as of December
31, 2003 and 2002, and the related consolidated statements of income, changes in
common shareholder's equity and comprehensive income and cash flows for each of
the three years in the period ended December 31, 2003. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Ohio Power Company Consolidated as
of December 31, 2003 and 2002, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2003 in
conformity with accounting principles generally accepted in the United States of
America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations," and EITF 02-3,
"Issues Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities," effective January 1, 2003.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities," effective July 1,
2003.

/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004



<PAGE>















                       PUBLIC SERVICE COMPANY OF OKLAHOMA



<PAGE>
<TABLE>
<CAPTION>

                                                  PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                        SELECTED FINANCIAL DATA

                                                   2003              2002              2001              2000              1999
                                                   ----              ----              ----              ----              ----
                                                                                  (in thousands)
       INCOME STATEMENTS DATA
--------------------------------------
<C>                                             <C>               <C>              <C>               <C>               <C>
Operating Revenues                              $1,102,822          $793,647         $957,000          $956,398          $749,390
Operating Expenses                               1,009,959           708,926          860,012           859,729           650,677
                                                -----------       -----------      -----------       -----------       -----------
Operating Income                                    92,863            84,721           96,988            96,669            98,713
Nonoperating Items, Net                              5,812            (3,239)              20             8,974               946
Interest Charges                                    44,784            40,422           39,249            38,980            38,151
                                                -----------       -----------      -----------       -----------       -----------
Net Income                                          53,891            41,060           57,759            66,663            61,508
Preferred Stock Dividend Requirements                  213               213              213               212               212
Gain on Reacquired Preferred Stock                       -                 1                -                -                  -
                                                -----------       -----------      -----------       -----------       -----------
Earnings Applicable to Common Stock                $53,678           $40,848          $57,546           $66,451           $61,296
                                                ===========       ===========      ===========       ===========       ===========

        BALANCE SHEETS DATA
--------------------------------------
Electric Utility Plant                          $2,806,396        $2,759,504       $2,695,099        $2,604,670        $2,459,705
Accumulated Depreciation and Amortization        1,069,216         1,037,222          989,426           963,176           935,946
                                                -----------       -----------      -----------       -----------       -----------
Net Electric Utility Plant                      $1,737,180        $1,722,282       $1,705,673        $1,641,494        $1,523,759
                                                ===========       ===========      ===========       ===========       ===========

TOTAL ASSETS                                    $1,970,032        $1,979,323       $1,943,928        $2,325,500        $1,703,155
                                                ===========       ===========      ===========       ===========       ===========

Common Stock and Paid-in Capital                  $387,246          $337,246         $337,246          $337,246          $337,246
Retained Earnings                                  139,604           116,474          142,994           137,688           139,237
Accumulated Other Comprehensive Income (Loss)      (43,842)          (54,473)               -                 -                 -
                                                -----------       -----------      -----------       -----------       -----------
Total Common Shareholder's Equity                 $483,008          $399,247         $480,240          $474,934          $476,483
                                                ===========       ===========      ===========       ===========       ===========

Cumulative Preferred Stock Not
  Subject to Mandatory Redemption                   $5,267            $5,267           $5,267            $5,267            $5,270
                                                ===========       ===========      ===========       ===========       ===========

Trust Preferred Securities (a)                          $-           $75,000          $75,000           $75,000           $75,000
                                                ===========       ===========      ===========       ===========       ===========

Long-term Debt (b)                                $574,298          $545,437         $451,129          $470,822          $384,516
                                                ===========       ===========      ===========       ===========       ===========

Obligations Under Capital Leases (b)                $1,010                $-               $-                $-                $-
                                                ===========       ===========      ===========       ===========       ===========

TOTAL CAPITALIZATION AND
 LIABILITIES                                    $1,970,032        $1,979,323       $1,943,928        $2,325,500        $1,703,155
                                                ===========       ===========      ===========       ===========       ===========
</TABLE>

(a) See Note 16 of the Notes to Respective Financial Statements.
(b) Including portion due within one year.


<PAGE>


                       PUBLIC SERVICE COMPANY OF OKLAHOMA
            MANAGEMENT'S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
            --------------------------------------------------------

Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation and purchase of electric power, and the subsequent sale, transmission
and distribution of that power to approximately 505,000 retail customers in
eastern and southwestern Oklahoma. As a power pool member with AEP West
companies, we share in the revenues and expenses of the power pool's sales to
neighboring utilities and power marketers. PSO also sells electric power at
wholesale to other utilities, municipalities and rural electric cooperatives.

Power pool members are compensated for energy delivered to other members based
upon the delivering members' incremental cost plus a portion of the savings
realized by the purchasing member that avoids the use of more costly
alternatives. The revenue and costs for sales to neighboring utilities and power
marketers made by AEPSC on behalf of the AEP West companies are shared among the
members based upon the relative magnitude of the energy each member provides to
make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

Net Income increased $13 million for the year. The increase for the year was due
mainly to higher retail base revenue and wholesale margins. Significant
fluctuations occurred in revenues, fuel and purchased power due to certain ICR
adjustments in 2002 and changing natural gas prices; however, operating income
was not significantly affected due to the functioning of the fuel adjustment
clause in Oklahoma.

Operating Income
----------------

Operating Income increased $8 million primarily due to:

  o     Increased wholesale margins of $9 million due to an increase in
        our allocation percentage, in AEP's Power Pool, resulting from
        increased amounts of off-system sales.
  o     Increased retail base revenue of $6 million (2%), resulting mainly
        from a 6% increase in KWH sold. Cooling degree-days decreased 3%
        while heating degree-days increased 1%.
  o     Decreased Other Operation expense of $4 million which has several
        contributing factors including administrative and support
        expenses, outside services and related expenses.
  o     Decreased Taxes Other Than Income Taxes of $2 million due primarily to
        decreased franchise taxes.

The increase in Operating Income was partially offset by:

  o     Increased Maintenance expense of $5 million due mainly to increased
        plant maintenance and tree trimming.
  o     Increased Income Taxes of $13 million due to an increase in pre-tax
        operating income and increases in tax return and tax accrual
        adjustments.

Other Impacts on Earnings
-------------------------

Nonoperating Income increased $6 million primarily due to higher margins from
risk management activities and gains on the disposition of excess land.

Nonoperating Expenses decreased $6 million due to the 2002 write-down of certain
non-utility investments.

Interest Charges increased $4 million as a result of replacing floating rate
short-term debt with long-term fixed rate unsecured debt.

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                             Moody's       S&P         Fitch
                                             -------       ---         -----
          First Mortgage Bonds               A3            BBB         A
          Senior Unsecured Debt              Baa1          BBB         A-

In February 2003, Moody's Investor Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review included a downgrade
of our rating for unsecured debt from A2 to Baa1 and secured debt from A1 to A3.
The completion of this review was a culmination of ratings action started during
2002. In March 2003, S&P lowered AEP and our senior unsecured debt and first
mortgage bonds ratings from BBB+ to BBB.

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

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

<TABLE>
<CAPTION>


                                                                        Payments Due by Period
                                                                            (in thousands)

Contractual Cash Obligations                Less Than 1 year     2-3 years    4-5 years      After 5 years       Total
----------------------------                ----------------     ---------    ---------      -------------       -----

<C>                                             <C>              <C>           <C>              <C>           <C>
Long-term Debt                                   $83,700          $50,000        $1,000         $439,598        $574,298
Advances from Affiliates                          32,864               -             -                 -          32,864
Unconditional Purchase Obligation (a)            181,379          175,082       139,916          377,568         873,945
Capital Lease Obligations                            492              562            50                -           1,104
Noncancellable Operating Leases                    4,684            8,599         4,642            8,616          26,541
                                                ---------        ---------     ---------        ---------     -----------
  Total                                         $303,119         $234,243      $145,608         $825,782      $1,508,752
                                                =========        =========     =========        =========     ===========
</TABLE>

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

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------

This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.
<TABLE>
<CAPTION>

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

     Domestic Power
     --------------
     <C>                                                                                                              <C>
     Beginning Balance December 31, 2002                                                                               $3,545
     (Gain) Loss from Contracts Realized/Settled During the Period (a)                                                  1,308
     Fair Value of New Contracts When Entered Into During the Period (b)                                                    -
     Net Option Premiums Paid/(Received) (c)                                                                              (69)
     Change in Fair Value Due to Valuation Methodology Changes                                                              -
     Effect of EITF 98-10 Rescission (d)                                                                                    -
     Changes in Fair Value of Risk Management Contracts (e)                                                                 -
     Changes in Fair Value of Risk Management  Contracts Allocated to Regulated Jurisdictions (f)                       9,273
                                                                                                                      --------
     Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                         14,057
     Net Cash Flow Hedge Contracts (g)                                                                                    239
                                                                                                                      --------
     Ending Balance December 31, 2003                                                                                 $14,296
                                                                                                                      ========
</TABLE>

    (a) "(Gain) Loss from Contracts Realized/Settled During the Period" includes
        realized gains from risk management contracts and related derivatives
        that settled during 2003 that were entered into prior to 2003.
    (b) The "Fair Value of New Contracts When Entered Into During the Period"
        represents the fair value of long-term contracts entered into with
        customers during 2003. The fair value is calculated as of the execution
        of the contract. Most of the fair value comes from longer term fixed
        price contracts with customers that seek to limit their risk against
        fluctuating energy prices. The contract prices are valued against market
        curves associated with the delivery location.
    (c) "Net Option Premiums Paid/(Received)" reflects the net option premiums
        paid/(received) as they relate to unexercised and unexpired option
        contracts that were entered into in 2003.
    (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
        Cumulative Effect of Accounting Changes."
    (e) "Changes in Fair Value of Risk Management Contracts" represents the fair
        value change in the risk management portfolio due to market fluctuations
        during the current period. Market fluctuations are attributable to
        various factors such as supply/demand, weather, storage, etc.
    (f) "Change in Fair Value of Risk Management Contracts Allocated to
        Regulated Jurisdictions" relates to the net gains (losses) of those
        contracts that are not reflected in the Consolidated Statements of
        Income. These net gains (losses) are recorded as regulatory
        liabilities/assets for those subsidiaries that operate in regulated
        jurisdictions.
    (g) "Net Cash Flow Hedge Contracts (pre-tax)" are discussed below in
        Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>

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

                                                                                                              After
                                            2004             2005        2006        2007         2008        2008      Total (c)
                                            ----             ----        ----        ----         ----        ----      --------
                                                                                (in thousands)
 <C>                                        <C>            <C>            <C>         <C>         <C>       <C>         <C>
 Prices Actively Quoted - Exchange
  Exchange Traded Contracts                   $326          $(136)         $13         $83          $-          $-         $286
 Prices Provided by Other External
  Sources - OTC Broker Quotes (a)            6,962          2,151          788         497         285           -       10,683
 Prices Based on Models and Other
  Valuation Methods (b)                       (883)           676          155         325         680       2,135        3,088
                                            -------        -------        -----       -----       -----     -------     --------

 Total                                      $6,405         $2,691         $956        $905        $965      $2,135      $14,057
                                            =======        =======        =====       =====       =====     =======     ========

</TABLE>


    (a) "Prices Provided by Other External Sources - OTC Broker Quotes reflects
        information obtained from over-the-counter brokers, industry services,
        or multiple-party on-line platforms.
    (b) "Prices Based on Models and Other Valuation Methods" is in absence of
        pricing information from external sources, modeled information is
        derived using valuation models developed by the reporting entity,
        reflecting when appropriate, option pricing theory, discounted cash
        flow concepts, valuation adjustments, etc. and may require projection
        of prices for underlying commodities beyond the period that prices are
        available from third-party sources. In addition, where external pricing
        information or market liquidity are limited, such valuations are
        classified as modeled. The determination of the point at which a market
        is no longer liquid for placing it in the Modeled category varies by
        market.
    (c) Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.


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

                                                                Domestic
                                                                 Power
                                                                --------
                                                            (in thousands)
      Beginning Balance December 31, 2002                        $(42)
      Changes in Fair Value (a)                                    18
      Reclassifications from AOCI to Net Income (b)               180
                                                                 -----
      Ending Balance December 31, 2003                           $156
                                                                 =====

     (a) "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
     (b) "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is a $724 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $258  $1,004   $420    $100            $136    $415     $148     $30


VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $66 million and $70 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                                 PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                        STATEMENTS OF INCOME
                                        For the Years Ended December 31, 2003, 2002 and 2001

                                                                              2003                2002                2001
                                                                              ----                ----                ----
                                                                                             (in thousands)
                    OPERATING REVENUES
-------------------------------------------------------
<C>                                                                       <C>                   <C>                 <C>
Electric Generation, Transmission and Distribution                        $1,079,692            $784,208            $920,229
Sales to AEP Affiliates                                                       23,130               9,439              36,771
                                                                          -----------           ---------           ---------
TOTAL                                                                      1,102,822             793,647             957,000
                                                                          -----------           ---------           ---------

                    OPERATING EXPENSES
-------------------------------------------------------
Fuel for Electric Generation                                                 526,563             246,199             461,470
Purchased Electricity for Resale                                              35,685              47,507              24,187
Purchased Electricity from AEP Affiliates                                    109,639              89,454              43,758
Other Operation                                                              129,246             133,538             137,678
Maintenance                                                                   53,076              48,060              46,188
Depreciation and Amortization                                                 86,455              85,896              80,245
Taxes Other Than Income Taxes                                                 32,287              34,077              31,973
Income Taxes                                                                  37,008              24,195              34,513
                                                                          -----------           ---------           ---------
TOTAL                                                                      1,009,959             708,926             860,012
                                                                          -----------           ---------           ---------

OPERATING INCOME                                                              92,863              84,721              96,988

Nonoperating Income                                                            8,026               1,920               2,112
Nonoperating Expense                                                           1,385               6,971               1,740
Nonoperating Income Tax Expense (Credit)                                         829              (1,812)                352
Interest Charges                                                              44,784              40,422              39,249
                                                                          -----------           ---------           ---------
NET INCOME                                                                    53,891              41,060              57,759

Gain on Reacquired Preferred Stock                                                 -                   1                   -
Preferred Stock Dividend Requirements                                            213                 213                 213
                                                                          -----------           ---------           ---------

EARNINGS APPLICABLE TO COMMON STOCK                                          $53,678             $40,848             $57,546
                                                                          ===========           =========           =========

</TABLE>

The common stock of PSO is owned by a wholly-owned subsidiary of AEP.

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

<PAGE>
<TABLE>
<CAPTION>


                                                    PUBLIC SERVICE COMPANY OF OKLAHOMA
                                               STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                    EQUITY AND COMPREHENSIVE INCOME
                                            For the Years Ended December 31, 2003, 2002 and 2001
                                                               (in thousands)


                                                                                                    Accumulated Other
                                                      Common        Paid-in        Retained          Comprehensive
                                                      Stock         Capital        Earnings          Income (Loss)        Total
                                                      ------        -------        --------        -----------------      -----
<C>                                                 <C>            <C>               <C>                 <C>             <C>
DECEMBER 31, 2000                                   $157,230       $180,016          $137,688                  $-        $474,934

Common Stock Dividends Declared                                                       (52,240)                            (52,240)
Preferred Stock Dividends Declared                                                       (213)                               (213)
                                                                                                                         ---------
TOTAL                                                                                                                     422,481

          COMPREHENSIVE INCOME
-------------------------------------------
NET INCOME                                                                             57,759                              57,759
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 57,759
                                                    ---------      ---------         ---------           ---------       ---------

DECEMBER 31, 2001                                   $157,230       $180,016          $142,994                  $-        $480,240

Gain on Reacquired Preferred Stock                                                          1                                   1
Common Stock Dividends                                                                (67,368)                            (67,368)
Preferred Stock Dividends                                                                (213)                               (213)
                                                                                                                         ---------
TOTAL                                                                                                                     412,660
                                                                                                                         ---------


          COMPREHENSIVE INCOME
-------------------------------------------
Other Comprehensive Income, (Loss)
 Net of Taxes:
   Unrealized Loss on Cash Flow Hedges                                                                        (42)            (42)
   Minimum Pension Liability                                                                              (54,431)        (54,431)
NET INCOME                                                                             41,060                              41,060
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                (13,413)
                                                    ---------      ---------         ---------           ---------       ---------

DECEMBER 31, 2002                                   $157,230       $180,016          $116,474            $(54,473)       $399,247

Capital Contribution from Parent                                     50,000                                                50,000
Common Stock Dividends                                                                (30,000)                            (30,000)
Preferred Stock Dividends                                                                (213)                               (213)
Distribution of Investment in AEMT, Inc.
  Preferred Shares to Parent                                                             (548)                               (548)
                                                                                                                         ---------
TOTAL                                                                                                                     418,486
                                                                                                                         ---------

          COMPREHENSIVE INCOME
-------------------------------------------
Other Comprehensive Income
 Net of Taxes:
   Unrealized Gain on Cash Flow Hedges                                                                        198             198
   Minimum Pension Liability                                                                               10,433          10,433
NET INCOME                                                                             53,891                              53,891
                                                                                                                         ---------
TOTAL COMPREHENSIVE INCOME                                                                                                 64,522
                                                    ---------      ---------         ---------           ---------       ---------

DECEMBER 31, 2003                                   $157,230       $230,016          $139,604            $(43,842)       $483,008
                                                    =========      =========         =========           =========       =========
</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                                     PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                              BALANCE SHEETS
                                                                 ASSETS
                                                       December 31, 2003 and 2002

                                                                                             2003                    2002
                                                                                             ----                    ----
                                                                                                     (in thousands)

                ELECTRIC UTILITY PLANT
------------------------------------------------------
<C>                                                                                        <C>                     <C>
Production                                                                                 $1,065,408              $1,040,520
Transmission                                                                                  451,292                 432,846
Distribution                                                                                1,031,229                 990,947
General                                                                                       203,756                 206,747
Construction Work in Progress                                                                  54,711                  88,444
                                                                                           -----------             -----------
TOTAL                                                                                       2,806,396               2,759,504
Accumulated Depreciation and Amortization                                                   1,069,216               1,037,222
                                                                                           -----------             -----------
TOTAL - NET                                                                                 1,737,180               1,722,282
                                                                                           -----------             -----------

            OTHER PROPERTY AND INVESTMENTS
------------------------------------------------------
Non-Utility Property, Net                                                                       4,631                   4,833
Other Investments                                                                               2,320                     550
                                                                                           -----------             -----------
TOTAL                                                                                           6,951                   5,383
                                                                                           -----------             -----------

                     CURRENT ASSETS
------------------------------------------------------
Cash and Cash Equivalents                                                                      14,258                  16,774
Accounts Receivable:
  Customers                                                                                    28,515                  30,130
  Affiliated Companies                                                                         19,852                  14,139
  Miscellaneous                                                                                     -                   1,557
  Allowance for Uncollectible Accounts                                                            (37)                    (84)
Fuel Inventory                                                                                 18,331                  19,973
Materials and Supplies                                                                         38,125                  37,375
Regulatory Asset for Under-recovered Fuel Costs                                                24,170                  76,470
Risk Management Assets                                                                         18,586                   3,841
Margin Deposits                                                                                 4,351                      91
Prepayments and Other                                                                           2,655                   2,644
                                                                                           -----------             -----------
TOTAL                                                                                         168,806                 202,910
                                                                                           -----------             -----------

             DEFERRED DEBITS AND OTHER ASSETS
------------------------------------------------------
Regulatory Assets:
  Unamortized Loss on Required Debt                                                            14,357                  11,138
  Other                                                                                        14,342                  15,012
Long-term Risk Management Assets                                                               10,379                   4,481
Deferred Charges                                                                               18,017                  18,117
                                                                                           -----------             -----------
TOTAL                                                                                          57,095                  48,748
                                                                                           -----------             -----------

TOTAL ASSETS                                                                               $1,970,032              $1,979,323
                                                                                           ===========             ===========

</TABLE>


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

<PAGE>
<TABLE>
<CAPTION>


                                            PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                      BALANCE SHEETS
                                              CAPITALIZATION AND LIABILITIES
                                                December 31, 2003 and 2002

                                                                                                  2003                    2002
                                                                                                  ----                    ----
                                                                                                         (in thousands)

                   CAPITALIZATION
----------------------------------------------------
<C>                                                                                           <C>                     <C>
Common Shareholder's Equity:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                                                               $157,230                $157,230
    Paid-in Capital                                                                              230,016                 180,016
    Retained Earnings                                                                            139,604                 116,474
    Accumulated Other Comprehensive Income (Loss)                                                (43,842)                (54,473)
                                                                                              -----------             -----------
Total Common Shareholder's Equity                                                                483,008                 399,247
Cumulative Preferred Stock Not Subject to Mandatory Redemption                                     5,267                   5,267
                                                                                              -----------             -----------
Total Shareholder's Equity                                                                       488,275                 404,514
PSO - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary Trust
 Holding Solely Junior Subordinated Debentures of PSO                                                  -                  75,000
Long-term Debt                                                                                   490,598                 445,437
                                                                                              -----------             -----------
TOTAL                                                                                            978,873                 924,951
                                                                                              -----------             -----------

                CURRENT LIABILITIES
----------------------------------------------------
Long-term Debt Due Within One Year                                                                83,700                 100,000
Advances from Affiliates                                                                          32,864                  86,105
Accounts Payable:
  General                                                                                         48,808                  61,169
  Affiliated Companies                                                                            57,206                  78,076
Customer Deposits                                                                                 26,547                  21,789
Taxes Accrued                                                                                     27,157                   6,854
Interest Accrued                                                                                   3,706                   6,979
Risk Management Liabilities                                                                       11,067                   3,260
Obligations Under Capital Leases                                                                     452                       -
Other                                                                                             35,234                  24,957
                                                                                              -----------             -----------
TOTAL                                                                                            326,741                 389,189
                                                                                              -----------             -----------

       DEFERRED CREDITS AND OTHER LIABILITIES
----------------------------------------------------
Deferred Income Taxes                                                                            335,434                 341,396
Long-Term Risk Management Liabilities                                                              3,602                   1,581
Regulatory Liabilities:
  Asset Removal Costs                                                                            214,033                       -
  Deferred Investment Tax Credits                                                                 30,411                  32,201
  SFAS 109 Regulatory Liability, Net                                                              24,937                  27,893
  Other                                                                                           15,406                   4,391
Obligations Under Capital Leases                                                                     558                       -
Deferred Credits and Other                                                                        40,037                 257,721
                                                                                              -----------             -----------
TOTAL                                                                                            664,418                 665,183
                                                                                              -----------             -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                          $1,970,032              $1,979,323
                                                                                              ===========             ===========


</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>


                                                   PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                       STATEMENTS OF CASH FLOWS
                                         For the Years Ended December 31, 2003, 2002 and 2001

                                                                                  2003                2002              2001
                                                                                  ----                ----              ----
                                                                                                 (in thousands)
               OPERATING ACTIVITIES
------------------------------------------------------
<C>                                                                             <C>               <C>                <C>
Net Income                                                                       $53,891            $41,060           $57,759
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
   Depreciation and Amortization                                                  86,455             85,896            80,245
   Deferred Income Taxes                                                         (14,641)            75,659           (17,751)
   Deferred Investment Tax Credits                                                (1,790)            (1,791)           (1,791)
Changes in Certain Assets and Liabilities:
   Accounts Receivable, Net                                                       (2,588)            (3,737)           21,405
   Fuel, Materials and Supplies                                                      892                996              (589)
   Accounts Payable                                                              (33,231)            25,629           (55,319)
   Taxes Accrued                                                                  20,303            (11,296)           16,491
   Fuel Recovery                                                                  52,300            (85,190)           51,987
Changes in Other Assets                                                          (10,421)             1,796           (11,929)
Changes in Other Liabilities                                                      14,987             (6,928)            9,351
                                                                                ---------         ----------         ---------
Net Cash Flows From Operating Activities                                         166,157            122,094           149,859
                                                                                ---------         ----------         ---------

               INVESTING ACTIVITIES
------------------------------------------------------
Construction Expenditures                                                        (86,815)           (89,365)         (124,520)
Proceeds from Sale of Property and Other                                           2,862                963              (359)
                                                                                ---------         ----------         ---------
Net Cash Flows Used For Investing Activities                                     (83,953)           (88,402)         (124,879)
                                                                                ---------         ----------         ---------

               FINANCING ACTIVITIES
------------------------------------------------------
Capital Contributions from Parent                                                 50,000                  -                 -
Issuance of Long-term Debt                                                       148,734            187,850                 -
Retirement of Long-term Debt                                                    (200,000)          (106,000)          (20,000)
Change in Advances to/from Affiliates, Net                                       (53,241)           (36,982)           41,967
Dividends Paid on Common Stock                                                   (30,000)           (67,368)          (52,240)
Dividends Paid on Cumulative Preferred Stock                                        (213)              (213)             (213)
                                                                                ---------         ----------         ---------
Net Cash Flows Used For Financing Activities                                     (84,720)           (22,713)          (30,486)
                                                                                ---------         ----------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                              (2,516)            10,979            (5,506)
Cash and Cash Equivalents at Beginning of Period                                  16,774              5,795            11,301
                                                                                ---------         ----------         ---------
Cash and Cash Equivalents at End of Period                                       $14,258            $16,774            $5,795
                                                                                =========         ==========         =========

</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid (received) for interest net of capitalized amounts was $44,703,000,
$38,620,000 and $38,250,000 and for income taxes was $36,470,000, (38,943,000)
and $38,653,000 in 2003, 2002 and 2001, respectively.

There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc.
to PSO's Parent Company in 2003.

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

<PAGE>
<TABLE>
<CAPTION>


                                                PUBLIC SERVICE COMPANY OF OKLAHOMA
                                                   STATEMENTS OF CAPITALIZATION
                                                     December 31, 2003 and 2002

                                                                                                    2003            2002
                                                                                                    ----            ----
                                                                                                       (in thousands)
<C>                                                                                                <C>            <C>
TOTAL COMMON SHAREHOLDER'S EQUITY                                                                  $483,008       $399,247

PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
  redeemable at the option of PSO upon 30 days notice.

                                                                  Shares
            Call Price       Number of Shares Redeemed         Outstanding
Series     December 31,       Year Ended December 31,          December 31,
------     ------------      -------------------------         ------------
              2003            2003      2002      2001             2003
              ----            ----      ----      ----             ----

Not Subject to Mandatory Redemption:


4.00%       $105.75             2         6         -              44,598                             4,460          4,460
4.24%        103.19             -         1         -               8,069                               807            807
                                                                                                   ---------      ---------
Total                                                                                                 5,267          5,267
                                                                                                   ---------      ---------

TRUST PREFERRED SECURITIES:
PSO-Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely
   Junior Subordinated Debentures of PSO, 8.00%,
   Due April 30, 2037 (a)                                                                                 -         75,000
                                                                                                   ---------      ---------

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                                 99,864        298,079
Installment Purchase Contracts                                                                       47,358         47,358
Note Payable to Trust (a)                                                                            77,320              -
Senior Unsecured Notes                                                                              349,756        200,000
Less Portion Due Within One Year                                                                    (83,700)      (100,000)
                                                                                                   ---------      ---------

Long-term Debt Excluding Portion Due Within One Year                                                490,598        445,437
                                                                                                   ---------      ---------

TOTAL CAPITALIZATION                                                                               $978,873       $924,951
                                                                                                   =========      =========

</TABLE>

(a) See Note 16 for discussion of Notes Payable to Trust.

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

<PAGE>

                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002


First Mortgage Bonds outstanding were as follows:

                                              2003                   2002
                                              ----                   ----
 %Rate        Due                                    (in thousands)
 -----        ---
 6.25         2003 - April 1                     $-               $ 35,000
 7.25         2003 - July 1                       -                 65,000
 7.38         2004 - December 1              50,000                 50,000
 6.50         2005 - June 1                  50,000                 50,000
 7.38         2023 - April 1                      -                100,000
 Unamortized Discount                          (136)                (1,921)
                                            --------              ---------
 Total                                      $99,864               $298,079
                                            ========              =========

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions. Interest payments are made semi-annually.

Installment Purchase Contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:


                                                  2003                   2002
                                                  ----                   ----
 %Rate        Due                                       (in thousands)
 -----        ---
Oklahoma Environmental Finance Authority (OEFA):
 5.90         2007 - December 1                   $1,000                 $1,000

Oklahoma Development Finance Authority (ODFA):
 4.875        2014 - June 1 (a)                   33,700                 33,700

Red River Authority of Texas:
 6.00         2020 - June 1                       12,660                 12,660
 Unamortized Discount                                 (2)                    (2)
                                                 --------               --------
 Total                                           $47,358                $47,358
                                                 ========               ========

(a) These bonds will be remarketed on June 1, 2004.

Under the terms of the installment purchase contracts, PSO is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants. Interest payments are made semi-annually.

Senior Unsecured Notes outstanding were as follows:

                                                   2003                  2002
                                                   ----                  ----
 %Rate           Due                                      (in thousands)
 -----           ---
 4.85            2010 - September 15            $150,000                     $-
 6.00            2032 - December 31              200,000                200,000
 Unamortized Discount                               (244)                     -
                                                ---------              ---------
 Total                                          $349,756               $200,000
                                                =========              =========



Notes Payable to Trust was outstanding as follows:

                                                   2003                  2002
                                                   ----                  ----
 %Rate           Due                                       (in thousands)
 -----           ---
 8.00            2037 - April 30                 $77,320                     $-
                                                 ========              =========

See Note 16 for discussion of Notes Payable to Trust.


At December 31, 2003, future annual long-term debt payments are as follows:

                                                      Amount
                                                      ------
                                                  (in thousands)
       2004                                           $83,700
       2005                                            50,000
       2006                                                 -
       2007                                             1,000
       2008                                                 -
       Later Years                                    439,980
                                                     ---------
       Total Principal Amount                         574,680
       Unamortized Discount                              (382)
                                                     ---------
       Total                                         $574,298
                                                     =========



<PAGE>
<TABLE>
<CAPTION>


                                            PUBLIC SERVICE COMPANY OF OKLAHOMA
                                    INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to PSO's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to PSO. The footnotes begin on page L-1.

                                                                                                                      Footnote
                                                                                                                      Reference
                                                                                                                      ---------

<C>                                                                                                                   <C>
Organization and Summary of Significant Accounting Policies                                                           Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                        Note 2

Rate Matters                                                                                                          Note 4

Effects of Regulation                                                                                                 Note 5

Commitments and Contingencies                                                                                         Note 7

Guarantees                                                                                                            Note 8

Sustained Earnings Improvement Initiative                                                                             Note 9

Benefit Plans                                                                                                         Note 11

Business Segments                                                                                                     Note 12

Derivatives, Hedging and Financial Instruments                                                                        Note 13

Income Taxes                                                                                                          Note 14

Leases                                                                                                                Note 15

Financing Activities                                                                                                  Note 16

Related Party Transactions                                                                                            Note 17

Jointly Owned Electric Utility Plant                                                                                  Note 18

Unaudited Quarterly Financial Information                                                                             Note 19

</TABLE>


<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:

We have audited the accompanying balance sheets and statements of capitalization
of Public Service Company of Oklahoma as of December 31, 2003 and 2002, and the
related statements of income, changes in common shareholder's equity and
comprehensive income and cash flows for each of the three years in the period
ended December 31, 2003. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material
respects, the financial position of Public Service Company of Oklahoma as of
December 31, 2003 and 2002, and the results of its operations and its cash flows
each of the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company adopted FIN 46,
"Consolidation of Variable Interest Entities," effective July 1, 2003.


/s/ Deloitte & Touche LLP


Columbus, Ohio
March 5, 2004


<PAGE>
















                 SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED



<PAGE>
<TABLE>
<CAPTION>

                                                  SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                        SELECTED CONSOLIDATED FINANCIAL DATA


                                                      2003             2002             2001             2000              1999
                                                      ----             ----             ----             ----              ----
                                                                                   (in thousands)
           INCOME STATEMENTS DATA
----------------------------------------
<C>                                                <C>              <C>              <C>               <C>             <C>
Operating Revenues                                 $1,146,842       $1,084,720       $1,101,326        $1,118,274        $971,527
Operating Expenses                                    996,706          942,251          955,119           989,996         824,465
                                                   -----------      -----------      -----------       -----------     -----------
Operating Income                                      150,136          142,469          146,207           128,278         147,062
Nonoperating Items, Net                                 4,767             (309)             741             3,851          (1,965)
Interest Charges                                       63,779           59,168           57,581            59,457          58,892
Minority Interest                                      (1,500)               -                -                 -               -
                                                   -----------      -----------      -----------       -----------     -----------
Income Before Extraordinary Item
 And Cumulative Effect                                 89,624           82,992           89,367            72,672          86,205
Extraordinary Loss                                          -                -                -                 -          (3,011)
Cumulative Effect of Accounting Changes                 8,517                -                -                 -               -
                                                   -----------      -----------      -----------       -----------     -----------
Net Income                                             98,141           82,992           89,367            72,672          83,194
Preferred Stock Dividend Requirements                     229              229              229               229             229
                                                   -----------      -----------      -----------       -----------     -----------
Earnings Applicable to Common Stock                   $97,912          $82,763          $89,138           $72,443         $82,965
                                                   ===========      ===========      ===========       ===========     ===========

            BALANCE SHEETS DATA
----------------------------------------
Electric Utility Plant                             $3,799,460       $3,596,174       $3,460,764        $3,319,024      $3,231,431
Accumulated Depreciation and Amortization           1,617,846        1,477,875        1,342,003         1,259,509       1,196,629
                                                   -----------      -----------      -----------       -----------     -----------
Net Electric Utility Plant                         $2,181,614       $2,118,299       $2,118,761        $2,059,515      $2,034,802
                                                   ===========      ===========      ===========       ===========     ===========

TOTAL ASSETS                                       $2,581,963       $2,428,138       $2,509,291        $2,855,885      $2,294,375
                                                   ===========      ===========      ===========       ===========     ===========

Common Stock and Paid-in Capital                     $380,663         $380,663         $380,663          $380,663        $380,663
Retained Earnings                                     359,907          334,789          308,915           293,989         283,546
Accumulated Other Comprehensive Income (Loss)         (43,910)         (53,683)               -                 -               -
                                                   -----------      -----------      -----------       -----------     -----------
Total Common Shareholder's Equity                    $696,660         $661,769         $689,578          $674,652        $664,209
                                                   ===========      ===========      ===========       ===========     ===========

Cumulative Preferred Stock Not Subject to
 Mandatory Redemption                                  $4,700           $4,701           $4,701            $4,701          $4,703
                                                   ===========      ===========      ===========       ===========     ===========

Trust Preferred Securities (a)                             $-         $110,000         $110,000          $110,000        $110,000
                                                   ===========      ===========      ===========       ===========     ===========

Long-term Debt (b)                                   $884,308         $693,448         $645,283          $645,963        $541,568
                                                   ===========      ===========      ===========       ===========     ===========

Obligations Under Capital Leases (b)                  $21,542                -                -                 -               -
                                                   ===========      ===========      ===========       ===========     ===========

TOTAL CAPITALIZATION AND LIABILITIES               $2,581,963       $2,428,138       $2,509,291        $2,855,885      $2,294,375
                                                   ===========      ===========      ===========       ===========     ===========
</TABLE>


(a) See Note 16 of the Notes to Respective Financial Statements.
(b) Including portion due within one year.


<PAGE>


                SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                 MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
                 ----------------------------------------------

Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation and purchase of electric power, and the subsequent sale, transmission
and distribution of that power to approximately 439,000 retail customers in our
service territory in northeastern Texas, northwestern Louisiana and western
Arkansas. As a power pool member with AEP West companies, we share in the
revenues and expenses of the power pool's sales to neighboring utilities and
power marketers. SWEPCo also sells electric power at wholesale to other
utilities, municipalities and electric cooperatives.

Power pool members are compensated for energy delivered to other members based
upon the delivering members' incremental cost plus a portion of the savings
realized by the purchasing member that avoids the use of more costly
alternatives. The revenue and costs for sales to neighboring utilities and power
marketers made by AEPSC on behalf of the AEP West companies are shared among the
members based upon the relative magnitude of the energy each member provides to
make such sales.

Power and gas risk management activities are conducted on our behalf by AEPSC.
We share in the revenues and expenses associated with these risk management
activities with other AEP registrant subsidiaries excluding AEGCo under existing
power pool and system integration agreements. Risk management activities
primarily involve the purchase and sale of electricity under physical forward
contracts at fixed and variable prices and to a lesser extent gas. The
electricity and gas contracts include physical transactions, over-the-counter
options and swaps and exchange traded futures and options. The majority of the
physical forward contracts are typically settled by entering into offsetting
contracts.

Under our system integration agreement, revenues and expenses from the sales to
neighboring utilities, power marketers and other power and gas risk management
entities are shared among AEP East and West companies. Sharing in a calendar
year is based upon the level of such activities experienced for the twelve
months ended June 30, 2000, which immediately preceded the merger of AEP and
CSW. This resulted in an AEP East and West companies' allocation of
approximately 91% and 9%, respectively, for revenues and expenses. Allocation
percentages in any given calendar year may also be based upon the relative
generating capacity of the AEP East and West companies in the event the
pre-merger activity level is exceeded. The capacity based allocation mechanism
was triggered in June 2003, resulting in an allocation factor of approximately
70% and 30% for the AEP East and West companies, respectively, for the remainder
of 2003.

Results of Operations
---------------------

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

During 2003, Net Income increased $15 million primarily due to an $8 million
increase in Operating Income and the adoption of SFAS 143, which resulted in
Cumulative Effect of Accounting Changes of $9 million in the first quarter of
2003. Significant fluctuations occurred in revenues, fuel and purchased power
due to certain ICR adjustments in 2002; however, income is generally not
affected due to the functioning of fuel adjustment clauses in the retail
jurisdictions.

Operating Income
----------------

Operating Income increased by $8 million primarily due to:

  o     A $12 million increase in wholesale margins due to an increase in
        our allocation of overall AEP System sales percentages resulting
        from increased amounts of off-system sales.
  o     A $12 million increase in retail base revenues due to increased
        customers and their average usage, offset in part by milder
        weather. Cooling and heating degree-days declined 6%.
  o     A $7 million increase in income from risk management activities.
  o     A decrease of $16 million in Other Operation expense primarily due
        to decreases in customer services, outside services and other
        administrative expenses.

The increase in Operating Income was partially offset by:

  o     A $9 million decrease in wholesale base margins primarily due to
        decreased demand from wholesale customers.
  o     A $4 million decrease in capacity revenues due to the elimination
        of the requirement under the Texas Restructuring legislation to
        sell capacity. See Note 6.
  o     A $21 million increase in Income Taxes due to increases in pre-tax
        operating income, federal and state tax return and tax accrual
        adjustments and changes to certain book/tax timing differences
        accounted for on a flow-through basis.

Other Impacts on Earnings
-------------------------

Nonoperating Income Tax Credit increased by $5 million due to changes in certain
book/tax timing differences accounted for on a flow-through basis, changes in
consolidated tax savings and tax return and tax accrual adjustments.

Interest Charges increased $5 million primarily due to higher levels of
outstanding debt, consolidation of Sabine Mining Company and in financing
activity at Dolet Hills.

Minority Interest expense of $2 million is a result of consolidating Sabine
Mining Company during the third quarter of 2003, due to the implementation of
FIN 46. See Notes 2 and 8 for additional discussion.

Cumulative Effect of Accounting Changes
---------------------------------------

The Cumulative Effect of Accounting Changes is due to the one-time, after-tax
impact of adopting SFAS 143 and implementing the requirements of EITF 02-3 (see
Note 2).

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

During 2002, Net Income decreased $6 million primarily resulting from reduced
margins from risk management activities. Significant fluctuations occurred in
revenues, fuel and purchased power due to certain ICR adjustments in 2002;
however, income is generally not affected due to the functioning of fuel
adjustment clauses in the retail jurisdictions.

Operating Income
----------------

Operating Income decreased by $4 million primarily due to:

  o     A $4 million  decrease in retail base revenues  mainly due to decreased
        KWH sales of 6% resulting from the loss of a large industrial customer
        in 2002.
  o     A $15 million decrease in income from risk management activities.
  o     An increase of $18 million in Other Operation expense primarily
        due to the acquisition of Dolet Hills Lignite Company.
  o     A $3 million increase in Depreciation and Amortization due primarily
        to the Dolet Hills acquisition.

The decrease in Operating Income was partially offset by:

  o     An increase of $13 million in other revenue primarily from the Dolet
        Hills Acquisition.
  o     An increase of $7 million in capacity revenues, due to the requirement
        under the Texas Restructuring legislation to sell capacity.
  o     An $8 million decrease in Maintenance expense due to less storm
        damage and reduced tree trimming expense in 2002.
  o     A decrease in Income Taxes of $8 million due to a decrease in pre-tax
        income.

Financial Condition
-------------------

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

The rating agencies currently have us on stable outlook. Current ratings are as
follows:

                                            Moody's       S&P         Fitch
                                            -------       ---         -----
         First Mortgage Bonds               A3            BBB         A
         Senior Unsecured Debt              Baa1          BBB         A-

  In February 2003, Moody's Investors Service (Moody's) completed their review
  of AEP and its rated subsidiaries. The results of that review included a
  downgrade of our rating for unsecured debt from A2 to Baa1 and secured debt
  from A1 to A3. The completion of this review was a culmination of ratings
  action started during 2002. In March 2003, S&P lowered AEP and our senior
  unsecured debt and first mortgage bonds ratings from BBB+ to BBB.

Cash Flow
---------

Cash flows for the years ended December 31, 2003, 2002 and 2001 were as follows:

<TABLE>
<CAPTION>


                                                                                 2003              2002                2001
                                                                                 ----              ----                ----
           <C>                                                                <C>                <C>                 <C>
           Cash and cash equivalents at beginning of period                    $2,069             $5,415              $1,907
                                                                              ---------          ---------           ---------
           Cash flows from (used for):
             Operating activities                                              248,094            210,563             169,610
             Investing activities                                             (110,849)          (110,641)           (197,852)
             Financing activities                                             (127,590)          (103,268)             31,750
                                                                              ---------          ---------           ---------
           Net increase (decrease) in cash and cash equivalents                  9,655             (3,346)              3,508
                                                                              ---------          ---------           ---------
           Cash and cash equivalents at end of period                          $11,724             $2,069              $5,415
                                                                              =========          =========           =========
</TABLE>

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

Cash flows from operating activities were $248 million during 2003 primarily due
to net income, Accounts Receivables, Accounts Payable and Accrued Taxes.

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

Cash spent on investing activities during 2003 were comparable to 2002. In 2003,
construction expenditures were primarily related to projects for improved
transmission and distribution service reliability.

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

Cash flows used for financing activities increased by $24 million during 2003 in
comparison to 2002. During 2003 we paid $16 million more in common stock
dividends than in 2002. During the first quarter of 2003 we retired $55 million
of first mortgage bonds at maturity. In April 2003, we issued $100 million of
senior unsecured debt due 2015 at a coupon of 5.375%. In May 2003, one of our
mining subsidiaries issued $44 million of notes due in 2011 at a coupon of
4.47%. The loan was used primarily to reduce a note to us with an interest rate
of 8.06%. During the fourth quarter of 2003, we had an early redemption of $45
million of first mortgage bonds due in 2023.

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

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

<TABLE>
<CAPTION>

                                                                        Payments Due by Period
                                                                             (in millions)

Contractual Cash Obligations                Less Than 1 year    2-3 years      4-5 years      After 5 years       Total
----------------------------                ----------------    ---------      ---------      -------------       -----

<C>                                             <C>              <C>            <C>             <C>            <C>
Long-term Debt                                  $142,714         $226,628       $123,263        $391,703         $884,308
Unconditional Purchase Obligations (a)           185,425          329,513         85,800         171,601          772,339
Capital Lease Obligations                          4,737            9,174          8,799           4,380           27,090
Noncancellable Operating Leases                    5,522           12,864         14,669          17,849           50,904
                                                ---------        ---------      ---------       ---------      -----------
  Total                                         $338,398         $578,179       $232,531        $585,533       $1,734,641
                                                =========        =========      =========       =========      ===========
</TABLE>

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

In connection with reducing the cost of the lignite mining contract for its
Henry W. Pirkey Power Plant, we have agreed under certain conditions, to assume
the obligations under capital lease obligations and term loan payments of the
mining contractor, Sabine Mining Company (Sabine). In the event Sabine defaults
under any of these agreements, our total future maximum payment exposure is
approximately $58 million with maturity dates ranging from June 2005 to February
2012.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, we have agreed to provide guarantees of mine
reclamation in the amount of approximately $85 million. Since we use
self-bonding, the guarantee provides for us to commit to use its resources to
complete the reclamation in the event the work is not completed by a third party
miner. At December 31, 2003, the cost to reclaim the mine in 2035 is estimated
to be approximately $36 million. This guarantee ends upon depletion of reserves
estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, we consolidated Sabine due to the application of FIN 46 (see
Note 2). Upon consolidation, we recorded the assets and liabilities of Sabine
($78 million). Also, after consolidation, we currently record all expenses
(depreciation, interest and other operation expense) of Sabine and eliminate
Sabine's revenues against our fuel expenses. There is no cumulative effect of an
accounting change recorded as a result of the requirement to consolidate, and
there is no change in net income due to the consolidation of Sabine.

Significant Factors
-------------------

See the "Registrants' Combined Management's Discussion and Analysis" section
beginning on page M-1 for additional discussion of factors relevant to us.

Quantitative And Qualitative Disclosures About Risk Management Activities
-------------------------------------------------------------------------

Market Risks
------------

Our risk management policies and procedures are instituted and administered at
the AEP consolidated level. See complete discussion within AEP's "Qualitative
And Quantitative Disclosures About Risk Management Activities" section. The
following tables provide information about our risk management activities'
effect on this specific registrant.

MTM Risk Management Contract Net Assets
---------------------------------------
This table provides detail on changes in our MTM net asset or liability balance
sheet position from one period to the next.

<TABLE>
<CAPTION>


                                           MTM Risk Management Contract Net Assets
                                                Year Ended December 31, 2003
                                                       (in thousands)
     Domestic Power
     --------------
     <C>                                                                                                              <C>
     Beginning Balance December 31, 2002                                                                               $4,050
     (Gain) Loss from Contracts Realized/Settled During the Period (a)                                                    820
     Fair Value of New Contracts When Entered Into During the Period (b)                                                    -
     Net Option Premiums Paid/(Received) (c)                                                                              (32)
     Change in Fair Value Due to Valuation Methodology Changes                                                              -
     Effect of EITF 98-10 Rescission (d)                                                                                  151
     Changes in Fair Value of Risk Management Contracts (e)                                                             4,002
     Changes in Fair Value of Risk Management Contracts Allocated to Regulated Jurisdictions (f)                        7,615
                                                                                                                      --------
     Total MTM Risk Management Contract Net Assets, Excluding Cash Flow Hedges                                         16,606
     Net Cash Flow Hedge Contracts (g)                                                                                   (741)
                                                                                                                      --------
     Ending Balance December 31, 2003                                                                                 $15,865
                                                                                                                      ========
</TABLE>

       (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
           includes realized gains from risk management contracts and related
           derivatives that settled during 2003 that were entered into prior
           to 2003.
       (b) The "Fair Value of New Contracts When Entered Into During the
           Period" represents the fair value of long- term contracts entered
           into with customers during 2003. The fair value is calculated as of
           the execution of the contract. Most of the fair value comes from
           longer term fixed price contracts with customers that seek to limit
           their risk against fluctuating energy prices. The contract prices
           are valued against market curves associated with the delivery
           location.
       (c) "Net Option Premiums Paid/(Received)" reflects the net option
           premiums paid/(received) as they relate to unexercised and
           unexpired option contracts that were entered into in 2003.
       (d) See Note 2 "New Accounting Pronouncements, Extraordinary Items and
           Cumulative Effect of Accounting Changes."
       (e) "Changes in Fair Value of Risk Management Contracts" represents
           the fair value change in the risk management portfolio due to
           market fluctuations during the current period. Market fluctuations
           are attributable to various factors such as supply/demand,
           weather, etc.
       (f) "Change in Fair Value of Risk Management Contracts Allocated to
           Regulated Jurisdictions" relates to the net gains (losses) of those
           contracts that are not reflected in the Consolidated Statements of
           Income. These net gains (losses) are recorded as regulatory
           liabilities/assets for those subsidiaries that operate in regulated
           jurisdictions.
       (g) "Net Cash Flow Hedge Contracts (pre-tax) are discussed below in
           Accumulated Other Comprehensive Income (Loss).

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

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

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

<TABLE>
<CAPTION>


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

                                                                                                          After
                                                  2004         2005        2006       2007       2008     2008      Total (c)
                                                  ----         ----        ----       ----       ----     -----     ---------
                                                                                 (in thousands)
<C>                                              <C>          <C>         <C>        <C>       <C>       <C>        <C>
Prices Actively Quoted - Exchange
 Traded Contracts                                  $384        $(160)        $15        $98        $-        $-        $337
Prices Provided by Other External Sources -
 OTC Broker Quotes (a)                            8,198        2,533         928        585       336         -      12,580
Prices Based on Models and Other
 Valuation Methods (b)                             (970)         776         183        383       800     2,517       3,689
                                                 -------      -------     -------    -------   -------   -------    --------

Total                                            $7,612       $3,149      $1,126     $1,066    $1,136    $2,517     $16,606
                                                 =======      =======     =======    =======   =======   =======    ========
</TABLE>



    (a) "Prices Provided by Other External Sources - OTC Broker Quotes"
        reflects information obtained from over-the-counter brokers, industry
        services, or multiple-party on-line platforms.
    (b) "Prices Based on Models and Other Valuation Methods" is in absence of
        pricing information from external sources, modeled information is
        derived using valuation models developed by the reporting entity,
        reflecting when appropriate, option pricing theory, discounted cash
        flow concepts, valuation adjustments, etc. and may require projection
        of prices for underlying commodities beyond the period that prices are
        available from third-party sources. In addition, where external pricing
        information or market liquidity are limited, such valuations are
        classified as modeled. The determination of the point at which a market
        is no longer liquid for placing it in the Modeled category varies by
        market.
    (c) Amounts exclude Cash Flow Hedges.

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

The table provides detail on effective cash flow hedges under SFAS 133 included
in the balance sheet. The data in the table will indicate the magnitude of SFAS
133 hedges we have in place. (However, given that under SFAS 133 only cash flow
hedges are recorded in AOCI, the table does not provide an all-encompassing
picture of our hedging activity). The table also includes a roll-forward of the
AOCI balance sheet account, providing insight into the drivers of the changes
(new hedges placed during the period, changes in value of existing hedges and
roll-off of hedges). In accordance with GAAP, all amounts are presented net of
related income taxes.

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

                                                                 Domestic
                                                                  Power
                                                                 --------
                                                              (in thousands)
       Beginning Balance December 31, 2002                        $(48)
       Changes in Fair Value (a)                                    21
       Reclassifications from AOCI to Net Income (b)               211
                                                                  ----
       Ending Balance December 31, 2003                           $184
                                                                  ====

     (a) "Changes in Fair Value" shows changes in the fair value of derivatives
         designated as hedging instruments in cash flow hedges during the
         reporting period not yet reclassified into net income, pending the
         hedged item's affecting net income. Amounts are reported net of related
         income taxes.
     (b) "Reclassifications from AOCI to Net Income" represents gains or losses
         from derivatives used as hedging instruments in cash flow hedges that
         were reclassified into net income during the reporting period. Amounts
         are reported net of related income taxes above.

The portion of cash flow hedges in AOCI expected to be reclassified to earnings
during the next twelve months is an $853 thousand gain.

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

Our counterparty credit quality and exposure is generally consistent with that
of AEP.

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

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

               December 31, 2003                      December 31, 2002
         ----------------------------           ----------------------------
                 (in thousands)                         (in thousands)
         End    High   Average   Low             End    High    Average   Low
        -----  ------  -------  -----          ------  ------   -------  -----
         $304  $1,182   $495    $118            $155    $474     $170     $34



VaR Associated with Debt Outstanding
------------------------------------

The risk of potential loss in fair value attributable to our exposure to
interest rates, primarily related to long-term debt with fixed interest rates
was $57 million and $70 million at December 31, 2003 and 2002, respectively. We
would not expect to liquidate our entire debt portfolio in a one-year holding
period, therefore a near term change in interest rates should not negatively
affect our results of operation or consolidated financial position.


<PAGE>
<TABLE>
<CAPTION>


                                          SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                               CONSOLIDATED STATEMENTS OF INCOME
                                         For the Years Ended December 31, 2003, 2002 and 2001


                                                                   2003                    2002                2001
                                                                   ----                    ----                ----
                                                                                      (in thousands)
               OPERATING REVENUES
----------------------------------------------------
<C>                                                              <C>                    <C>                    <C>
Electric Generation, Transmission and Distribution               $1,077,988             $1,012,421             $1,022,089
Sales to AEP Affiliates                                              68,854                 72,299                 79,237
                                                                 -----------            -----------            -----------
TOTAL                                                             1,146,842              1,084,720              1,101,326
                                                                 -----------            -----------            -----------

                OPERATING EXPENSES
----------------------------------------------------
Fuel for Electric Generation                                        441,445                388,334                457,613
Purchased Electricity for Resale                                     34,850                 44,119                 18,164
Purchased Electricity from AEP Affiliates                            47,914                 42,022                 15,858
Other Operation                                                     173,349                189,024                171,314
Maintenance                                                          70,443                 66,855                 74,677
Depreciation and Amortization                                       121,072                122,969                119,543
Taxes Other Than Income Taxes                                        53,165                 55,232                 55,834
Income Taxes                                                         54,468                 33,696                 42,116
                                                                 -----------            -----------            -----------
TOTAL                                                               996,706                942,251                955,119
                                                                 -----------            -----------            -----------

OPERATING INCOME                                                    150,136                142,469                146,207

Nonoperating Income                                                   3,978                  3,260                  4,512
Nonoperating Expenses                                                 2,607                  1,797                  3,229
Nonoperating Income Tax Expense (Credit)                             (3,396)                 1,772                    542
Interest Charges                                                     63,779                 59,168                 57,581
Minority Interest                                                    (1,500)                     -                      -
                                                                 -----------            -----------            -----------
Income Before Cumulative Effect of Accounting Changes                89,624                 82,992                 89,367
Cumulative Effect of Accounting Changes (Net of Tax)                  8,517                      -                      -
                                                                 -----------            -----------            -----------

NET INCOME                                                           98,141                 82,992                 89,367

Preferred Stock Dividend Requirements                                   229                    229                    229
                                                                 -----------            -----------            -----------

EARNINGS APPLICABLE TO COMMON STOCK                                 $97,912                $82,763                $89,138
                                                                 ===========            ===========            ===========
</TABLE>


The common stock of SWEPCo is owned by a wholly-owned subsidiary of AEP.

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

<PAGE>
<TABLE>
<CAPTION>


                                             SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                       CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S
                                                     EQUITY AND COMPREHENSIVE INCOME
                                          For the Years Ended December 31, 2003, 2002 and 2001
                                                             (in thousands)


                                                                                                   Accumulated Other
                                                       Common         Paid-in         Retained       Comprehensive
                                                       Stock          Capital         Earnings       Income (Loss)       Total
                                                       ------         -------         --------     -----------------     -----

<C>                                                    <C>            <C>             <C>              <C>              <C>
DECEMBER 31, 2000                                      $135,660       $245,003        $293,989               $-         $674,652

Common Stock Dividends                                                                 (74,212)                          (74,212)
Preferred Stock Dividends                                                                 (229)                             (229)
                                                                                                                        ---------
TOTAL                                                                                                                    600,211
                                                                                                                        ---------

           COMPREHENSIVE INCOME
--------------------------------------------
NET INCOME                                                                              89,367                            89,367
                                                                                                                        ---------
TOTAL COMPREHENSIVE INCOME                                                                                                89,367
                                                       ---------      ---------       ---------        ---------        ---------

DECEMBER 31, 2001                                      $135,660       $245,003        $308,915               $-         $689,578

Common Stock Dividends                                                                 (56,889)                          (56,889)
Preferred Stock Dividends                                                                 (229)                             (229)
                                                                                                                        ---------
TOTAL                                                                                                                    632,460
                                                                                                                        ---------

           COMPREHENSIVE INCOME
--------------------------------------------
Other Comprehensive Income, Net of Taxes:
 Unrealized Gain on Cash Flow Power Hedges                                                                  (48)             (48)
 Minimum Pension Liability                                                                              (53,635)         (53,635)
NET INCOME                                                                              82,992                            82,992
                                                                                                                        ---------
TOTAL COMPREHENSIVE INCOME                                                                                                29,309
                                                       ---------      ---------       ---------        ---------        ---------

DECEMBER 31, 2002                                      $135,660       $245,003        $334,789         $(53,683)        $661,769

Common Stock Dividends                                                                 (72,794)                          (72,794)
Preferred Stock Dividends                                                                 (229)                             (229)
                                                                                                                        ---------
TOTAL                                                                                                                    588,746
                                                                                                                        ---------

           COMPREHENSIVE INCOME
--------------------------------------------
Other Comprehensive Income, Net of Taxes:
  Unrealized Gain on Cash Flow Hedges                                                                       232              232
  Minimum Pension Liability                                                                               9,541            9,541
NET INCOME                                                                              98,141                            98,141
                                                                                                                        ---------
TOTAL COMPREHENSIVE INCOME                                                                                               107,914
                                                       ---------      ---------       ---------        ---------        ---------

DECEMBER 31, 2003                                      $135,660       $245,003        $359,907         $(43,910)        $696,660
                                                       =========      =========       =========        =========        =========

</TABLE>

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


<PAGE>
<TABLE>
<CAPTION>


                                         SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                 CONSOLIDATED BALANCE SHEETS
                                                           ASSETS
                                                   December 31, 2003 and 2002

                                                                                                 2003                   2002
                                                                                                 ----                   ----
                                                                                                        (in thousands)

              ELECTRIC UTILITY PLANT
-------------------------------------------------
<C>                                                                                             <C>                   <C>
Production                                                                                      $1,622,498            $1,503,722
Transmission                                                                                       615,158               575,003
Distribution                                                                                     1,078,368             1,063,564
General                                                                                            423,427               378,130
Construction Work in Progress                                                                       60,009                75,755
                                                                                                -----------           -----------
TOTAL                                                                                            3,799,460             3,596,174
Accumulated Depreciation and Amortization                                                        1,617,846             1,477,875
                                                                                                -----------           -----------
TOTAL - NET                                                                                      2,181,614             2,118,299
                                                                                                -----------           -----------

           OTHER PROPERTY AND INVESTMENTS
-------------------------------------------------
Non-Utility Property, Net                                                                            3,808                 4,203
Other Investments                                                                                    4,710                 1,775
                                                                                                -----------           -----------
TOTAL                                                                                                8,518                 5,978
                                                                                                -----------           -----------

                  CURRENT ASSETS
-------------------------------------------------
Cash and Cash Equivalents                                                                           11,724                 2,069
Advances to Affiliates                                                                              66,476                     -
Accounts Receivable:
  Customers                                                                                         41,474                61,478
  Affiliated Companies                                                                              10,394                19,253
  Miscellaneous                                                                                      4,682                   881
  Allowance for Uncollectible Accounts                                                              (2,093)               (2,128)
Fuel Inventory                                                                                      63,881                61,741
Materials and Supplies                                                                              33,775                33,539
Regulatory Asset for Under-recovered Fuel Costs                                                     11,394                 2,865
Risk Management Assets                                                                              19,715                 4,388
Margin Deposits                                                                                      5,123                   105
Prepayments and Other                                                                               19,078                17,746
                                                                                                -----------           -----------
TOTAL                                                                                              285,623               201,937
                                                                                                -----------           -----------

          DEFERRED DEBITS AND OTHER ASSETS
-------------------------------------------------
Regulatory Assets:
  SFAS 109 Regulatory Asset, Net                                                                     3,235                19,855
  Unamortized Loss on Required Debt                                                                 19,331                17,031
  Other                                                                                             15,859                12,347
Long-term Risk Management Assets                                                                    12,178                 5,119
Deferred Charges                                                                                    55,605                47,572
                                                                                                -----------           -----------
TOTAL                                                                                              106,208               101,924
                                                                                                -----------           -----------

TOTAL ASSETS                                                                                    $2,581,963            $2,428,138
                                                                                                ===========           ===========

</TABLE>

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




<PAGE>
<TABLE>
<CAPTION>


                                        SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                                  CONSOLIDATED BALANCE SHEETS
                                                 CAPITALIZATION AND LIABILITIES
                                                   December 31, 2003 and 2002

                                                                                            2003                  2002
                                                                                            ----                  ----
                                                                                                 (in thousands)
                       CAPITALIZATION
----------------------------------------------------------
<C>                                                                                     <C>                   <C>
Common Shareholder's Equity:
  Common Stock - $18 Par Value:
     Authorized - 7,600,000 Shares
     Outstanding - 7,536,640 Shares                                                       $135,660              $135,660
     Paid-in Capital                                                                       245,003               245,003
     Retained Earnings                                                                     359,907               334,789
     Accumulated Other Comprehensive Income (Loss)                                         (43,910)              (53,683)
                                                                                        -----------           -----------
Total Common Shareholder's Equity                                                          696,660               661,769
Cumulative Preferred Stock Not Subject to Mandatory Redemption                               4,700                 4,701
                                                                                        -----------           -----------
Total Shareholder's Equity                                                                 701,360               666,470
SWEPCo - Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary
 Trust Holding Solely Junior Subordinated Debentures of SWEPCo                                   -               110,000
Long-term Debt                                                                             741,594               637,853
                                                                                        -----------           -----------
TOTAL                                                                                    1,442,954             1,414,323
                                                                                        -----------           -----------

Minority Interest                                                                            1,367                     -
                                                                                        -----------           -----------

                     CURRENT LIABILITIES
----------------------------------------------------------
Long-term Debt Due Within One Year                                                         142,714                55,595
Advances from Affiliates                                                                         -                23,239
Accounts Payable:
  General                                                                                   37,646                62,139
  Affiliated Companies                                                                      35,138                58,773
Customer Deposits                                                                           24,260                20,110
Taxes Accrued                                                                               28,691                19,081
Interest Accrued                                                                            16,852                17,051
Risk Management Liabilities                                                                 11,361                 3,724
Obligations Under Capital Leases                                                             3,159                     -
Regulatory Liability for Over-recovered Fuel                                                 4,178                17,226
Other                                                                                       53,753                34,565
                                                                                        -----------           -----------
TOTAL                                                                                      357,752               311,503
                                                                                        -----------           -----------

            DEFERRED CREDITS AND OTHER LIABILITIES
----------------------------------------------------------
Deferred Income Taxes                                                                      349,064               341,064
Long-term Risk Management Liabilities                                                        4,667                 1,806
Reclamation Reserve                                                                         16,512                13,826
Regulatory Liabilities:
  Asset Removal Costs                                                                      236,409                     -
  Deferred Investment Tax Credits                                                           39,864                44,190
  Excess Earnings                                                                            2,600                 3,700
  Other                                                                                     18,779                 3,394
Asset Retirement Obligations                                                                 8,429                     -
Obligations Under Capital Leases                                                            18,383                     -
Deferred Credits and Other                                                                  85,183               294,332
                                                                                        -----------           -----------
TOTAL                                                                                      779,890               702,312
                                                                                        -----------           -----------

Commitments and Contingencies (Note 7)

TOTAL CAPITALIZATION AND LIABILITIES                                                    $2,581,963            $2,428,138
                                                                                        ===========           ===========

</TABLE>

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

<PAGE>
<TABLE>
<CAPTION>

                                         SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                             CONSOLIDATED STATEMENTS OF CASH FLOWS
                                       For the Years Ended December 31, 2003, 2002 and 2001

                                                                                  2003              2002              2001
                                                                                  ----              ----              ----
                                                                                      (in thousands)
<C>                                                                              <C>              <C>               <C>
             OPERATING ACTIVITIES
-----------------------------------------------------
Net Income                                                                        $98,141          $82,992           $89,367
Adjustments to Reconcile Net Income to Net Cash Flows
 From Operating Activities:
    Depreciation and Amortization                                                 121,072          122,969           119,543
    Deferred Income Taxes                                                           9,942           (3,134)          (31,396)
    Deferred Investment Tax Credits                                                (4,326)          (4,524)           (4,453)
    Cumulative Effect of Accounting Changes                                        (8,517)               -                 -
    Mark-to-Market of Risk Management Contracts                                   (12,403)          (1,151)          (10,695)
Changes in Certain Assets and Liabilities:
    Accounts Receivable, Net                                                       27,527          (24,371)          (11,447)
    Fuel, Materials and Supplies                                                    4,165          (10,541)          (19,578)
    Accounts Payable                                                              (51,687)          11,633           (34,489)
    Taxes Accrued                                                                   8,446          (17,441)           25,298
    Fuel Recovery                                                                 (21,577)          17,713            34,423
Change in Other Assets                                                             16,268           24,257             1,323
Change in Other Liabilities                                                        61,043           12,161            11,714
                                                                                 ---------        ---------         ---------
Net Cash Flows From Operating Activities                                          248,094          210,563           169,610
                                                                                 ---------        ---------         ---------

             INVESTING ACTIVITIES
-----------------------------------------------------
Construction Expenditures                                                        (121,124)        (111,775)         (111,725)
Investment in Mining Operations                                                         -                -           (85,716)
Proceeds from Sale of Assets and Other                                             10,275            1,134              (411)
                                                                                 ---------        ---------         ---------
Net Cash Flows Used For Investing Activities                                     (110,849)        (110,641)         (197,852)
                                                                                 ---------        ---------         ---------

             FINANCING ACTIVITIES
-----------------------------------------------------
Issuance of Long-term Debt                                                        254,630          198,573                 -
Retirement of Long-term Debt                                                     (219,482)        (150,595)             (595)
Change in Advances to/from Affiliates, Net                                        (89,715)         (94,128)          106,786
Dividends Paid on Common Stock                                                    (72,794)         (56,889)          (74,212)
Dividends Paid on Cumulative Preferred Stock                                         (229)            (229)             (229)
                                                                                 ---------        ---------         ---------
Net Cash Flows From (Used For) Financing Activities                              (127,590)        (103,268)           31,750
                                                                                 ---------        ---------         ---------

Net Increase (Decrease) in Cash and Cash Equivalents                                9,655           (3,346)            3,508
Cash and Cash Equivalents at Beginning of Period                                    2,069            5,415             1,907
                                                                                 ---------        ---------         ---------
Cash and Cash Equivalents at End of Period                                        $11,724           $2,069            $5,415
                                                                                 =========        =========         =========

</TABLE>

SUPPLEMENTAL DISCLOSURE:
Cash paid for interest net of capitalized amounts was $57,775,000, $49,008,000
and $51,126,000 and for income taxes was $33,616,000, $60,451,000 and
$49,901,000 in 2003, 2002 and 2001, respectively.

Noncash activity in 2003 included an increase in assets and liabilities of $78
million resulting from the consolidation of Sabine Mining Company (see Note 2).

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



<PAGE>
<TABLE>
<CAPTION>


                                           SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                              CONSOLIDATED STATEMENTS OF CAPITALIZATION
                                                      December 31, 2003 and 2002



                                                                                                    2003               2002
                                                                                                    ----               ----
                                                                                                         (in thousands)

<C>                                                                                             <C>                <C>
COMMON SHAREHOLDER'S EQUITY                                                                       $696,660           $661,769
                                                                                                -----------        -----------

PREFERRED STOCK: $100 par value - authorized shares 1,860,000


              Call Price                                                      Shares
             December 31,            Number of Shares Redeemed             Outstanding
Series           2003                 Year Ended December 31,            December 31, 2003
------       ------------          ------------------------------        -----------------
                                   2003         2002         2001
                                   ----         ----         ----

Not Subject to Mandatory Redemption:

4.28%             $103.90            -            -           -                7,386                   740                740
4.65%             $102.75            -            -           -                1,907                   190                190
5.00%             $109.00           12            -           -               37,703                 3,770              3,771
                                                                                                -----------        -----------

Total Preferred Stock                                                                                4,700              4,701
                                                                                                -----------        -----------


TRUST PREFERRED SECURITIES:
SWEPCo-Obligated, Mandatorily Redeemable Preferred
    Securities of Subsidiary Trust Holding Solely
    Junior Subordinated Debentures of SWEPCo, 7.875%,
    due April 30, 2037 (a)                                                                               -            110,000
                                                                                                -----------        -----------

LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds                                                                               215,712            315,420
Installment Purchase Contracts                                                                     178,531            179,183
Senior Unsecured Notes                                                                             299,216            198,845
Notes Payable to Trust (a)                                                                         113,009                  -
Notes Payable                                                                                       77,840                  -
Less Portion Due Within One Year                                                                  (142,714)           (55,595)
                                                                                                -----------        -----------

Long-term Debt Excluding Portion Due Within One Year                                               741,594            637,853
                                                                                                -----------        -----------

TOTAL CAPITALIZATION                                                                            $1,442,954         $1,414,323
                                                                                                ===========        ===========

</TABLE>

(a) See Note 16 for Notes Payable to Trust.

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


<PAGE>




                SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                           SCHEDULE OF LONG-TERM DEBT
                           December 31, 2003 and 2002

First Mortgage Bonds outstanding were as follows:

                                             2003                  2002
                                             ----                  ----
 %Rate        Due                                  (in thousands)
 -----        ---
 6-5/8        2003 - February 1                 $-               $55,000
 7-3/4        2004 - June 1                 40,000                40,000
 6.20         2006 - November 1              5,360                 5,505
 6.20         2006 - November 1              1,000                 1,000
 7.00         2007 - September 1            90,000                90,000
 7-1/4        2023 - July 1                      -                45,000
 6-7/8        2025 - October 1 (a)          80,000                80,000
 Unamortized Discount                         (648)               (1,085)
                                          ---------             ---------
 Total                                    $215,712              $315,420
                                          =========             =========

(a) This bond was redeemed on March 1, 2004 and has been classified for payment
in 2004.

First Mortgage Bonds are secured by a first mortgage lien on electric utility
plant. The indenture, as supplemented, relating to the first mortgage bonds
contains maintenance and replacement provisions requiring the deposit of cash or
bonds with the trustee, or in lieu thereof, certification of unfunded property
additions.

Installment Purchase Contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                                                    2003                2002
                                                    ----                ----
  %Rate                     Due                          (in thousands)
  -----                     ---
 Desoto County:
  7.60                      2019 - January 1       $53,500             $53,500

 Sabine River Authority of Texas:
  6.10                      2018 - April 1          81,700              81,700

 Titus County:
  6.90                      2004 - November 1       12,290              12,290
  6.00                      2008 - January 1        12,170              12,620
  8.20                      2011 - August 1         17,125              17,125
  Unamortized Premium                                1,746               1,948
                                                  ---------           ---------
  Total                                           $178,531            $179,183
                                                  =========           =========

Under the terms of the installment purchase contracts, SWEPCo is required to pay
amounts sufficient to enable the payment of interest on and the principal of (at
stated maturities and upon mandatory redemptions) related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain plants.

Senior Unsecured Notes outstanding were as follows:

                                                2003               2002
                                                ----               ----
 %Rate                  Due                         (in thousands)
 -----                  ---
 4.50                   2005 - July 1         $200,000           $200,000
 5.38                   2015 - April 15        100,000                 -
 Unamortized Discount                             (784)            (1,155)
                                              ---------          ---------
 Total                                        $299,216           $198,845
                                              =========          =========

Notes Payable to Trust was outstanding as follows:

                                                2003              2002
                                                ----              ----
 %Rate                  Due                         (in thousands)
 -----                  ---
 5.25% (a)              2043 - October 1      $113,403                 $-
 Unamortized Discount                             (394)                 -
                                              ---------                ---
 Total                                        $113,009                 $-
                                              =========                ===

(a) The 5.25% interest rate is thru September 10, 2008 after which they become
floating rate bonds if the notes are not remarketed.

See Note 16 for discussion of Notes Payable to Trust.

Notes Payable outstanding were as follows:

                                                   2003                2002
                                                   ----                ----
        %Rate        Due                                (in thousands)
        -----        ---
Sabine Mining Company (a):
        6.36         2007 - February 22            $4,000               $-
        (b)          2008 - June 30                13,500                -
        7.03         2012 - February 22            20,000                -

Dolet Hills Lignite Company:
        4.47         2011 - May 16                 40,340                -
                                                  --------              ---
        Total                                     $77,840               $-
                                                  ========              ===

(a) Sabine Mining Company was consolidated during the third quarter of 2003 due
    to the implementation of FIN 46.
(b) A floating interest rate is determined quarterly. The rate on December 31,
    2003 was 1.54%.

At December 31, 2003 future annual long-term debt payments are as follows:


                                                         Amount
                                                         ------
                                                      (in thousands)
               2004                                      $142,714
               2005                                       210,424
               2006                                        16,204
               2007                                       104,862
               2008                                        18,401
               Later Years                                391,783
                                                         ---------
               Total Principal Amount                     884,388
               Unamortized Discount                           (80)
                                                         ---------
               Total                                     $884,308
                                                         =========


<PAGE>
<TABLE>
<CAPTION>



                                         SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
                                         INDEX TO NOTES TO RESPECTIVE FINANCIAL STATEMENTS

The notes to SWEPCo's consolidated financial statements are combined with the notes to respective financial statements for other
subsidiary registrants. Listed below are the notes that apply to SWEPCo. The footnotes begin on page L-1.

                                                                                                                      Footnote
                                                                                                                      Reference
                                                                                                                      ---------
<C>                                                                                                                   <C>
Organization and Summary of Significant Accounting Policies                                                           Note 1

New Accounting Pronouncements, Extraordinary Items and Cumulative Effect of Accounting Changes                        Note 2

Goodwill and Other Intangible Assets                                                                                  Note 3

Rate Matters                                                                                                          Note 4

Effects of Regulation                                                                                                 Note 5

Customer Choice and Industry Restructuring                                                                            Note 6

Commitments and Contingencies                                                                                         Note 7

Guarantees                                                                                                            Note 8

Sustained Earnings Improvement Initiative                                                                             Note 9

Acquisitions, Dispositions, Impairments, Assets Held for Sale and Assets Held and Used                                Note 10

Benefit Plans                                                                                                         Note 11

Business Segments                                                                                                     Note 12

Derivatives, Hedging and Financial Instruments                                                                        Note 13

Income Taxes                                                                                                          Note 14

Leases                                                                                                                Note 15

Financing Activities                                                                                                  Note 16

Related Party Transactions                                                                                            Note 17

Jointly Owned Electric Utility Plant                                                                                  Note 18

Unaudited Quarterly Financial Information                                                                             Note 19

</TABLE>

<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Southwestern Electric Power Company:

We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southwestern Electric Power Company Consolidated
as of December 31, 2003 and 2002, and the related consolidated statements of
income, changes in common shareholder's equity and comprehensive income and cash
flows for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Southwestern Electric Power Company
Consolidated as of December 31, 2003 and 2002, and the results of its operations
and its cash flows for each of the three years in the period ended December 31,
2003 in conformity with accounting principles generally accepted in the United
States of America.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted SFAS 143, "Accounting for Asset Retirement Obligations," effective
January 1, 2003.

As discussed in Note 2 to the consolidated financial statements, the Company
adopted FIN 46, "Consolidation of Variable Interest Entities," effective July 1,
2003.


/s/ Deloitte & Touche LLP

Columbus, Ohio
March 5, 2004

<PAGE>

                    NOTES TO RESPECTIVE FINANCIAL STATEMENTS
                    ----------------------------------------


The notes to respective financial statements that follow are a combined
presentation for AEP's subsidiary registrants. The following list indicates the
registrants to which the footnotes apply:
<TABLE>
<CAPTION>

<C>          <C>                                   <C>
1.           Organization and                      AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
               Summary of Significant
               Accounting Policies

2.           New Accounting                        AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
               Pronouncements, Extraordinary
               Items and Cumulative Effect of
               Accounting Changes

3.           Goodwill and Other                    SWEPCo
               Intangible Assets

4.           Rate Matters                          APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

5.           Effects of Regulation                 AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

6.           Customer Choice and                   APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC
               Industry Restructuring

7.           Commitments and Contingencies         AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

8.           Guarantees                            AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

9.           Sustained Earnings Improvement        AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
               Initiative

10.          Acquisitions, Dispositions,           APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo, TCC, TNC
               Impairments, Assets Held for
               Sale and Assets Held and Used

11.          Benefit Plans                         AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

12.          Business Segments                     AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

13.          Derivatives, Hedging and              AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
               Financial Instruments

14.          Income Taxes                          AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

15.          Leases                                AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

16.          Financing Activities                  AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

17.          Related Party Transactions            AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

18.          Jointly Owned Electric Utility        CSPCo, PSO, SWEPCo, TCC, TNC
               Plant

19.          Unaudited Quarterly Financial         AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC
               Information

20.          Subsequent Events (Unaudited)         TCC
</TABLE>



<PAGE>


  1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
  ---------------------------------------------------------------


ORGANIZATION
------------

The principal business conducted by AEP's ten domestic electric utility
operating companies is the generation, transmission and distribution of
electric power. These companies are subject to regulation by the FERC
under the Federal Power Act and maintain accounts in accordance with
FERC and other regulatory guidelines. These companies are subject to
further regulation with regard to rates and other matters by state
regulatory commissions.

With the exception of AEGCo, AEP's registrant subsidiaries engage in
wholesale marketing and risk management activities in the United States.
In addition, I&M provides barging services to both affiliated and
nonaffiliated companies.

See Note 10 for additional information regarding asset impairments and
assets and liabilities held for sale related to our Texas generation
plants.

Certain previously reported amounts have been reclassified to conform to
current classifications with no effect on net income or shareholders'
equity.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
------------------------------------------

Rate Regulation
---------------

AEP and its subsidiaries are subject to regulation by the SEC under the
PUHCA. The rates charged by the utility subsidiaries are approved by the
FERC and the state utility commissions. The FERC regulates wholesale
electricity operations and transmission rates and the state commissions
regulate retail rates.

Principles of Consolidation
---------------------------

The consolidated financial statements for APCo, CSPCo, I&M, OPCO, SWEPCo
and TCC include the registrant and its wholly-owned subsidiaries and/or
substantially controlled variable interest entities. Intercompany items
are eliminated in consolidation. Equity investments not substantially
controlled that are 50% or less owned are accounted for using the equity
method of accounting; equity earnings are included in Nonoperating
Income.

Accounting for the Effects of Cost-Based Regulation
---------------------------------------------------

As cost-based rate-regulated electric public utility companies, the
consolidated financial statements reflect the actions of regulators that
result in the recognition of revenues and expenses in different time
periods than enterprises that are not rate-regulated. Regulatory assets
(deferred expenses) and regulatory liabilities (future revenue
reductions or refunds) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through regulated
revenues. The following subsidiaries discontinued the application of
SFAS 71 for the generation portion of their business as follows: in Ohio
by OPCo and CSPCo in September 2000, in Virginia and West Virginia by
APCo in June 2000, in Texas by TCC, TNC, and SWEPCo in September 1999,
in Arkansas by SWEPCo in September 1999 and in the FERC jurisdiction for
TNC in December 2003. During 2003, APCo reapplied SFAS 71 for West
Virginia and SWEPCo reapplied SFAS 71 for Arkansas.

Use of Estimates
----------------

The preparation of these financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the
amounts reported in the financial statements and accompanying notes.
These estimates include but are not limited to inventory valuation,
allowance for doubtful accounts, unbilled electricity revenue, values of
long-term energy contracts, the effects of regulation, long-lived asset
recovery, the effects of contingencies and certain assumptions made in
accounting for pension benefits. Actual results could differ from those
estimates.


Property, Plant and Equipment
-----------------------------

Domestic electric utility property, plant and equipment are stated at
original purchase cost. Property, plant and equipment of the
non-regulated operations and other investments are stated at their fair
market value at acquisition (or as adjusted for any applicable
impairments) plus the original cost of property acquired or constructed
since the acquisition, less disposals. Additions, major replacements and
betterments are added to the plant accounts. For cost-based
rate-regulated operations, retirements from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation. For non-regulated operations, retirements from the plant
accounts and associated salvage are deducted from accumulated
depreciation and removal costs are charged to expense. The costs of
labor, materials and overhead incurred to operate and maintain plant are
included in operating expenses. Assets are tested for impairment as
required under SFAS 144 (see Note 10).

Allowance for Funds Used During Construction (AFUDC)and Interest Capitalization
-------------------------------------------------------------------------------

AFUDC represents the estimated cost of borrowed and equity funds used to
finance construction projects that is capitalized and recovered through
depreciation over the service life of domestic regulated electric
utility plant. For non-regulated operations, interest is capitalized
during construction in accordance with SFAS 34, "Capitalization of
Interest Costs." Capitalized interest is also recorded for domestic
generating assets in Ohio, Texas and Virginia, effective with the
discontinuance of SFAS 71 regulatory accounting. The amounts of AFUDC
and interest capitalized were not material in 2003, 2002 and 2001.

Depreciation, Depletion and Amortization
----------------------------------------

We provide for depreciation of property, plant and equipment on a
straight-line basis over the estimated useful lives of property,
excluding coal-mining properties, through the use of composite rates by
functional class. The following table provides the annual composite
depreciation rates by functional class generally used by the AEP
registrant subsidiaries for the year 2003:
<TABLE>
<CAPTION>


                         Nuclear        Steam          Hydro            Transmission          Distribution        General
                         -------        -----          -----            ------------          ------------        -------

   <C>                    <C>             <C>            <C>               <C>                   <C>               <C>
   AEGCo                    - %           3.5%             - %               - %                    - %            16.7%
   APCo                     -             3.3            2.7               2.2                    3.3               9.3
   CSPCo                    -             3.0              -               2.3                    3.6               9.9
   I&M                    3.4             4.6            3.4               1.9                    4.2              11.8
   KPCo                     -             3.8              -               1.7                    3.5               7.1
   OPCo                     -             2.8            2.7               2.3                    4.0              10.5
   PSO                      -             2.7              -               2.3                    3.4               9.7
   SWEPCo                   -             3.3              -               2.8                    3.6               8.0
   TCC                    2.5             2.3            1.9               2.3                    3.5               8.1
   TNC                      -             2.6              -               3.1                    3.3              10.2
</TABLE>


The annual composite depreciation rates by functional class generally
used by the AEP registrant subsidiaries for the years 2002 and 2001 were
as follows:
<TABLE>
<CAPTION>


                         Nuclear        Steam          Hydro            Transmission          Distribution        General


<C>                       <C>             <C>            <C>               <C>                   <C>                <C>
   AEGCo                    - %           3.5%             - %               - %                    - %             2.8%
   APCo                     -             3.4            2.9               2.2                    3.3               3.1
   CSPCo                    -             3.2              -               2.3                    3.6               3.2
   I&M                    3.4             4.5            3.4               1.9                    4.2               3.8
   KPCo                     -             3.8              -               1.7                    3.5               2.5
   OPCo                     -             3.4            2.7               2.3                    4.0               2.7
   PSO                      -             2.7              -               2.3                    3.4               6.3
   SWEPCo                   -             3.4              -               2.7                    3.6               4.7
   TCC                    2.5             2.6            1.9               2.3                    3.5               4.0
   TNC                      -             2.8              -               3.1                    3.3               6.8
</TABLE>


We provide for depreciation, depletion and amortization of coal-mining
assets over each asset's estimated useful life or the estimated life of
each mine, whichever is shorter, using the straight-line method for
mining structures and equipment. We use either the straight-line method
or the units-of-production method to amortize mine development costs and
deplete coal rights based on estimated recoverable tonnages. We include
these costs in the cost of coal charged to fuel expense. Average
amortization rates for coal rights and mine development costs related to
SWEPCo were $0.41 per ton in 2003, 2002 and 2001 and related to OPCo
were $3.46 per ton in 2001. In 2001, OPCo sold coal mines in Ohio and
West Virginia.

Valuation of Non-Derivative Financial Instruments
-------------------------------------------------

The book values of Cash and Cash Equivalents, Accounts Receivable,
Short-term Debt and Accounts Payable approximate fair value because of
the short-term maturity of these instruments. The book value of the
pre-April 1983 spent nuclear fuel disposal liability for I&M
approximates the best estimate of its fair value.

Cash and Cash Equivalents
-------------------------

Cash and cash equivalents include temporary cash investments with
original maturities of three months or less.

Inventory
---------

Except for PSO, TCC and TNC, the regulated domestic utility companies
value fossil fuel inventories using a weighted average cost method. PSO,
TCC and TNC, utilize the LIFO method to value fossil fuel inventories.
For those domestic utilities whose generation is unregulated, inventory
of coal and oil is carried at the lower of cost or market. Coal mine
inventories are also carried at the lower of cost or market. Materials
and supplies inventories are carried at average cost.

Accounts Receivable
-------------------

Customer accounts receivable primarily includes receivables from
wholesale and retail energy customers, receivables from energy contract
counterparties related to our risk management activities and customer
receivables primarily related to other revenue-generating activities.

Revenue is recognized from electric power sales when power is delivered
to customers. To the extent that deliveries have occurred but a bill has
not been issued, AEP and its registrant subsidiaries accrue and
recognize, as Accrued Unbilled Revenues, an estimate of the revenues for
energy delivered since the latest billings.

AEP Credit, Inc. factors accounts receivable for certain registrant
subsidiaries. These subsidiaries include CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and a portion of APCo. Since APCo does not have regulatory
authority to sell accounts receivable in all of its regulatory
jurisdictions, only a portion of APCo's accounts receivable are sold to
AEP Credit. AEP Credit has a sale of receivables agreement with banks
and commercial paper conduits. Under the sale of receivables agreement,
AEP Credit sells an interest in the receivables it acquires to the
commercial paper conduits and banks and receives cash. This transaction
constitutes a sale of receivables in accordance with SFAS 140, allowing
the receivables to be taken off of the company's balance sheet. See Note
16 for further details.

Deferred Fuel Costs
-------------------

The cost of fuel consumed is charged to expense when the fuel is burned.
Where applicable under governing state regulatory commission retail rate
orders, fuel cost over-recoveries (the excess of fuel revenues billed to
ratepayers over fuel costs incurred) are deferred as regulatory
liabilities and under-recoveries (the excess of fuel costs incurred over
fuel revenues billed to ratepayers) are deferred as regulatory assets.
These deferrals are amortized when refunded or billed to customers in
later months with the regulator's review and approval. The amounts of
over-recovery or under-recovery can also be affected by actions of
regulators. When these actions become probable we adjust our deferrals
to recognize these probable outcomes. For the Texas companies, TCC &
TNC, their deferred fuel balances will be included in their 2004 True Up
Proceeding (see Note 6 "Customer Choice and Industry Restructuring").
See Note 5 "Effects of Regulation" for the amount of deferred fuel costs
by registrant subsidiary.

In general, changes in fuel costs in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia
for APCo are timely reflected in rates through the fuel cost adjustment
clauses in place in those states. Where fuel clauses have been
eliminated due to the transition to market pricing, (Ohio effective
January 1, 2001 and in the Texas ERCOT area effective January 1, 2002)
changes in fuel costs impact earnings. In other state jurisdictions,
(Indiana, Michigan and West Virginia) where fuel clauses have been
frozen or suspended for a period of years, fuel cost changes have also
impacted earnings. The Michigan fuel clause suspension ended December
31, 2003, and the Indiana freeze is scheduled to end on March 1, 2004.
See Note 4, "Rate Matters" and Note 6, "Customer Choice and Industry
Restructuring" for further information about fuel recovery.

Revenue Recognition
-------------------

Regulatory Accounting
---------------------

The consolidated financial statements of the registrant subsidiary
companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and
a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate
regulated. In accordance with SFAS 71, regulatory assets (deferred
expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect
the economic effects of regulation by matching expenses with their
recovery through regulated revenues in the same accounting period and by
matching income with its passage to customers through regulated revenues
in the same accounting period. Regulatory liabilities (unrealized gains)
or regulatory assets (unrealized losses) are also recorded for changes
in the fair value of physical and financial contracts that meet the
definition of a derivative as defined in SFAS 133 and are subject to the
regulated ratemaking process.

When regulatory assets are probable of recovery through regulated rates,
certain registrant subsidiaries record them as assets on the balance
sheet. Registrant subsidiaries test for probability of recovery whenever
new events occur, for example a regulatory commission order or passage
of new legislation. If registrant subsidiaries determine that recovery
of a regulatory asset is no longer probable, they write off that
regulatory asset as a charge against net income. A write off of
regulatory assets may also reduce future cash flows since there may be
no recovery through regulated rates.

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

Revenues are recognized on the accrual or settlement basis for normal
retail and wholesale electricity supply sales and electricity
transmission and distribution delivery services. The revenues are
recognized and recorded when the energy is delivered to the customer and
include estimated unbilled as well as billed amounts. In general,
expenses are recorded when purchased electricity is received and when
expenses are incurred.

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

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

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

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

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

All of the registrant subsidiaries except AEGCo participate in wholesale
marketing and risk management activities in electricity and gas. For
I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract
settles the total gain or loss is realized in revenues. Where the
revenues are recorded on the income statement depends on whether the
contract is subject to the regulated ratemaking process. For contracts
subject to the regulated ratemaking process the total gain or loss
realized for sales and the cost of purchased energy are included in
revenues on a net basis. Prior to settlement, changes in the fair value
of physical and financial forward sale and purchase contracts subject to
the regulated ratemaking process are deferred as regulatory liabilities
(gains) or regulatory assets (losses). For contracts not subject to the
ratemaking process only the difference between the accumulated
unrealized net gains or losses recorded in prior periods and the cash
proceeds are recognized in the income statement as nonoperating income.
Prior to settlement, changes in the fair value of physical and financial
forward sale and purchase contracts not subject to the ratemaking
process are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the balance sheets as
Risk Management Assets or Liabilities as appropriate.

For APCo, CSPCo and OPCo, depending on whether the delivery point for
the electricity is in the traditional marketing area or not determines
where the contract is reported in the income statement. Physical forward
risk management sale and purchase contracts with delivery points in the
traditional marketing area are included in revenues on a net basis.
Prior to settlement, changes in the fair value of physical forward sale
and purchase contracts in the traditional marketing area are also
included in revenues on a net basis. Physical forward sale and purchase
contracts for delivery outside of the traditional marketing area are
included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of the traditional
marketing area are included in nonoperating income on a net basis.

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

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

Certain derivative instruments are designated as a hedge of a forecasted
transaction or future cash flow (cash flow hedge) or as a hedge of a
recognized asset, liability or firm commitment (fair value hedge). The gains
or losses on derivatives designated as fair value hedges are recongized
in Revenues in the Consolidated Statement of Operations in the period of
change together with the offseting losses or gains on the hedged item
attributable to the risks being hedged. For derivatives designated as
cash flow hedges, the effective portion of the derivatives' gain or loss
is initially reported as a component of Accumulated Other Comprehensive
Income and subsequently reclassified into Revenues in the Consolidated
Statement of Operations when the forecasted transaction affects earnings.
The ineffective portion of the gain or loss is recognized in Revenues in
the Consolidated Statement of Operations immediately (see Note 13).

Registrant subsidiaries measure the fair values of derivative
instruments and hedge instruments accounted for using mark-to-market
accounting based on exchange prices and broker quotes. If a quoted
market price is not available, registrant subsidiaries estimate the fair
value based on the best information available including valuation models
that estimate future energy prices based on existing market and broker
quotes, supply and demand market data, and other assumptions. Registrant
subsidiaries reduce fair values by estimated valuation adjustments for
items such as discounting, liquidity and credit quality. There are
inherent risks related to the underlying assumptions in models used to
fair value open long-term derivative contracts.

Registrant subsidiaries have independent controls to evaluate the
reasonableness of our valuation models. However, energy markets,
especially electricity markets, are imperfect and volatile. Unforeseen
events can and will cause reasonable price curves to differ from actual
prices throughout a contract's term and at the time a contract settles.
Therefore, there could be significant adverse or favorable effects on
future results of operations and cash flows if market prices are not
consistent with our approach at estimating current market consensus for
forward prices in the current period. This is particularly true for
long-term contracts.

Registrant subsidiaries recognize all derivative instruments at fair
value in our balance sheets as either Risk Management Assets or Risk
Management Liabilities. Registrant subsidiaries do not consider
contracts that have been elected normal purchase or normal sale under
SFAS 133 to be derivatives. Unrealized and realized gains and losses on
all derivative instruments are ultimately included in revenues in the
income statement on a net basis.

Debt Instrument Hedging and Related Activities
----------------------------------------------

In order to mitigate the risks of market price and interest rate
fluctuations, registrant subsidiaries enter into contracts to manage the
exposure to unfavorable changes in the cost of debt to be issued. These
anticipatory hedges are entered into in order to manage the change in
interest rates between the time a debt offering is initiated and the
issuance of the debt (usually a period of 60 days). Gains or losses from
these transactions are deferred and amortized over the life of the debt
issuance with the amortization included in interest charges. There were
no such forward contracts outstanding at December 31, 2003 or 2002.

Levelization of Nuclear Refueling Outage Costs
----------------------------------------------

In order to match costs with regulated revenues, incremental operation
and maintenance costs associated with periodic refueling outages at
I&M's Cook Plant are deferred and amortized over the period beginning
with the commencement of an outage and ending with the beginning of the
next outage.

Maintenance Costs
-----------------

Maintenance costs are expensed as incurred. If it becomes probable that
registrant subsidiaries will recover specifically incurred costs through
future rates a regulatory asset is established to match the expensing of
maintenance costs with their recovery in cost-based regulated revenues.

Income Taxes and Investment Tax Credits
---------------------------------------

Registrant Subsidiaries use the liability method of accounting for
income taxes. Under the liability method, deferred income taxes are
provided for all temporary differences between the book cost and tax
basis of assets and liabilities which will result in a future tax
consequence.

The flow-through method of accounting for temporary differences is
reflected in regulated revenues (that is, when deferred taxes are not
included in the cost of service for determining regulated rates for
electricity), deferred income taxes are recorded and related regulatory
assets and liabilities are established to match the regulated revenues
and tax expense.

Investment tax credits have been accounted for under the flow-through
method except where regulatory commissions have reflected investment tax
credits in the rate-making process on a deferral basis. Investment tax
credits that have been deferred are being amortized over the life of the
regulated plant investment.

Excise Taxes
------------

Registrant subsidiaries, as agents for some state and local governments
collect from customers certain excise taxes levied by those state or
local governments on our customers. We do not record these taxes as
revenue or expense.

Debt and Preferred Stock
------------------------

Gains and losses from the reacquisition of debt used to finance domestic
regulated electric utility plant are generally deferred and amortized
over the remaining term of the reacquired debt in accordance with their
rate-making treatment unless the debt is refinanced. If the reacquired
debt, associated with the regulated business, is refinanced, the
reacquisition costs attributable to the portions of the business that
are subject to cost based regulatory accounting are generally deferred
and amortized over the term of the replacement debt consistent with its
recovery in rates. We report gains and losses on the reacquisition of
debt for operations that are not subject to cost-based rate regulation
in Nonoperating Income or Nonoperating Expenses.

Debt discount or premium and debt issuance expenses are deferred and
amortized utilizing the effective interest rate method over the term of
the related debt. The amortization expense is included in interest
charges.

Where reflected in rates, redemption premiums paid to reacquire
preferred stock of certain domestic utility subsidiaries are included in
paid-in capital and amortized to retained earnings commensurate with
their recovery in rates. The excess of par value over costs of preferred
stock reacquired is credited to paid-in capital and amortized to
retained earnings consistent with the timing of its inclusion in rates
in accordance with SFAS 71.

Goodwill and Intangible Assets
------------------------------

In the first quarter of fiscal 2002, AEP's registrant subsidiaries
adopted SFAS No. 142, "Goodwill and Other Intangible Assets" which
revises the accounting for purchased goodwill and other intangible
assets. Under SFAS No. 142, purchased goodwill and intangible assets
with indefinite lives are no longer amortized, but instead tested for
impairment at least annually. Intangible assets with finite lives,
requires that they be amortized over their respective estimated lives to
the estimated residual values. The AEP registrant subsidiaries have no
recorded goodwill and intangible assets with indefinite lives as of
December 31, 2003 and 2002. SWEPCo is the only AEP registrant with an
intangible asset with a finite life on its books. See Note 3 for further
information about SWEPCo's intangible asset.

Nuclear Trust Funds
-------------------

Nuclear decommissioning and spent nuclear fuel trust funds represent
funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal
liabilities. By rules or orders, the state jurisdictional commissions
(Indiana, Michigan and Texas) and the FERC have established investment
limitations and general risk management guidelines. In general,
limitations include:

o  Acceptable investments (rated investment grade or above)
o  Maximum percentage invested in a specific type of investment
o  Prohibition of investment in obligations of the applicable company or its
   affiliates

Trust funds are maintained for each regulatory jurisdiction and managed
by investment managers external to AEP subsidiaries, who must comply
with the guidelines and rules of the applicable regulatory authorities.
The trust assets are invested in order to optimize the after-tax
earnings of the trust, giving consideration to liquidity, risk,
diversification, and other prudent investment objectives.

Securities held in trust funds for decommissioning nuclear facilities
and for the disposal of spent nuclear fuel are included in Nuclear
Decommissioning and Spent Nuclear Fuel Disposal Trust Funds for amounts
relating to the Cook Plant and are included in Assets Held for Sale for
amounts relating to the Texas Plants. See "Assets Held for Sale" section
of Note 10 for further information regarding the Texas Plants. These
securities are recorded at market value. Securities in the trust funds
have been classified as available-for-sale due to their long-term
purpose. Unrealized gains and losses from securities in these trust
funds are reported as adjustments to the regulatory liability account
for the nuclear decommissioning trust funds and to regulatory assets or
liabilities for the spent nuclear fuel disposal trust funds in
accordance with their treatment in rates.

Comprehensive Income (Loss)
---------------------------

Comprehensive income (loss) is defined as the change in equity (net
assets) of a business enterprise during a period from transactions and
other events and circumstances from non-owner sources. It includes all
changes in equity during a period except those resulting from
investments by owners and distributions to owners. Comprehensive income
(loss) has two components: net income (loss) and other comprehensive
income (loss). There were no material differences between net income and
comprehensive income for AEGCo.

Components of Accumulated Other Comprehensive Income (Loss)
-----------------------------------------------------------

Accumulated Other Comprehensive Income (Loss) is included on the balance
sheet in the equity section. Accumulated Other Comprehensive Income
(Loss) for AEP registrant subsidiaries as of December 31, 2003 and 2002
is shown in the following table.

                                               December 31,
   Components                           2003                  2002
   -----------                          ----                  ----
                                              (in thousands)
   Cash Flow Hedges:
           APCo                       $(1,569)             $(1,920)
           CSPCo                          202                 (267)
           I&M                            222                 (286)
           KPCo                           420                  322
           OPCo                          (103)                (738)
           PSO                            156                  (42)
           SWEPCo                         184                  (48)
           TCC                         (1,828)                 (36)
           TNC                           (601)                 (15)

   Minimum Pension Liability:
           APCo                      $(50,519)            $(70,162)
           CSPCo                      (46,529)             (59,090)
           I&M                        (25,328)             (40,201)
           KPCo                        (6,633)              (9,773)
           OPCo                       (48,704)             (72,148)
           PSO                        (43,998)             (54,431)
           SWEPCo                     (44,094)             (53,635)
           TCC                        (60,044)             (73,124)
           TNC                        (26,117)             (30,748)

Earnings Per Share (EPS)
------------------------

AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC are
wholly-owned subsidiaries of AEP and are not required to report EPS.

Supplementary Information
-------------------------

The amounts of power purchased by the registrant subsidiaries from Ohio
Valley Electric Corporation, which is 44.2% owned by the AEP System, for
the years ended December 31, 2003, 2002 and 2001 were:

                                  APCo         CSPCo         I&M         OPCo
                                  ----         -----         ---         ----
                                               (in thousands)
Year Ended December 31, 2003    $55,219      $15,259      $25,659      $50,995
Year Ended December 31, 2002     53,386       14,885       23,282       50,135
Year Ended December 31, 2001     45,542       12,626       20,723       47,757

Reclassification
----------------

Certain prior period financial statement items have been reclassified to
conform to current period presentation. Such reclassifications had no
impact on previously reported Net Income (Loss).


2.  NEW ACCOUNTING PRONOUNCEMENTS, EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT
    OF ACCOUNTING CHANGES
----------------------------------------------------------------------------

NEW ACCOUNTING PRONOUNCEMENTS
-----------------------------

SFAS 132 (revised 2003) "Employers' Disclosure about Pensions and Other
Postretirement Benefits"
-----------------------------------------------------------------------

In December 2003 the FASB issued SFAS 132 (revised 2003), which requires
additional footnote disclosures about pensions and postretirement
benefits, some of which are effective beginning with the year-end 2003
financial statements. Other additional disclosures will begin with APCo,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC's 2004 quarterly
financial statements.

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC will implement
new quarterly disclosures when they become effective in the first
quarter of 2004, including (a) the amount of net periodic benefit cost
for each period for which an income statement is presented, showing
separately each component thereof, and (b) the amount of employer
contributions paid and expected to be paid during the current year, if
significantly different from amounts disclosed at the most recent
year-end. See Note 11 for these additional 2003 disclosures.

SFAS 142 "Goodwill and Other Intangible Assets"
-----------------------------------------------

SFAS 142 requires that goodwill and intangible assets with indefinite
useful lives no longer be amortized, and that goodwill and intangible
assets be tested annually for impairment. See Note 3 for further
information on goodwill and other intangible assets.

SFAS 143 "Accounting for Asset Retirement Obligations"
------------------------------------------------------

We implemented SFAS 143, "Accounting for Asset Retirement Obligations,"
effective January 1, 2003, which requires entities to record a liability
at fair value for any legal obligations for asset retirements in the
period incurred. Upon establishment of a legal liability, SFAS 143
requires a corresponding asset to be established which will be
depreciated over its useful life. SFAS 143 requires that a cumulative
effect of change in accounting principle be recognized for the
cumulative accretion and accumulated depreciation that would have been
recognized had SFAS 143 been applied to existing legal obligations for
asset retirements. In addition, the cumulative effect of change in
accounting principle is favorably affected by the reversal of
accumulated removal cost. These costs had previously been recorded for
generation and did not qualify as a legal obligation although these
costs were collected in depreciation rates by certain formerly regulated
subsidiaries.

We completed a review of our asset retirement obligations and concluded
that we have related legal liabilities for nuclear decommissioning costs
for I&M's Cook Plant and TCC's partial ownership in the South Texas
Project, as well as liabilities for the retirement of certain ash ponds.
Since we presently recover our nuclear decommissioning costs in our
regulated cash flow and have existing balances recorded for such nuclear
retirement obligations, we recognized the cumulative difference between
the amount already provided through rates and the amount as measured by
applying SFAS 143, as a regulatory asset or liability. Similarly, a
regulatory asset was recorded for the cumulative effect of certain
retirement costs for ash ponds related to our regulated operations. In
2003, we recorded an unfavorable cumulative effect for the non-regulated
operations. See the table later in this section for a summary by
registrant subsidiary of the cumulative effect of changes in accounting
principles for the year ended December 31, 2003.

Certain of AEP's registrant subsidiaries have collected removal costs
from ratepayers for certain assets that do not have associated legal
asset retirement obligations. To the extent that such registrant
subsidiaries have now been deregulated, the registrant subsidiaries
reversed the balance of such removal costs which resulted in a net
favorable cumulative effect in 2003. The following is a summary by
registrant subsidiary of the removal costs reclassified from Accumulated
Depreciation and Amortization to Asset Removal Costs in 2003 and to
Deferred Credits and Other in 2002 (Other on AEGCo's 2002 Balance
Sheet):

                              December 31, 2003          December 31, 2002
                              -----------------          -----------------
                                            (in millions)
    AEGCo                           $ 27.8                   $ 28.0
    APCo                              92.5                     94.6
    CSPCo                             99.1                     96.0
    I&M                              263.0                    250.5
    KPCo                              26.1                     23.7
    OPCo                             101.2                     97.0
    PSO                              214.0                    202.6
    SWEPCo                           236.4                    219.5
    TCC (a)                          104.8                     97.5
    TNC                               76.7                     75.0

    (a)   Includes $9 million classified as
          Liabilities Held for Sale - Texas
          Generation Plants on TCC's Consolidated
          Balance Sheets as of December 31, 2003 and 2002.

The following is a summary by registrant subsidiary of the cumulative
effect of change in accounting principle, as a result of SFAS 143, for
the year ended December 31, 2003:

                 Pre-tax Income (Loss)               After-tax Income (Loss)
              ---------------------------          --------------------------
                                       (in millions)
                                Reversal of                         Reversal of
                                  Cost of                             Cost of
               Ash Ponds          Removal          Ash Ponds          Removal
               ---------          -------          ---------          -------
 AEGCo           $   -             $   -              $  -               $  -
 APCo            (18.2)            146.5             (11.4)              91.7
 CSPCo            (7.8)             56.8              (4.7)              33.9
 I&M                 -                 -                 -                  -
 KPCo                -                 -                 -                  -
 OPCo            (36.8)            250.4             (21.9)             149.3
 PSO                 -                 -                 -                  -
 SWEPCo              -              13.0                 -                8.4
 TCC                 -                 -                 -                  -
 TNC                 -               4.7                 -                3.1

We have identified, but not recognized, asset retirement obligation
liabilities related to electric transmission and distribution as a
result of certain easements on property on which we have assets.
Generally, such easements are perpetual and require only the retirement
and removal of our assets upon the cessation of the property's use. The
retirement obligation is not estimable for such easements since we plan
to use our facilities indefinitely. The retirement obligation would only
be recognized if and when we abandon or cease the use of specific
easements.

The following is a reconciliation of beginning and ending aggregate
carrying amounts of asset retirement obligations by registrant
subsidiary following the adoption of SFAS 143:
<TABLE>
<CAPTION>


                                    Balance At                                               Balance at
                                    January 1,                             Liabilities      December 31,
                                      2003                Accretion         Incurred            2003
                                    ----------            ---------        -----------      ------------
     <C>                              <C>                  <C>                <C>              <C>
     AEGCo (a)                         $1.1                  $-                 $-              $1.1
     APCo (a)                          20.1                 1.6                  -              21.7
     CSPCo (a)                          8.1                 0.6                  -               8.7
     I&M (b)                          516.1                37.1                  -             553.2
     OPCo (a)                          39.5                 3.2                  -              42.7
     SWEPCo (d)                           -                 0.3                8.1               8.4
     TCC (c)                          203.2                15.6                  -             218.8
</TABLE>


      (a) Consists of asset retirement obligations related to ash ponds.
      (b) Consists of asset retirement obligations related to ash ponds
          ($1.1 million at December 31, 2003) and nuclear decommissioning
          costs for the Cook Plant ($552.1 million at December 31, 2003).
      (c) Consists of asset retirement obligations related to nuclear
          decommissioning costs for STP included in Liabilities Held for Sale -
          Texas Generation Plants on TCC's consolidated Balance Sheets.
      (d) Consists of asset retirement obligations related to Sabine
          Mining which is now being consolidated under FIN 46 (see FIN 46
          "Consolidation of Variable Interest Entities" later in this note).

Accretion expense is included in Other Operation expense in the
respective income statements of the individual subsidiary registrants.

As of December 31, 2003 and 2002, the fair value of assets that are
legally restricted for purposes of settling the nuclear decommissioning
liabilities totaled $845 million ($720 million for I&M and $125 million
for TCC) and $716 million ($618 million for I&M and $98 million for
TCC), respectively, recorded in Nuclear Decommissioning and Spent
Nuclear Fuel Disposal Trust Funds on I&M's Consolidated Balance Sheets
and in Assets Held for Sale-Texas Generation Plants on TCC's
Consolidated Balance Sheets.

Pro forma net income has not been presented for the years ended December
31, 2002 and 2001 because the pro forma application of SFAS 143 would
result in pro forma net income not materially different from the actual
amounts reported for those periods.

The following is a summary by registrant subsidiary of the pro forma
liability for asset retirement obligations which has been calculated as
if SFAS 143 had been adopted as of the beginning of each period
presented:

                                 December 31,
                      ------------------------------------
                      2002            2001            2000
                      ----            ----            ----
                                 (in millions)
        AEGCo       $  1.1          $  1.0            $0.9
        APCo          20.1            18.7            17.3
        CSPCo          8.1             7.5             6.9
        I&M          516.1           481.4           449.1
        KPCo             -               -               -
        OPCo          39.5            36.5            33.8
        PSO              -               -               -
        SWEPCo           -               -               -
        TCC          203.2           188.8           175.4
        TNC              -               -               -

SFAS 144 "Accounting for the Impairment or Disposal of Long-lived Assets"
-------------------------------------------------------------------------

In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment
or Disposal of Long-lived Assets" which sets forth the accounting to
recognize and measure an impairment loss. This standard replaced, SFAS
121, "Accounting for Long-lived Assets and for Long-lived Assets to be
Disposed Of." All of the registrant subsidiaries adopted SFAS 144
effective January 1, 2002. See Note 10 for discussion of impairments
recognized in 2003 and 2002.

SFAS 145  "Rescission  of FASB  Statements  No. 4, 44 and 64, Amendment of FASB
Statement No. 13, and  Technical Corrections"
-------------------------------------------------------------------------------

In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS 145). SFAS 145 rescinds SFAS 4, "Reporting Gains and
Losses from Extinguishment of Debt," effective for fiscal years
beginning after May 15, 2002. SFAS 4 required gains and losses from
extinguishment of debt to be aggregated and classified as an
extraordinary item if material. In 2003, TCC reclassified Extraordinary
Losses (Net of Tax) on its reacquired debt of $2 million for 2001 to
Nonoperating Expenses and Nonoperating Income Tax Expense.

SFAS 146 "Accounting for Costs Associated with Exit or Disposal Activities"
---------------------------------------------------------------------------

In June 2002, FASB issued SFAS 146 which addresses accounting for costs
associated with exit or disposal activities. This statement supersedes
previous accounting guidance, principally EITF No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to
Exit an Activity (including Certain Costs Incurred in a Restructuring)."
Under EITF No. 94-3, a liability for an exit cost was recognized at the
date of an entity's commitment to an exit plan. SFAS 146 requires that
the liability for costs associated with an exit or disposal activity be
recognized when the liability is incurred. SFAS 146 also establishes
that the liability should initially be measured and recorded at fair
value. The time at which we recognize future costs related to exit or
disposal activities, including restructuring, as well as the amounts
recognized may be affected by SFAS 146. The registrant subsidiaries
adopted the provisions of SFAS 146 for exit or disposal activities
initiated after December 31, 2002.

SFAS 149 "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"
--------------------------------------------------------------------------

On April 30, 2003, the FASB issued Statement No. 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS
149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative
and the requirements for contracts to qualify as "normal purchase/normal
sale." SFAS 149 also amends certain other existing pronouncements.
Effective July 1, 2003, registrant subsidiaries implemented SFAS 149 and
the effect was not material to our results of operations, cash flows or
financial condition.

SFAS 150  "Accounting for Certain Financial Instruments with Characteristics of
Both Liabilities and Equity"
-------------------------------------------------------------------------------

We implemented SFAS 150 effective July 1, 2003. SFAS 150 is the first
phase of the FASB's project to eliminate from the balance sheet the
"mezzanine" presentation of items with characteristics of both
liabilities and equity, including: (1) mandatorily redeemable shares,
(2) instruments other than shares that could require the issuer to buy
back some of its shares in exchange for cash or other assets and (3)
certain obligations that can be settled with shares. Measurement of
these liabilities generally is to be at fair value, with the payment or
accrual of "dividends" and other amounts to holders reported as interest
cost.

Beginning with our third quarter 2003 financial statements, we present
Cumulative Preferred Stocks Subject to Mandatory Redemption as Liability
for Cumulative Preferred Stock Subject to Mandatory Redemption.
Beginning July 1, 2003, we classify dividends on these mandatorily
redeemable preferred shares as Interest Charges. In accordance with SFAS
150, dividends from prior periods remain classified as Preferred Stock
Dividends.

FIN 45 "Guarantor's  Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of Indebtedness of Others"
---------------------------------------------------------------------------

In November 2002, the FASB issued FIN 45 which clarifies the accounting
to recognize a liability related to issuing a guarantee, as well as
additional disclosures of guarantees. We implemented FIN 45 as of
January 1, 2003, and the effect was not material to our results of
operations, cash flows or financial condition. See Note 8 for further
disclosures.

FIN 46 (revised December 2003)"Consolidation of Variable Interest Entities" and
FIN 46 "Consolidation of Variable Interest Entities"
-------------------------------------------------------------------------------

We implemented FIN 46, "Consolidation of Variable Interest Entities,"
effective July 1, 2003. FIN 46 interprets the application of Accounting
Research Bulletin No. 51, "Consolidated Financial Statements," to
certain entities in which equity investors do not have the
characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities
without additional subordinated financial support from other parties.
Due to the prospective application of FIN 46, we did not reclassify
prior period amounts.

On July 1, 2003, we deconsolidated the trusts which hold mandatorily
redeemable trust preferred securities. Therefore, of the $321 million
net amount ($75 million PSO, $110 million SWEPCo and $136 million TCC),
reported as "Certain Subsidiary Obligated, Mandatorily Redeemable,
Preferred Securities of Subsidiary Trusts Holding Solely Junior
Subordinated Debentures of Such Subsidiaries" at December 31, 2002, $331
million ($77 million PSO, $113 million SWEPCo and $141 million TCC) is
reported as a component of Long-term Debt and $10 million ($2 million
PSO, $3 million SWEPCo and $5 million TCC) is reported in Other
Investments within Other Property and Investments at December 31, 2003.

Effective July 1, 2003, SWEPCo consolidated Sabine Mining Company
(Sabine), a contract mining operation providing mining services to
SWEPCo. Upon consolidation, SWEPCo recorded the assets and liabilities
of Sabine ($78 million). Also, after consolidation, SWEPCo currently
records all expenses (depreciation, interest and other operation
expense) of Sabine and eliminates Sabine's revenues against SWEPCo's
fuel expenses. There is no cumulative effect of an accounting change
recorded as a result of our requirement to consolidate, and there is no
change in net income due to the consolidation of Sabine.

Effective July 1, 2003, OPCo consolidated JMG. Upon consolidation, OPCo
recorded the assets and liabilities of JMG ($469.6 million). OPCo now
records the depreciation, interest and other operating expenses of JMG
and eliminates JMG's revenues against OPCo's operating lease expenses.
There is no cumulative effect of an accounting change recorded as a
result of our requirement to consolidate JMG, and there is no change in
net income due to the consolidation of JMG. See Note 15 "Leases" for
further disclosures.

In December 2003, the FASB issued FIN 46 (revised December 2003) (FIN
46R) which replaces FIN 46. The FASB and other accounting constituencies
continue to interpret the application of FIN 46R. As a result, we are
continuing to review the application of this new interpretation and
expect to adopt FIN 46R by March 31, 2004.

EITF 02-3 and the Rescission of EITF 98-10
------------------------------------------

In October 2002, the Emerging Issues Task Force of the FASB reached a
final consensus on Issue No. 02-3. EITF 02-3 rescinds EITF 98-10 and
related interpretive guidance. Under EITF 02-3, mark-to-market
accounting is precluded for risk management contracts that are not
derivatives pursuant to SFAS 133. The consensus to rescind EITF 98-10
also eliminated the recognition of physical inventories at fair value
other than as provided by GAAP. Registrant subsidiaries have implemented
this standard for all physical inventory and non-derivative risk
management transactions occurring on or after October 25, 2002. For
physical inventory and non-derivative risk management transactions
entered into prior to October 25, 2002, registrant subsidiaries
implemented this standard on January 1, 2003 and reported the effects of
implementation as a cumulative effect of an accounting change (see
"Cumulative Effect of Accounting Change" for a summary by registrant
subsidiary).

Effective January 1, 2003, EITF 02-3 requires that gains and losses on
all derivatives, whether settled financially or physically, be reported
in the income statement on a net basis if the derivatives are held for
risk management purposes. Previous guidance in EITF 98-10 permitted
contracts that were not settled financially to be reported either gross
or net in the income statement. Prior to the third quarter of 2002, the
registrant subsidiaries recorded and reported upon settlement, sales
under forward risk management contracts as revenues. Registrant
subsidiaries also recorded and reported purchases under forward risk
management contracts as purchased energy expenses. Effective July 1,
2002, the registrant subsidiaries reclassified such forward risk
management revenues and purchases on a net basis. The reclassification
of such risk management activities to a net basis of reporting resulted
in a substantial reduction in both revenues and purchased energy
expense, but did not have any impact on financial condition, results of
operations or cash flows.

EITF  03-11  "Reporting  Realized  Gains and  Losses on  Derivative  Instruments
That Are  Subject to FASB Statement No. 133 and Not "Held for Trading Purposes"
as Defined in Issue No. 02-3"
-------------------------------------------------------------------------------

In July 2003, the EITF reached consensus on Issue No. 03-11. The
consensus states that realized gains and losses on derivative contracts
not "held for trading purposes" should be reported either on a net or
gross basis based on the relevant facts and circumstances.
Reclassification of prior year amounts is not required. The adoption of
EITF 03-11 did not have a material impact on our results of operations,
financial position or cash flows.

FASB Staff Position No. 106-1, Accounting and Disclosure Requirements Related
to the Medicare Prescription Drug Improvement and Modernization Act of 2003
-----------------------------------------------------------------------------

On January 12, 2004, the FASB Staff issued FSP 106-1, which allows a
one-time election to defer accounting for any effects of the
prescription drug subsidy under the Medicare Prescription Drug
Improvement and Modernization Act of 2003 (the Act), enacted on December
8, 2003. There are significant uncertainties as to whether AEP's plan
will be eligible for a subsidy under future federal regulations that
have not yet been drafted. The method of accounting for any such subsidy
and, therefore, the subsidy's possible reduction to the accumulated
postretirement benefit obligation and periodic postretirement benefit
costs has not been resolved by the FASB or other professional accounting
standard setting authority. Accordingly, any potential effects of the
Act were deferred until authoritative guidance on the accounting for the
federal subsidy is issued. Measurements of the accumulated
postretirement benefit obligation and periodic postretirement benefit
cost included in these financial statements do not reflect any potential
effects of the Act. APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and
TNC cannot determine what impact, if any, new authoritative guidance on
the accounting for the federal subsidy may have on our results of
operations or financial condition.

Future Accounting Changes
-------------------------

The FASB's standard-setting process is ongoing. Until new standards have
been finalized and issued by FASB, we cannot determine the impact on the
reporting of our operations that may result from any such future
changes.

CUMULATIVE EFFECT OF ACCOUNTING CHANGE
--------------------------------------

Accounting for Risk Management Contracts
----------------------------------------

EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Certain
registrant subsidiaries have recorded after tax charges against net
income as Accounting for Risk Management Contracts in our Consolidated
Statements of Operations in Cumulative Effect of Accounting Changes in
the first quarter of 2003. This amount will be realized when the
positions settle.

The FASB's Derivative Implementation Group (DIG) issued accounting
guidance under SFAS 133 for certain derivative fuel supply contracts
with volumetric optionality and derivative electricity capacity
contracts. This guidance, effective in the third quarter of 2001,
concluded that fuel supply contracts with volumetric optionality cannot
qualify for a normal purchase or sale exclusion from mark-to-market
accounting and provided guidance for determining when certain
option-type contracts and forward contracts in electricity can qualify
for the normal purchase or sale exclusion.

Asset Retirement Obligations (SFAS 143)
---------------------------------------

In the first quarter of 2003, certain of the registrant subsidiaries
recorded in after-tax income a cumulative effect of accounting change
for Asset Retirement Obligations.

The following is a summary by registrant subsidiary of the cumulative
effect of changes in accounting principles recorded in 2003 for the
adoptions of SFAS 143 and EITF 02-3 (no effect on AEGCo or PSO):
<TABLE>
<CAPTION>


                                         SFAS 143 Cumulative Effect                    EITF 02-3 Cumulative Effect
                                    -----------------------------------           ---------------------------------
                                      Pre-tax               After-tax              Pre-tax              After-tax
                                    Income (Loss)         Income (Loss)           Income (Loss)       Income (Loss)
                                    -------------         -------------           -------------       -------------
                                               (in millions)                                  (in millions)

         <C>                           <C>                    <C>                   <C>                   <C>
          APCo                         $128.3                 $ 80.3                $ (4.7)               $ (3.0)
          CSPCo                          49.0                   29.3                  (3.1)                 (2.0)
          I&M                              -                      -                   (4.9)                 (3.2)
          KPCo                             -                      -                   (1.7)                 (1.1)
          OPCo                          213.6                  127.3                  (4.2)                 (2.7)
          SWEPCo                         13.0                    8.4                   0.2                   0.1
          TCC                              -                      -                    0.2                   0.1
          TNC                             4.7                    3.1                     -                     -
</TABLE>


EXTRAORDINARY ITEMS
-------------------

In 2003 an extraordinary item of $177,000, net of tax of $95,000, was
recorded at TNC for the discontinuance of regulatory accounting under
SFAS 71 in compliance with a FERC Order dated December 24, 2003
approving a Settlement. AEP's registrant subsidiaries had no
extraordinary items in 2002. In 2001 an extraordinary item was recorded
for the discontinuance of regulatory accounting under SFAS 71 for the
generation portion of the business in the Ohio state jurisdiction. OPCo
and CSPCo recognized an extraordinary loss of $48 million (net of tax of
$20 million) for unrecoverable Ohio Public Utility Excise Tax (commonly
known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits. This loss resulted from regulatory decisions in connection with
Ohio deregulation which stranded the recovery of the GRT. Effective with
the liability affixing on May 1, 2001, CSPCo and OPCo recorded an
extraordinary loss under SFAS 101. Both Ohio companies appealed to the
Ohio Supreme Court the PUCO order on Ohio restructuring that the Ohio
companies believe failed to provide for recovery for the final year of
the GRT. In April 2002, the Ohio Supreme Court denied recovery of the
final year of the GRT.

3.  GOODWILL AND OTHER INTANGIBLE ASSETS
----------------------------------------

Goodwill
--------

There is no goodwill carried by any of the AEP registrant subsidiaries.

Acquired Intangible Assets
--------------------------

SWEPCo's acquired intangible asset subject to amortization is $21.7
million at December 31, 2003 and $24.7 million at December 31, 2002, net
of accumulated amortization. The gross carrying amount, accumulated
amortization and amortization life are:
<TABLE>
<CAPTION>


                                             December 31, 2003                             December 31, 2002
                               -----------------------------------------------         -------------------------
                                                     Gross                              Gross
                               Amortization         Carrying      Accumulated          Carrying     Accumulated
                                  Life               Amount       Amortization          Amount      Amortization
                               ------------         --------      ------------         --------     ------------
                                (in years)               (in millions)                        (in millions)
<C>                                 <C>              <C>             <C>                <C>            <C>
  Advanced royalties                10               $29.4           $7.7               $29.4          $4.7
</TABLE>



Amortization of the intangible asset was $3.0 million for the twelve
months ended December 31, 2003 and 2002. SWEPCo's estimated aggregate
amortization expense is $3 million for each year 2004 through 2010 and
$1 million in 2011.

4.  RATE MATTERS
----------------

In certain jurisdictions, we have agreed to base rate or fuel recovery
limitations usually under terms of settlement agreements. See Note 5 for
a discussion of those terms related to Nuclear Plant Restart and Merger
with CSW.

Fuel in SPP Area of Texas - Affecting  SWEPCo and TNC
------------------------------------------------------

In 2001, the PUCT delayed the start of customer choice in the SPP area
of Texas. In May 2003, the PUCT ordered that competition would not begin
in the SPP areas before January 1, 2007. TNC filed with the PUCT in 2002
to determine the most appropriate method to reconcile fuel costs in
TNC's SPP area. In April 2003, the PUCT issued an order adopting the
methodology proposed in TNC's filing, with adjustments, for reconciling
fuel costs in the SPP area. The adjustments removed $3.71 per MWH from
reconcilable fuel expense. This adjustment will reduce revenues received
by Mutual Energy SWEPCo who now serves TNC's SPP customers by
approximately $400,000 annually. In October 2003, Mutual Energy SWEPCo
agreed with the PUCT staff and the Office of Public Utility Counsel
(OPC) to file a fuel reconciliation proceeding for the period January
2002 through December 2003 by March 31, 2004 and the PUCT ordered that
the filing be made.

TNC Fuel Reconciliation - Affecting  TNC
----------------------------------------

In June 2002, TNC filed with the PUCT to reconcile fuel costs,
requesting to defer any unrecovered portion applicable to retail sales
within its ERCOT service area for inclusion in the 2004 true-up
proceeding. This reconciliation for the period of July 2000 through
December 2001 will be the final fuel reconciliation for TNC's ERCOT
service territory. At December 31, 2001, the deferred under-recovery
balance associated with TNC's ERCOT service area was $27.5 million
including interest. During the reconciliation period, TNC incurred
$293.7 million of eligible fuel costs serving both ERCOT and SPP retail
customers. TNC also requested authority to surcharge its SPP customers
for under-recovered fuel costs. TNC's SPP customers will continue to be
subject to fuel reconciliations until competition begins in the SPP area
as described above. The under-recovery balance at December 31, 2001 for
TNC's service within SPP was $0.7 million including interest.

In March 2003, the ALJ in this proceeding filed a Proposal for Decision
(PFD) with a recommendation that TNC's under-recovered retail fuel
balance be reduced. In March 2003, TNC established a reserve of $13
million based on the recommendations in the PFD. In May 2003, the PUCT
reversed the ALJ on certain matters and remanded TNC's final fuel
reconciliation to the ALJ to consider two issues. The issues are the
sharing of off-system sales margins from AEP's trading activities with
customers for five years per the PUCT's interpretation of the Texas
AEP/CSW merger settlement and the inclusion of January 2002 fuel factor
revenues and associated costs in the determination of the
under-recovery. The PUCT proposed that the sharing of off-system sales
margins for periods beyond the termination of the fuel factor should be
recognized in the final fuel reconciliation proceeding. This would
result in the sharing of margins for an additional three and one half
years after the end of the Texas ERCOT fuel factor.

On December 3, 2003, the ALJ issued a PFD in the remand phase of the TNC
fuel reconciliation recommending additional disallowances for the two
remand issues. TNC filed responses to the PFD and the PUCT announced a
final ruling in the fuel reconciliation proceeding on January 15, 2004
accepting the PFD. TNC is waiting for a written order, after which it
will request a rehearing of the PUCT's ruling. While management believes
that the Texas merger settlement only provided for sharing of margins
during the period fuel and generation costs were regulated by the PUCT,
an additional provision of $10 million was recorded in December 2003.
Based on the decisions of the PUCT, TNC's final under-recovery including
interest at December 31, 2003 was $6.2 million.

In February 2002, TNC received a final order from the PUCT in a previous
fuel reconciliation covering the period July 1997 to June 2000 and
reflected the order in its financial statements. This final order was
appealed to the Travis County District Court. In May 2003, the District
Court upheld the PUCT's final order. That order is currently on appeal
to the Third Court of Appeals.

TCC Fuel Reconciliation  - Affecting  TCC
-----------------------------------------

In December 2002, TCC filed its final fuel reconciliation with the PUCT
to reconcile fuel costs to be included in its deferred over-recovery
balance in the 2004 true-up proceeding. This reconciliation covers the
period of July 1998 through December 2001. At December 31, 2001, the
over-recovery balance for TCC was $63.5 million including interest.
During the reconciliation period, TCC incurred $1.6 billion of eligible
fuel and fuel-related expenses.

Based on the PUCT ruling in the TNC proceeding relating to similar
issues, TCC established a reserve for potential adverse rulings of $81
million during 2003. In July 2003, the ALJ requested that additional
information be provided in the TCC fuel reconciliation related to the
impact of the TNC orders, referenced above, on TCC. On February 3, 2004,
the ALJ issued a PFD recommending that the PUCT disallow $140 million in
eligible fuel costs including some new items not considered in the TNC
case, and other items considered but not disallowed in the TNC ruling.
At this time, management is unable to predict the outcome of this
proceeding. An adverse ruling from the PUCT, disallowing amounts in
excess of the established reserve could have a material impact on future
results of operations, cash flows and financial condition. Additional
information regarding the 2004 true-up proceeding for TCC can be found
in Note 6 "Customer Choice and Industry Restructuring."

SWEPCo Texas Fuel Reconciliation - Affecting SWEPCo
---------------------------------------------------

In June 2003, SWEPCo filed with the PUCT to reconcile fuel costs in SPP.
This reconciliation covers the period of January 2000 through December
2002. At December 31, 2002, SWEPCo's filing included a $2 million
deferred over-recovery balance including interest. During the
reconciliation period, SWEPCo incurred $435 million of Texas retail
eligible fuel expense. In November 2003, intervenors and the PUCT Staff
recommended fuel cost disallowances of more than $30 million. In
December 2003, SWEPCo agreed to a settlement in principle with all
parties in the fuel reconciliation. The settlement provides for a
disallowance in fuel costs of $8 million which was recorded in December
2003. In addition, the settlement provides for the deferral as a
regulatory asset of costs of a new lignite mining agreement in excess of
a specified benchmark for lignite at SWEPCo's Dolet Hills Plant. The
settlement provides for recovery of those deferred costs over a period
ending in April 2011 as cost savings are realized under the new mining
agreement. The settlement also will allow future recovery of litigation
costs associated with the termination of a previous lignite mining
agreement if future costs savings are adequate. The settlement will be
filed with the PUCT for approval.

ERCOT Price-to-Beat Fuel Factor Appeal - Affecting TCC and TNC
--------------------------------------------------------------

Several parties including the OPC and cities served by both TCC and TNC
appealed the PUCT's December 2001 orders establishing initial PTB fuel
factors for Mutual Energy CPL and Mutual Energy WTU. On June 25, 2003,
the District Court ruled in both appeals. The Court ruled in the Mutual
Energy WTU case that the PUCT lacked sufficient evidence to include
unaccounted for energy in the fuel factor, and that the PUCT improperly
shifted the burden of proof and the record lacked substantial evidence
on the effect of loss of load due to retail competition on generation
requirements. The Court upheld the initial PTB orders on all other
issues. In the Mutual Energy CPL proceeding, the Court ruled that the
PUCT improperly shifted the burden of proof and the record lacked
substantial evidence on the effect of loss of load due to retail
competition on generation requirements. The amount of unaccounted for
energy built into the PTB fuel factors was approximately $2.7 million
for Mutual Energy WTU. At this time, management is unable to estimate
the potential financial impact related to the loss of load issue. The
District Court decision was appealed to the Third Court of Appeals by
Mutual Energy CPL, Mutual Energy WTU and other parties. Management
believes, based on the advice of counsel, that the PUCT's original
decision will ultimately be upheld. If the District Court's decisions
are ultimately upheld, the PUCT could reduce the PTB fuel factors
charged to retail customers in 2002 and 2003 resulting in an adverse
effect on future results of operations and cash flows.

Unbundled Cost of Service (UCOS) Appeal - Affecting  TCC
--------------------------------------------------------

The UCOS proceeding established the regulated wires rates to be
effective when retail electric competition began. TCC placed new
transmission and distribution rates into effect as of January 1, 2002
based upon an order issued by the PUCT resulting from TCC's UCOS
proceeding. TCC requested and received approval from the FERC of
wholesale transmission rates determined in the UCOS proceeding.
Regulated delivery charges include the retail transmission and
distribution charge and, among other items, a nuclear decommissioning
fund charge, a municipal franchise fee, a system benefit fund fee, a
transition charge associated with securitization of regulatory assets
and a credit for excess earnings. Certain rulings of the PUCT in the
UCOS proceeding, including the initial determination of stranded costs,
the requirement to refund TCC's excess earnings, regulatory treatment of
nuclear insurance and distribution rates charged municipal customers,
were appealed to the Travis County District Court by TCC and other
parties to the proceeding. The District Court issued a decision on June
16, 2003, upholding the PUCT's UCOS order with one exception. The Court
ruled that the refund of the 1999 through 2001 excess earnings, solely
as a credit to non-bypassable transmission and distribution rates
charged to REPs, discriminates against residential and small commercial
customers and is unlawful. The distribution rate credit began in January
2002. This decision could potentially affect the PTB rates charged by
Mutual Energy CPL and could result in a refund to certain of its
customers. Mutual Energy CPL was a subsidiary of AEP until December 23,
2002 when it was sold. Management estimates that the effect of a
decision to reduce the PTB rates for the period prior to the sale is
approximately $11 million pre-tax. The District Court decision was
appealed to the Third Court of Appeals by TCC and other parties. Based
on advice of counsel, management believes that it will ultimately
prevail on appeal. If the District Court's decision is ultimately upheld
on appeal or the Court of Appeals reverses the District Court on issues
adverse to TCC, it could have an adverse effect on future results of
operations and cash flows.

TCC Rate Case - Affecting TCC
-----------------------------

On June 26, 2003, the City of McAllen, Texas requested that TCC provide
justification showing that its transmission and distribution rates
should not be reduced. Other municipalities served by TCC passed similar
rate review resolutions. In Texas, municipalities have original
jurisdiction over rates of electric utilities within their municipal
limits. Under Texas law, TCC must provide support for its rates to the
municipalities. TCC filed the requested support for its rates based on a
test year ending June 30, 2003 with all of its municipalities and the
PUCT on November 3, 2003. TCC's proposal would decrease its wholesale
transmission rates by $2 million or 2.5% and increase its retail energy
delivery rates by $69 million or 19.2%. On February 9, 2004, eight
intervening parties filed testimony recommending reductions to TCC's
requested $67 million rate increase. The recommendations range from a
decrease in existing rates of approximately $100 million to an increase
in TCC's current rates of approximately $27 million. The PUCT Staff
filed testimony, on February 17, 2004, recommending reductions to TCC's
request of approximately $51 million. TCC's rebuttal testimony was filed
on February 26, 2004. Hearings are scheduled for March 2004 with a PUCT
decision expected in May 2004. Management is unable to predict the
ultimate effect of this proceeding on TCC's rates or its impact on TCC's
results of operations, cash flows and financial condition.

Louisiana Fuel Audit - Affecting SWEPCO
---------------------------------------

The LPSC is performing an audit of SWEPCo's historical fuel costs. In
addition, five SWEPCo customers filed a suit in the Caddo Parish
District Court in January 2003 and filed a complaint with the LPSC. The
customers claim that SWEPCo has over charged them for fuel costs since
1975. The LPSC consolidated the customer complaint and audit. In January
2004, a procedural schedule was issued requiring LPSC Staff and
intervenor testimony to be filed in June 2004 and scheduling hearings
for October 2004. Management believes that SWEPCo's fuel costs were
proper and those costs incurred prior to 1999 have been approved by the
LPSC. Management is unable to predict the outcome of these proceedings.
If the actions of the LPSC or the Court result in a material
disallowance of recovery of SWEPCo's fuel costs from customers, it could
have an adverse impact on results of operations and cash flows.

Louisiana Compliance Filing -  Affecting SWEPCo
-----------------------------------------------

In October 2002, SWEPCo filed with the LPSC detailed financial
information typically utilized in a revenue requirement filing,
including a jurisdictional cost of service. This filing was required by
the LPSC as a result of their order approving the merger between AEP and
CSW. The LPSC's merger order also provides that SWEPCo's base rates are
capped at the present level through mid 2005. The filing indicates that
SWEPCo's current rates should not be reduced. In 2004 the LPSC required
SWEPCo to file updated financial information with a test year ending
December 31, 2003 before April 16, 2004. If, after review of the updated
information, the LPSC disagrees with our conclusion, they could order
SWEPCo to file all documents for a full cost of service revenue
requirement review in order to determine whether SWEPCo's capped rates
should be reduced which would adversely impact results of operations and
cash flows.

FERC Wholesale Fuel Complaints - Affecting TNC
----------------------------------------------

Certain TNC wholesale customers filed a complaint with FERC alleging
that TNC had overcharged them through the fuel adjustment clause for
certain purchased power costs since 1997.

Negotiations to settle the complaint and update the contracts resulted
in new contracts. The FERC approved an offer of settlement regarding the
fuel complaint and new contracts at market prices in December 2003.
Since TNC had recorded a provision for refund in 2002, the effect of the
settlement was a $4 million favorable adjustment recorded in December
2003. See Note 2 for a discussion of TNC's discontinuance of SFAS 71
accounting for its FERC jurisdictional customers.

Environmental Surcharge Filing - Affecting KPCo
-----------------------------------------------

In September 2002, KPCo filed with the KPSC to revise its environmental
surcharge tariff (annual revenue increase of approximately $21 million)
to recover the cost of emissions control equipment being installed at
the Big Sandy Plant. See NOx Reductions in Note 7.

In March 2003, the KPSC granted approximately $18 million of the
request. Annual rate relief of $1.7 million became effective in May 2003
and an additional $16.2 million became effective in July 2003. The
recovery of such amounts is intended to offset KPCo's cost of compliance
with the Clean Air Act.

PSO Rate Review - Affecting PSO
-------------------------------

In February 2003, the Director of the OCC filed an application requiring
PSO to file all documents necessary for a general rate review. In
October 2003, PSO filed financial information and supporting testimony
in response to the OCC's requirements. PSO's response indicates that its
annual revenues are $36 million less than costs. As a result, PSO is
seeking OCC approval to increase its base rates by that amount, which is
a 3.6% increase over PSO's existing revenues. Hearings are scheduled for
October 2004. Management is unable to predict the ultimate effect of
this review on PSO's rates or its impact on PSO's results of operations,
cash flows and financial condition.

PSO Fuel and Purchased Power - Affecting PSO
--------------------------------------------

PSO had a $44 million under-recovery of fuel costs resulting from a 2002
reallocation among AEP West companies of purchased power costs for
periods prior to January 1, 2002. In July 2003, PSO filed with the OCC
seeking recovery of the $44 million over an 18-month time period. In
August 2003, the OCC Staff filed testimony recommending PSO be granted
recovery of $42.4 million over three years. In September 2003, the OCC
expanded the case to include a full review of PSO's 2001 fuel and
purchased power practices. PSO filed its testimony in February 2004 and
hearings will occur in June 2004. If the OCC determines as a result of
the review that a portion of PSO's fuel and purchased power costs should
not be recovered, there will be an adverse effect on PSO's results of
operations, cash flows and possibly financial condition.

Merger Mitigation Sales - Affecting PSO, SWEPCo, TCC and TNC
------------------------------------------------------------

As a condition of AEP/CSW merger approval at the FERC, the AEP West
companies were required to mitigate market power concerns in SPP by
divesting 300 MW of SPP capacity and selling 300 MW of SPP capacity at
auction on an interim basis until the divestiture is completed. The
margins from the interim sales were to be shared with customers in
accordance with the existing margin sharing if they were positive on an
annual basis and customers were to be held harmless if the margins on an
annual basis were negative. Consequently, for proper accounting, the
margins were deferred until year-end.

On September 1, 2003, AEP sold its share of the Eastex plant located in
SPP. As a result of the sale, AEP satisfied the 300 MW FERC divestiture
requirement in SPP. Based on the advice of counsel, management has
concluded that it is no longer required to make the agreed upon 300 MW
interim merger mitigation sale. The AEP West companies had $8.7 million
of net merger mitigation sales losses deferred. Since these sales are no
longer required, the final adjustment to the accrual occurred in
September 2003. The amounts of revenues reversed were $8.6 million by
PSO, $0.7 million by TCC and $1.2 million by TNC. SWEPCo recorded its
gain of $1.8 million as revenues.

Virginia Fuel Factor Filing - Affecting APCo
--------------------------------------------

APCo filed with the Virginia SCC to reduce its fuel factor effective
August 1, 2003. The requested fuel rate reduction was approved by the
Virginia SCC and is effective for 17 months (August 1, 2003 to December
31, 2004) and is estimated to reduce revenues by $36 million during that
period. This fuel factor adjustment will reduce cash flows without
impacting results of operations as any over-recovery or under-recovery
of fuel costs would be deferred as a regulatory liability or a
regulatory asset.

FERC Long-term Contracts - Affecting AEP East and AEP West companies
--------------------------------------------------------------------

In 2002, the FERC set for hearing complaints filed by certain wholesale
customers located in Nevada and Washington that sought to break
long-term contracts which the customers alleged were "high-priced." At
issue were long-term contracts entered into during the California energy
price spike in 2000 and 2001. The complaints alleged that AEP sold power
at unjust and unreasonable prices.

In February 2003, AEP and one of the customers agreed to terminate their
contract. The customer withdrew its FERC complaint and paid $59 million
to AEP. As a result of the contract termination, AEP reversed $69
million of unrealized mark-to-market gains previously recorded,
resulting in a $10 million pre-tax loss.

In December 2002, a FERC ALJ ruled in favor of AEP and dismissed a
complaint filed by two Nevada utilities. In 2000 and 2001, we agreed to
sell power to the utilities for future delivery. In 2001, the utilities
filed complaints asserting that the prices for power supplied under
those contracts should be lowered because the market for power was
allegedly dysfunctional at the time such contracts were executed. The
ALJ rejected the utilities' complaint, held that the markets for future
delivery were not dysfunctional, and that the utilities had failed to
demonstrate that the public interest required that changes be made to
the contracts. In June 2003, the FERC issued an order affirming the
ALJ's decision. The utilities requested a rehearing which the FERC
denied. The utilities' appeal of the FERC order is pending before the
U.S. Court of Appeals for the Ninth Circuit. Management is unable to
predict the outcome of this proceeding and its impact on future results
of operations and cash flows.

RTO Formation/Integration Costs - Affecting APCo, CSPCo, I&M, KPCo, and OPCo
----------------------------------------------------------------------------

With FERC approval, AEP East companies have been deferring costs
incurred under FERC orders to form an RTO (the Alliance RTO) or join an
existing RTO (PJM). In July 2003, the FERC issued an order approving our
continued deferral of both our Alliance formation costs and our PJM
integration costs including the deferral of a carrying charge. The AEP
East companies have deferred approximately $28 million of RTO formation
and integration costs and related carrying charges through December 31,
2003. Amounts per company are as follows:

                    Company                      (in millions)
                    APCo                             $7.8
                    CSPCo                             3.3
                    I&M                               6.0
                    KPCo                              1.8
                    OPCo                              8.6

As a result of the subsequent delay in the integration of AEP's East
transmission system into PJM, FERC declined to rule, in its July 2003
order, on our request to transfer the deferrals to regulatory assets,
and to maintain the deferrals until such time as the costs can be
recovered from all users of AEP's East transmission system. The AEP East
companies will apply for permission to transfer the deferred
formation/integration costs to a regulatory asset prior to integration
with PJM. In August 2003, the Virginia SCC filed a request for rehearing
of the July 2003 order, arguing that FERC's action was an infringement
on state jurisdiction, and that FERC should not have treated Alliance
RTO startup costs in the same manner as PJM integration costs. On
October 22, 2003, FERC denied the rehearing request.

In its July 2003 order, FERC indicated that it would review the deferred
costs at the time they are transferred to a regulatory asset account and
scheduled for amortization and recovery in the open access transmission
tariff (OATT) to be charged by PJM. Management believes that the FERC
will grant permission for the deferred RTO costs to be amortized and
included in the OATT. Whether the amortized costs will be fully
recoverable depends upon the state regulatory commissions' treatment of
AEP East companies' portion of the OATT at the time they join PJM.
Presently, retail base rates are frozen or capped and cannot be
increased for retail customers of CSPCo, I&M and OPCo. APCo's Virginia
retail base rates are capped with an opportunity for a one-time increase
in non-generation rates after January 1, 2004. We intend to file an
application with FERC seeking permission to delay the amortization of
the deferred RTO formation/integration costs until they are recoverable
from all users of the transmission system including retail customers.
Management is unable to predict the timing of when AEP will join PJM and
if upon joining PJM whether FERC will grant a delay of recovery until
the rate caps and freezes end. If the AEP East companies do not obtain
regulatory approval to join PJM, we are committed to reimburse PJM for
certain project implementation costs (presently estimated at $24 million
for the entire PJM integration project). If incurred, PJM project
implementation costs will be allocated among the AEP East companies.
Management intends to seek recovery of the deferred RTO
formation/integration costs and project implementation cost
reimbursements, if incurred. If the FERC ultimately decides not to
approve a delay or the state commissions deny recovery, future results
of operations and cash flows could be adversely affected.

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

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

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

In November 2003, the FERC issued an order preliminarily finding that
AEP must fulfill its CSW merger condition to join an RTO by integrating
into PJM (transmission and markets) by October 1, 2004. The order was
based on PURPA 205(a), which allows FERC to exempt electric utilities
from state law or regulation in certain circumstances. The FERC set
several issues for public hearing before an ALJ. Those issues include
whether the laws, rules, or regulations of Virginia and Kentucky are
preventing AEP from joining an RTO and whether the exceptions under
PURPA apply. The FERC directed the ALJ to issue an initial decision by
March 15, 2004.

FERC Order on Regional Through and Out Rates - Affecting APCo, CSPCo, I&M,
KPCo and OPCo
--------------------------------------------------------------------------

In July 2003, the FERC issued an order directing PJM and the Midwest ISO
to make compliance filings for their respective Open Access Transmission
Tariffs to eliminate, by November 1, 2003, the transaction-based charges
for through and out (T&O) transmission service on transactions where the
energy is delivered within the proposed Midwest ISO and PJM expanded
regions (RTO Footprint). In October 2003, the FERC postponed the
November 1, 2003 deadline to eliminate T&O rates. The elimination of the
T&O rates will reduce the transmission service revenues collected by the
RTOs and thereby reduce the revenues received by transmission owners
under the RTOs' revenue distribution protocols. The order provided that
affected transmission owners could file to offset the elimination of
these revenues by increasing rates or utilizing a transitional rate
mechanism to recover lost revenues that result from the elimination of
the T&O rates. The FERC also found that the T&O rates of some of the
former Alliance RTO companies, including AEP, may be unjust,
unreasonable, and unduly discriminatory or preferential for energy
delivered in the RTO Footprint. FERC initiated an investigation and
hearing in regard to these rates. We made a filing with the FERC to
support the justness and reasonableness of our rates. We also made a
joint filing with unaffiliated utilities proposing a regional revenue
replacement mechanism for the lost revenues, in the event that FERC
eliminated all T&O rates for delivery points within the RTO Footprint.
In orders issued in November 2003, the FERC dismissed the joint filing,
but adopted a new regional rate design substantially in the form
proposed in the joint filing. The orders, directed each transmission
provider to file compliance rates to eliminate T&O rates prospectively
within the region and simultaneously implement a new seams elimination
cost allocation (SECA) rates to mitigate the lost revenues for a
two-year transition period beginning April 1, 2004. The FERC did not
indicate the recovery method for the revenues after the two-year period.
As required by the FERC, we filed compliance tariff changes in January
2004 to eliminate the T&O charges within the RTO Footprint. The SECA
rate issues that remain unresolved have been set before an ALJ for
settlement procedures, and the effective date of the T&O rate
elimination and SECA rates were delayed until May 1, 2004. The November
2003 orders have been appealed by a number of parties. The AEP East
companies received approximately $150 million of T&O rate revenues from
transactions delivering energy to customers in the RTO Footprint for the
twelve months ended June 30, 2003. At this time, management is unable to
predict whether the new SECA rates will fully compensate the AEP East
companies for their lost T&O rate revenues and, consequently, their
impact on our future results of operations, cash flows and financial
condition.

Indiana Fuel Order - Affecting I&M
----------------------------------

On July 17, 2003, I&M filed a fuel adjustment clause application
requesting authorization to implement the fixed fuel adjustment charge
(fixed pursuant to a prior settlement of the Cook Nuclear Plant Outage)
for electric service for the billing months of October 2003 through
February 2004, and for approval of a new fuel cost adjustment credit for
electric service to be applicable during the March 2004 billing month.

On August 27, 2003, the IURC issued an order approving the requested
fixed fuel adjustment charge for October 2003 through February 2004. The
order further stated that certain parties must negotiate the appropriate
action on fuel to commence on March 1, 2004. Such negotiations are
ongoing. The IURC deferred ruling on the March 2004 factor until after
January 1, 2004.


Michigan 2004 Fuel Recovery Plan - Affecting I&M
------------------------------------------------

The MPSC's December 16, 1999 order approved a Settlement Agreement
regarding the extended outage of the Cook Plant and fixed I&M Power
Supply Cost Recovery (PSCR) factors for the St. Joseph and Three Rivers
rate areas through December 2003. In accordance with the settlement,
PSCR Plan cases were not required to be filed through the 2003 plan
year. As required, I&M filed its 2004 PSCR Plan with the MPSC on
September 30, 2003 seeking new fuel and power supply recovery factors to
be effective in 2004. The case has been scheduled for hearing. As
allowed by Michigan law, the proposed factors were effective on January
1, 2004, subject to review and possible adjustment based on the results
of the hearing.

5.  EFFECTS OF REGULATION
-------------------------

Regulatory Assets and Liabilities
---------------------------------

Regulatory assets and liabilities are comprised of the following items:
<TABLE>
<CAPTION>
                                                           AEGCo                                       APCo

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

                                                                   Recovery/Refund                            Recovery/Refund
                                          2003            2002          Period         2003          2002        Period
                                          ----            ----     ---------------     ----          ----     ---------------
                                                                   (in thousands)
<C>                                       <C>         <C>         <C>             <C>           <C>             <C>
Regulatory Assets:
                                                                                                                Various
 SFAS 109 Regulatory Asset, Net                                                   $325,889      $209,884        Periods (a)
 Transition Regulatory Assets -                                                                                 Up to 4
  Virginia                                                                          30,855        39,670          Years (a)
 Transition Regulatory Assets -  West
Virginia                                                                                 -       119,038           N/A
 Deferred Fuel Costs                                                                     -         5,367           N/A
 Unamortized Loss on                                                                                            Up to 29
   Reacquired Debt                         $4,733      $4,970      22 Years (b)     19,005         9,147          Years (b)
                                                                      Various                                   Various
 Asset Retirement Obligations                 928           -       Periods (a)      9,048             -        Periods (a)
 Unrealized Loss on Forward                                                                                     Various
  Commitments                                                                       17,006             -        Periods (a)
                                                                                                                Various
 Other                                                                              15,393        12,447        Periods (a)
                                          --------    --------                    ---------     ---------
Total Regulatory Assets                    $5,661      $4,970                     $417,196      $395,553
                                          ========    ========                    =========     =========


Regulatory Liabilities:
 Asset Removal Costs                      $27,822          $-              (d)     $92,497            $-                (d)
                                                                   Up to 19                                      Up to 17
 Deferred Investment Tax Credits           49,589      52,943       Years  (a)      30,545        33,691          Years (c)
 WV Rate Stabilization Deferral                                                          -        75,601           N/A
 SFAS 109 Regulatory Liability,                                    Various
  Net                                      15,505      16,670      Periods (a)
 Over Recovery of Fuel Costs -
  West Virginia                                                                     55,250             -                (a)
 Unrealized Gain on Forward                                                                                    Various
   Commitments                                                                      17,283             -       Periods  (a)
 Over Recovery of Fuel Costs -
   Virginia                                                                         13,454             -       1 Year   (b)
                                                                                                               Various
 Other                                                                                  43            72       Periods  (a)
                                          --------    --------                    ---------     ---------
Total Regulatory Liabilities              $92,916     $69,613                     $209,072      $109,364
                                          ========    ========                    =========     =========
</TABLE>




 (a) Amount does not earn a return.
 (b) Amount effectively earns a return.
 (c) A portion of this amount effectively earns a return.
 (d) The liability for removal costs will be discharged as removal costs are
     incurred over the life of the plant.
<TABLE>
<CAPTION>

                                                          CSPCo                                       I&M
                                            --------------------------------------      --------------------------------------
                                                                   Recovery/Refund                              Recovery/Refund
                                            2003         2002          Period           2003          2002          Period
                                            ----         ----      ---------------      ----          ----      ---------------
                                                                             (in thousands)
Regulatory Assets:
<C>                                       <C>         <C>            <C>              <C>           <C>          <C>
                                                                     Various                                      Various
 SFAS 109 Regulatory Asset, Net            $16,027     $26,290       Periods (a)      $151,973      $163,928      Periods (a)
                                                                      Up to 5
 Transition Regulatory Assets              188,532     204,961         Years (a)

 Deferred Fuel Costs                                                                         -        37,501       N/A
 Unamortized Loss on                                                 Up to 20                                     Up to 29
   Reacquired Debt                          13,659       5,978         Years (b)        18,424        14,994        Years (b)
 Cook Plant Restart Costs                                                                    -        40,000       N/A
 Incremental Nuclear Refueling
   Outage Expenses, Net                                                                 57,326        29,572              (c)
 DOE Decontamination and                                                                                            Up to 5
   Decommissioning Assessment                                                           18,863        23,375        Years (a)

                                                                     Various                                      Various
 Other                                      24,966      20,453       Periods (a)        29,691        38,842      Periods (a)
                                          ---------   ---------                       ---------     ---------
Total Regulatory Assets                   $243,184    $257,682                        $276,277      $348,212
                                          =========   =========                       =========     =========

Regulatory Liabilities:
 Asset Removal Costs                       $99,119          $-               (e)      $263,015            $-              (e)
                                                                     Up to 17                                     Up to 19
 Deferred Investment Tax Credits            30,797      33,907         Years (a)        90,278        97,709        Years (a)
 Excess ARO for Nuclear
   Decommissioning                                                                     215,715             -              (d)
 Unrealized Gain on Forward                                                                                       Various
   Commitments                                                                          25,010        36,804      Periods (a)
                                                                                                                  Various
 Other                                                                                  36,258        29,179      Periods (a)
                                          ---------   ---------                       ---------     ---------
Total Regulatory Liabilities              $129,916     $33,907                        $630,276      $163,692
                                          =========   =========                       =========     =========
</TABLE>


 (a) Amount does not earn a return.
 (b) Amount effectively earns a return.
 (c) Amortized over the period beginning with the commencement of an
     outage and ending with the beginning of the next outage and does not earn
     a return.
 (d) This is the cumulative difference in the amount provided
     through rates and the amount as measured by applying SFAS 143. Accrues
     monthly, will be paid when the nuclear plant is decommissioned and earns
     a return.
 (e) The liability for removal costs will be discharged as removal costs
     are incurred over the life of the plant.
<TABLE>
<CAPTION>
                                                          KPCo                                        OPCo
                                            ----------------------------------------    ---------------------------------------

                                                                     Recovery/Refund                            Recovery/Refund
                                            2003         2002            Period         2003          2002           Period
                                            ----         ----            ------         ----          ----           ------
                                                                     (in thousands)
<C>                                       <C>          <C>          <C>              <C>            <C>           <C>
Regulatory Assets:
                                                                    Various                                       Various
 SFAS 109 Regulatory Asset, Net            $99,828      $87,261     Periods (a)       $169,605      $165,106      Periods (a)
 Transition Regulatory Assets                                                          310,035       375,409       4 years (a)
 Unamortized Loss on                                                Up to 29                                      Up to 34
   Reacquired Debt                           1,088          152       Years (b)         10,172         4,899        Years (b)
                                                                    Various                                       Various
 Other                                      12,883       14,563     Periods (a)         22,506        23,227      Periods (a)
                                          ---------    ---------                      ---------     ---------
Total Regulatory Assets                   $113,799     $101,976                       $512,318      $568,641
                                          =========    =========                      =========     =========

Regulatory Liabilities:
Asset Removal Costs                        $26,140           $-             (c)       $101,160            $-              (c)
                                                                    Up to 17                                      Up to 17
 Deferred Investment Tax Credits             7,955        9,165      Years  (a)         15,641        18,748        Years (a)
 Unrealized Gain on Forward                                         Various
   Commitments                               9,174       10,967     Periods (a)
                                                                    Various                                       Various
 Other                                       1,417        1,185     Periods (a)              3         1,237      Periods (a)
                                          ---------    ---------                      ---------     ---------
Total Regulatory Liabilities               $44,686      $21,317                       $116,804       $19,985
                                          =========    =========                      =========     =========
</TABLE>


 (a) Amount does not earn a return.
 (b) Amount effectively earns a return.
 (c) The liability for removal costs will be discharged as removal costs are
     incurred over the life of the plant.
<TABLE>
<CAPTION>



                                                           PSO                                        SWEPCo
                                            ----------------------------------------    ---------------------------------------
                                                                     Recovery/Refund                            Recovery/Refund
                                            2003         2002            Period         2003          2002           Period
                                            ----         ----        ---------------    ----          ----      ---------------
                                                                                 (in thousands)
Regulatory Assets:

<C>                                       <C>          <C>          <C>               <C>            <C>          <c>
                                                                                                                  Various
 SFAS 109 Regulatory Asset, Net                                                         $3,235       $19,855      Periods (b)
 Under-recovered Fuel Costs                $24,170      $76,470       1 Year (a)        11,394         2,865        1 Year (a)
 Unamortized Loss on                                                Up to 12                                      Up to 40
   Reacquired Debt                          14,357       11,138        Years (b)        19,331        17,031        Years  (b)
                                                                    Various                                       Various
 Other                                      14,342       15,012     Periods  (c)        15,859        12,347      Periods (c)
                                          ---------    ---------                      ---------      --------
Total Regulatory Assets                    $52,869     $102,620                        $49,819       $52,098
                                          =========    =========                      =========      ========

Regulatory Liabilities:
 Asset Removal Costs                      $214,033           $-              (e)      $236,409            $-              (e)
                                                                    Up to 26                                      Up to 14
 Deferred Investment Tax Credits            30,411       32,201        Years (d)        39,864        44,190        Years (d)
 SFAS 109 Regulatory                                                Various
  Liability, Net                            24,937       27,893     Periods  (b)
 Over-Recovered Fuel Costs                                                               4,178        17,226      1 Year  (a)
 Excess Earnings                                                                         2,600         3,700              (d)
 Unrealized Gains on Forward                                         Various                                      Various
  Commitments                               15,406        4,360      Periods (c)        11,793         1,992      Periods (c)
                                                                     Various                                      Various
 Other                                                       31      Periods (c)         6,986         1,402      Periods (c)
                                          ---------    ---------                      ---------      --------
Total Regulatory Liabilities              $284,787      $64,485                       $301,830       $68,510
                                          =========    =========                      =========      ========
</TABLE>


 (a) Deferred fuel for PSO's Oklahoma jurisdiction & SWEPCo's Arkansas
     and Louisiana jurisdictions does not earn a return. Texas
     jurisdictional amounts do earn a return.
 (b) Amount effectively earns a return.
 (c) Amounts are both earning and not earning a return.
 (d) Amount does not earn a return.
 (e) The liability for removal costs will be discharged as removal
     costs are incurred over the life of the plant.
<TABLE>
<CAPTION>

                                                   TCC                                        TNC
                                    ----------------------------------------    ---------------------------------------

                                                             Recovery/Refund                            Recovery/Refund
                                    2003         2002            Period         2003          2002           Period
                                    ----         ----        ---------------    ----          ----      ---------------
                                                                       (in thousands)
<S>                              <C>          <C>          <C>                <C>           <C>                <C>
Regulatory Assets:
                                                           Various
 SFAS 109 Regulatory Asset, Net     $3,249      $9,950     Periods  (a)
 Designated For Securitization   1,253,289     330,960              (b)
 Deferred Fuel Costs                                                           $26,680      $26,680                     (c)
 Wholesale Capacity Auction
  True-up                          480,000     262,000              (c)
 Unamortized Loss on                                       Up to 34                                            Up to 17
   Reacquired Debt                   9,086       8,661        Years (a)          3,929        3,283               Years (a)
                                                           Up to 14                                            Up to 14
 Deferred Debt - Restructuring      12,015      13,324        Years (a)          6,579       10,134               Years (a)
 DOE Decontamination and
  Decommissioning Assessment         3,268       3,170       1 Year (d)
                                                           Various                                             Various
 Other                             130,645     166,931     Periods (e)          3,332        5,000             Periods (e)
                                -----------   ---------                       ---------     --------
Total Regulatory Assets         $1,891,552    $794,996                         $40,520      $45,097
                                ===========   =========                       =========     ========

Regulatory Liabilities:
 Asset Removal Costs               $95,415          $-              (f)        $76,740           $-                     (f)
                                                           Up to 25                                            Up to 19
 Deferred Investment Tax Credits   112,479     117,686       Years  (d)         19,990       21,510               Years (d)
 Deferred Fuel Costs                69,026      69,026              (c)
 Retail Clawback                    45,527      51,926              (c)         11,804       14,328                     (c)
 Over - Recovery of Transition                             Up to 13
   Charges                          22,499      20,870     Years    (a)
                                                           Various
 Purchased Power Conservation        9,234       9,560     Periods  (e)
                                                                                                               Up to 30
 Excess Earnings                    25,246      46,111              (b)         14,262       17,419               Years (a)
 SFAS 109 Regulatory                                                                                           Various
   Liability, Net                                                               13,655       12,280            Periods (a)
                                                            Various                                            Various
 Other                                   5           6      Periods (e)          1,826        7,285            Periods (e)
                                -----------   ---------                       ---------     --------
 Total Regulatory Liabilities     $379,431    $315,185                        $138,277      $72,822
                                ===========   =========                       =========     ========
</TABLE>


 (a) Amount earns a return.
 (b) Will be included in TCC's PUCT 2004 true-up proceedings and is
     designated for possible securitization during 2005.
 (c) Amount will be included in TCC's and TNC's 2004 true-up proceedings for
     future recovery/payment over a time period to be determined in a future
     PUCT proceeding.
 (d) Amount does not earn a return.
 (e) Amounts are both earning and not earning a return.
 (f) The liability for removal costs will be discharged as removal costs are
     incurred over the life of the plant.

Texas Restructuring Related Regulatory Assets and Liabilities
-------------------------------------------------------------

Regulatory assets Designated for Securitization, Wholesale Capacity
Auction True-up regulatory assets, Deferred Fuel Costs and Retail
Clawback regulatory liabilities are not being currently recovered from
or returned to ratepayers. Management believes that the laws and
regulations, established in Texas for industry restructuring, provide
for the recovery from ratepayers of these net amounts. See Note 6 for a
complete discussion of our plans to recover these regulatory assets, net
of regulatory liabilities.

Nuclear Plant Restart
---------------------

I&M completed the restart of both units of the Cook Plant in 2000.
Settlement agreements in the Indiana and Michigan retail jurisdictions
that addressed recovery of Cook Plant related outage costs were approved
in 1999 by the IURC and MPSC.

The amount of deferrals amortized to other O&M expenses were $40 million
in 2003, 2002 and 2001. Also pursuant to the settlement agreements,
accrued fuel-related revenues of approximately $37 million in 2003 and
$38 million in 2002 and 2001 were amortized as a reduction of revenues.

The amortization of O&M costs and fuel-related revenues deferred under
Indiana and Michigan retail jurisdictional settlement agreements
adversely affected results of operations through December 31, 2003 when
the amortization period ended.

Merger with CSW
---------------

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. In connection with the merger, non-recoverable merger
costs were expensed in 2003, 2002 and 2001. Such costs included
transaction and transition costs not recoverable from ratepayers. Also
included in the merger costs were non-recoverable change in control
payments. Merger transaction and transition costs recoverable from
ratepayers were deferred pursuant to state regulator approved settlement
agreements through December 31, 2003. The deferred merger costs are
being amortized over five to eight year recovery periods, depending on
the specific terms of the settlement agreements, with the amortization
included in depreciation and amortization expense.

The following tables show the deferred merger cost and amortization
expense of the applicable subsidiary registrants:
<TABLE>
<CAPTION>

                                                       Amortization Expense for
                           Merger Cost Deferral             the Year Ended
                            December 31, 2003              December 31, 2003
                            -----------------              -----------------
                                             (in millions)
     <C>                           <C>                              <C>
     I&M                           $6.7                             $1.7
     KPCo                           2.4                              0.6
     PSO                            3.2                              1.9
     SWEPCo                         2.7                              1.2
     TCC                            6.5                              2.6
     TNC                            1.9                              0.8


                                                       Amortization Expense for
                           Merger Cost Deferral             the Year Ended
                            December 31, 2002              December 31, 2002
                            -----------------              -----------------
                                             (in millions)
     I&M                           $8.2                             $1.7
     KPCo                           2.9                              0.6
     PSO                            5.0                              1.6
     SWEPCo                         3.9                              1.1
     TCC                            9.1                              2.6
     TNC                            2.7                              0.8



                                                       Amortization Expense for
                           Merger Cost Deferral             the Year Ended
                            December 31, 2001              December 31, 2001
                            -----------------              -----------------
                                             (in millions)
     I&M                           $9.1                             $1.7
     KPCo                           3.2                              0.6
     PSO                            6.6                              1.2
     SWEPCo                         5.0                              1.1
     TCC                           11.8                              2.6
     TNC                            3.5                              0.8

</TABLE>

Merger transition costs are expected to continue to be incurred for
several years after the merger and will be expensed or deferred for
amortization as appropriate. As hereinafter summarized, the state
settlement agreements provide for, among other things, a sharing of net
merger savings with certain regulated customers over periods of up to
eight years through rate reductions which began in the third quarter of
2000.

Summary of key provisions of Merger Rate Agreements:

 State/Company                 Ratemaking Provisions
 -------------                 ---------------------
 Texas - SWEPCo, TCC, TNC      $221 million rate
                               reduction over 6 years. No base rate
                               increases for 3 years post merger.

 Indiana - I&M                 $67 million rate reduction over 8
                               years. Extension of base rate freeze
                               until January 1, 2005. Requires
                               additional annual deposits of $6 million
                               to the nuclear decommissioning trust fund
                               for the years 2001 through 2003.

 Michigan - I&M                Customer billing credits of
                               approximately $14 million over 8 years.
                               Extension of base rate freeze until
                               January 1, 2005.

 Kentucky - KPCo               Rate  reductions of  approximately  $28 million
                               over 8 years. No base rate increases for 3 years
                               post merger.

 Oklahoma - PSO                Rate  reductions of  approximately  $28 million
                               over 5 years. No base rate increase before
                               January 1, 2003.

 Arkansas - SWEPCo             Rate  reductions  of $6  million  over 5 years.
                               No base rate increase before June 15, 2003.

 Louisiana - SWEPCo            Rate reductions to share merger savings
                               estimated to be $18 million over 8 years. Base
                               rate cap until June 2005.

If actual merger savings are significantly less than the merger savings
rate reductions required by the merger settlement agreements in the
eight-year period following consummation of the merger, future results
of operations, cash flows and possibly financial condition could be
adversely affected.

See Note 7, "Commitments and Contingencies" for information on a court
decision concerning the merger.


6.  CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING
----------------------------------------------


Prior to 2003, retail customer choice began in four of the eleven state
retail jurisdictions (Michigan, Ohio, Texas and Virginia) in which the
AEP domestic electric utility companies operate. The following
paragraphs discuss significant events occurring related to customer
choice and industry restructuring.

OHIO RESTRUCTURING - Affecting CSPCo and OPCo
---------------------------------------------

On June 27, 2002, the Ohio Consumers' Counsel, Industrial Energy
Users-Ohio and American Municipal Power-Ohio filed a complaint with the
PUCO alleging that CSPCo and OPCo have violated the PUCO's orders
regarding implementation of their transition plan and violated the
applicable law by failing to participate in an RTO.

The complainants seek, among other relief, an order from the PUCO:
o  suspending  collection of transition charges by CSPCo and OPCo until
   transfer of control of their transmission assets has occurred
o  requiring the pricing of standard offer electric generation
   effective January 1, 2006 at the market price used by CSPCo and
   OPCo in their 1999 transition plan filings to estimate
   transition costs and
o  imposing a $25,000 per company forfeiture for each day AEP
   fails to comply with its commitment to transfer control of
   transmission assets to an RTO

Due to FERC, state legislative and regulatory developments, CSPCo and
OPCo have been delayed in the implementation of their RTO participation
plans. We continue to pursue integration of CSPCo, OPCo and other AEP
East companies into PJM. In this regard, on December 19, 2002, CSPCo and
OPCo filed an application with the PUCO for approval of the transfer of
functional control over certain of their transmission facilities to PJM.
In February 2003, the PUCO consolidated the June 2002 complaint with our
December application. CSPCo's and OPCo's motion to dismiss the complaint
has been denied by the PUCO and the PUCO affirmed that ruling in
rehearing. All further action in the consolidated case has been stayed
"until more clarity is achieved regarding matters pending at the FERC
and elsewhere." Management is currently unable to predict the timing of
the AEP East companies' (including CSPCo and OPCo) participation in PJM,
the outcome of these proceedings before the PUCO or their impact on
results of operations and cash flows.

In October 2002, the PUCO initiated an investigation of the financial
condition of Ohio's regulated public utilities. The PUCO's goal is to
identify measures available to the PUCO to ensure that the regulated
operations of Ohio's public utilities are not impacted by adverse
financial consequences of parent or affiliate company unregulated
operations and take appropriate corrective action, if necessary. The
utilities and other interested parties were requested to provide
comments and suggestions by November 12, 2002, with reply comments by
November 22, 2002, on the type of information necessary to accomplish
the stated goals, the means to gather the required information from the
public utilities and potential courses of action that the PUCO could
take. In January 2004, the PUCO staff issued a report recommending that
the PUCO seek more authority from the Ohio Legislature on this issue.
The PUCO has taken no further action in this proceeding. Management is
unable to predict the outcome of the PUCO's investigation or its impact
on results of operations, cash flows and business practices, if any.

On March 20, 2003, the PUCO commenced a statutorily required
investigation concerning the desirability, feasibility and timing of
declaring retail ancillary, metering or billing and collection service,
supplied to customers within the certified territories of electric
utilities, a competitive retail electric service. The PUCO sent out a
list of questions and set June 6, 2003 and July 7, 2003 as the dates for
initial responses and replies, respectively. CSPCo and OPCo filed
comments and responses in compliance with the PUCO's schedule.
Management is unable to predict the timing or the outcome of this
proceeding or its impact on results of operations or cash flows.

The Ohio Act provides for a Market Development Period (MDP) during which
retail customers can choose their electric power suppliers or receive
Default Service at frozen generation rates from the incumbent utility.
The MDP began on January 1, 2001 and is scheduled to terminate no later
than December 31, 2005. The PUCO may terminate the MDP for one or more
customer classes before that date if it determines either that effective
competition exists in the incumbent utility's certified territory or
that there is a twenty percent switching rate of the incumbent utility's
load by customer class. Following the MDP, retail customers will receive
distribution and transmission service from the incumbent utility whose
distribution rates will be approved by the PUCO and whose transmission
rates will be approved by the FERC. Retail customers will continue to
have the right to choose their electric power suppliers or receive
Default Service, which must be offered by the incumbent utility at
market rates. On December 17, 2003, the PUCO adopted a set of rules
concerning the method by which it will determine market rates for
Default Service following the MDP. The rule provides for a Market Based
Standard Service Offer which would be a variable rate based on a
transparent forward market, daily market, and/or hourly market prices.
The rule also requires a fixed-rate Competitive Bidding Process for
residential and small nonresidential customers and permits a fixed-rate
Competitive Bidding Process for large general service customers and
other customer classes. Customers who do not switch to a competitive
generation provider can choose between the Market Based Standard Service
Offer or the Competitive Bidding Process. Customers who make no choice
will be served pursuant to the Competitive Bidding Process.

On February 9, 2004, CSPCo and OPCo filed their rate stabilization plan
with the PUCO addressing rates following the end of the MDP, which ends
December 31, 2005. If approved by the PUCO, rates would be established
pursuant to the plan for the period from January 1, 2006 through
December 31, 2008 instead of the rates discussed in the previous
paragraph. The plan is intended to provide rate stability and certainty
for customers, facilitate the development of a competitive retail market
in Ohio, provide recovery of environmental and other costs during the
plan period and improve the environmental performance of AEP's
generation resources that serve Ohio customers. The plan includes
annual, fixed increases in the generation component of all customers'
bills (3% annually for CSPCo and 7% annually for OPCo), and the
opportunity for additional generation-related increases upon PUCO review
and approval. For residential customers, however, if the temporary 5%
generation rate discount provided by the Ohio Act were eliminated on
June 30, 2004, the fixed increases would be 1.6% for CSPCo and 5.7% for
OPCo. The generation-related increases under the plan would be subject
to caps. The plan would maintain distribution rates through the end of
2008 for CSPCo and OPCo at the level effective on December 31, 2005.
Such rates could be adjusted for specified reasons through a PUCO
filing. Transmission charges can be adjusted to reflect applicable
charges approved by the FERC related to open access transmission, net
congestion, and ancillary services. The plan also provides for continued
recovery of transition regulatory assets and deferral of regulatory
assets in 2004 and 2005 for RTO costs and carrying costs on required
environmental expenditures. A procedural schedule has not been
established for this filing. Management cannot predict whether the plan
will be approved as submitted, modified by the PUCO, or its impacts on
results of operation and cash flows.

As provided in stipulation agreements approved by the PUCO in 2000,
CSPCo and OPCo are deferring customer choice implementation costs and
related carrying costs that are in excess of $20 million per company.
The agreements provide for the deferral of these costs as a regulatory
asset until the company's next distribution base rate case. The February
2004 filing provides for the continued deferrals of customer choice
implementation costs during the rate stabilization plan period. At
December 31, 2003, CSPCo has incurred $32 million and deferred $12
million and OPCo has incurred $34 million and deferred $14 million of
such costs. Recovery of these regulatory assets will be subject to PUCO
review in each company's future Ohio filings for new distribution rates.
If the rate stabilization plan is approved, it would defer recovery of
these amounts until after the end of the rate stabilization period.
Management believes that the customer choice implementation costs were
prudently incurred and the deferred amounts should be recoverable in
future rates. If the PUCO determines that any of the deferred costs are
unrecoverable, it would have an adverse impact on future results of
operations and cash flows.

TEXAS RESTRUCTURING - Affecting SWEPCo, TCC and TNC
---------------------------------------------------

Texas Legislation enacted in 1999 provided the framework and timetable
to allow retail electricity competition for all customers. On January 1,
2002, customer choice of electricity supplier began in the ERCOT area of
Texas. Customer choice has been delayed in the SPP area of Texas until
at least January 1, 2007.

The Texas Legislation, among other things:
o  provides for the recovery of regulatory assets and other stranded costs
   through securitization and non-bypassable wires charges;
o  requires each utility to structurally unbundle into a retail electric
   provider, a power generation company and a transmission and distribution
   (T&D) utility;
o  provides for an earnings test for each of the years 1999 through 2001 and;
o  provides for a 2004 true-up proceeding. See 2004 true-up proceeding
   discussion below.

The Texas Legislation required vertically integrated utilities to
legally separate their generation and retail-related assets from their
transmission and distribution-related assets. Prior to 2002, TCC and TNC
functionally separated their operations to comply with the Texas
Legislation requirements. AEP formed new subsidiaries to act as
affiliated REPs for TCC and TNC effective January 1, 2002 (the start
date of retail competition). In December 2002, AEP sold the affiliated
REPs to an unaffiliated company.

In 1999, TCC filed with the PUCT to securitize $1.27 billion of its
retail generation-related regulatory assets and $47 million in other
qualified restructuring costs. The PUCT authorized the issuance of up to
$797 million of securitization bonds ($949 million of generation-related
regulatory assets and $33 million of qualified refinancing costs offset
by $185 million of customer benefits for accumulated deferred income
taxes). TCC issued its securitization bonds in February 2002. The amount
not approved for securitization will be included in regulatory
assets/stranded costs in TCC's 2004 true-up proceeding.

TEXAS 2004 TRUE-UP PROCEEDING
-----------------------------

A 2004 true-up proceeding will determine the amount and recovery of:
o  net stranded generating plant costs and generation-related regulatory assets
   (stranded costs),
o  a true-up of actual market prices determined through legislatively-mandated
   capacity auctions to the power costs used in the PUCT's ECOM model for 2002
   and 2003 (wholesale capacity auction true-up),
o  final approved deferred fuel balance,
o  unrefunded accumulated excess earnings,
o  excess of price-to-beat revenues over market prices subject to certain
   conditions and limitations (retail clawback) and
o  other restructuring true-up items

The PUCT adopted a rule in 2003 regarding the timing of the 2004 true-up
proceedings scheduling TNC's filing in May 2004 and TCC's filing in
September 2004 or 60 days after the completion of the sale of TCC's
generation assets, if later.

Stranded Costs and Generation-Related Regulatory Assets
-------------------------------------------------------

Restructuring legislation required utilities with stranded costs to use
market-based methods to value certain generating assets for determining
stranded costs. TCC is the only AEP subsidiary that has stranded costs
under the Texas Legislation. We have elected to use the sale of assets
method to determine the market value of all of our generation assets for
stranded cost purposes. When completed, the sale of our generation
assets will substantially complete the required separation of generation
assets from transmission and distribution assets. For purposes of the
2004 true-up proceeding, the amount of stranded costs under this market
valuation methodology will be the amount by which the book value of
TCC's generating assets, including regulatory assets and liabilities
that were not securitized, exceeds the market value of the generation
assets as measured by the net proceeds from the sale of the assets. It
is anticipated that any such sale will result in significant stranded
costs for purposes of TCC's 2004 true-up proceeding.

In December 2002, TCC filed a plan of divestiture with the PUCT seeking
approval of a sales process for all of its generating facilities. In
March 2003, the PUCT dismissed TCC's divestiture filing, determining
that it was more appropriate to address allowable valuation methods for
the nuclear asset in a rulemaking proceeding. The PUCT approved a rule,
in May 2003, which allows the market value obtained by selling nuclear
assets to be used in determining stranded costs. Although the PUCT
declined to review TCC's proposed sale of assets process, the PUCT has
hired a consultant to advise TCC during the sale of the generation
assets. TCC's sale of its generating assets will be subject to a review
in the 2004 true-up proceeding.

In June 2003, we began actively seeking buyers for 4,497 megawatts of
TCC's generating capacity in Texas. In order to sell these assets, TCC
anticipates retiring first mortgage bonds by making open market
purchases or defeasing the bonds. Bids were received for all of TCC's
generating plants. In January 2004, TCC agreed to sell its 7.8%
ownership interest in the Oklaunion Power Station to an unaffiliated
third party for $43 million. The sale of TCC's remaining generation is
pending. Additional regulatory approvals will be required to complete
the sale of the generation assets including NRC approval of the transfer
of our interest in STP.

In the 2004 true-up proceeding, the amount of stranded costs under this
market valuation methodology will be the amount by which the book value
of TCC's generating assets, including regulatory assets and liabilities
that were not securitized and reduced by mitigation including unrefunded
excess earnings, exceeds the market value of the generation assets as
measured by the net proceeds from the sale of the assets. It is
anticipated that any such sale will result in significant stranded costs
for purposes of TCC's 2004 true-up proceeding.

After the 2004 true-up proceeding, TCC may seek to issue securitization
revenue bonds for its stranded costs and recover the costs of the
securitization bonds through transmission and distribution rates. Based
upon the Oklaunion sale and the bid information for the remaining
generation, we recorded an impairment of generating assets of $938
million in December 2003 as a regulatory asset (see Note 10). The
recovery of the regulatory asset will be subject to review and approval
by the PUCT as a stranded cost in the 2004 true-up proceeding.

Wholesale Capacity Auction True-up
----------------------------------

Texas Legislation also requires that electric utilities and their
affiliated power generation companies (PGC) offer for sale at auction,
in 2002 and 2003 and after, at least 15% of the PGC's Texas
jurisdictional installed generation capacity in order to promote
competitiveness in the wholesale market through increased availability
of generation. Actual market power prices received in the state mandated
auctions will be used to calculate the wholesale capacity auction
true-up adjustment for TCC for the 2004 true-up proceeding.

TCC recorded a $480 million regulatory asset and related revenues which
represent the quantifiable amount of the wholesale capacity auction
true-up for the years 2002 and 2003. In TCC's UCOS proceeding, the PUCT
estimated that TCC had negative stranded costs. In its true-up rule, the
PUCT determined that the wholesale capacity auction true-up proceeds
should be offset against negative stranded costs. However, in March
2003, the Texas Court of Appeals ruled that under the restructuring
legislation, other 2004 true-up items, including the wholesale capacity
auction true-up regulatory asset, could be recovered regardless of the
level of stranded costs.

In the fourth quarter of 2003, the PUCT approved a true-up filing
package containing calculation instructions similar to the methodology
employed by TCC to calculate the amount recorded for recovery under its
wholesale capacity auction true-up. The PUCT will review the $480
million wholesale capacity regulatory asset for recovery as part of the
2004 true-up proceeding.

Fuel Balance Recoveries
-----------------------

In 2002, TNC filed with the PUCT seeking to reconcile fuel costs and to
establish its deferred unrecovered fuel balance applicable to retail
sales within its ERCOT service area for inclusion in the 2004 true-up
proceeding. In January 2004, the PUCT announced a final ruling in TNC's
fuel reconciliation case that established TNC's unrecovered fuel
balance, including interest for the ERCOT service territory, at $6.2
million. This balance will be included in TNC's 2004 true-up proceeding.
TNC is waiting for a written order from the PUCT, after which it will
request a rehearing.

In 2002, TCC filed with the PUCT to reconcile fuel costs and to
establish its deferred over-recovery of fuel balance for inclusion in
the 2004 true-up proceeding. In February 2004, an ALJ issued
recommendations finding a $205 million over recovery in this fuel
proceeding. Management is unable to predict the amount of TCC's fuel
over-recovery which will be included in its 2004 true-up proceeding.

See TCC Fuel Reconciliation and TNC Fuel Reconciliation in Note 4 "Rate
Matters" for further discussion.

Unrefunded Excess Earnings
--------------------------

The Texas Legislation provides for the calculation of excess earnings
for each year from 1999 through 2001. The total excess earnings
determined for the three year period were $3 million for SWEPCo, $47
million for TCC and $19 million for TNC. TCC, TNC and SWEPCo challenged
the PUCT's treatment of fuel-related deferred income taxes and appealed
the PUCT's final 2000 excess earnings to the Travis County District
Court which upheld the PUCT ruling. The District Court's ruling was
appealed to the Third Court of Appeals. In August 2003, the Third Court
of Appeals reversed the PUCT order and the District Court judgment. The
PUCT's request for rehearing of the Appeals Court's decision was denied
and the PUCT chose not to appeal the ruling any further. Appeal of the
same issue from the PUCT's 2001 order is pending before the District
Court. Since an expense and regulatory liability had been accrued in
prior years in compliance with the PUCT orders, the companies reversed a
portion of their regulatory liability for the years 2000 and 2001
consistent with the Appeals Court's decision and credited amortization
expense during the third quarter of 2003. Pre-tax amounts reversed by
company were $5 million for TCC, $3 million for TNC and $1 million for
SWEPCo.

In 2001, the PUCT issued an order requiring TCC to return estimated
excess earnings by reducing distribution rates by approximately $55
million plus accrued interest over a five-year period beginning January
1, 2002. Since excess earnings amounts were expensed in 1999, 2000 and
2001, the order has no additional effect on reported net income but will
reduce cash flows for the five-year refund period. The amount to be
refunded is recorded as a regulatory liability. Management believes that
TCC will have stranded costs and that it was inappropriate for the PUCT
to order a refund prior to TCC's 2004 true-up proceeding. TCC appealed
the PUCT's refund of excess earnings to the Travis County District
Court. That court affirmed the PUCT's decision and further ordered that
the refunds be provided to customers. TCC has appealed the decision to
the Court of Appeals.

Retail Clawback
---------------

The Texas Legislation provides for the affiliated PTB REP serving
residential and small commercial customers to refund to its T&D utility
the excess of the PTB revenues over market prices (subject to certain
conditions and a limitation of $150 per customer). This is the retail
clawback. If, prior to January 1, 2004, 40% of the load for the
residential or small commercial classes is served by competitive REPs,
the retail clawback is not applicable for that class of customer. During
2003, TCC and TNC filed to notify the PUCT that competitive REPs serve
over 40% of the load in the small commercial class. The PUCT approved
TCC's and TNC's filings in December 2003. In 2002, AEP had accrued a
regulatory liability of approximately $9 million for the small
commercial retail clawback on its REP's books. When the PUCT certified
that the REP's in TCC and TNC service territories had reached the 40%
threshold, the regulatory liability was no longer required for the small
commercial class and was reversed in December 2003. At December 31,
2003, the remaining retail clawback liability was $45.5 million for TCC
and $11.8 million for TNC.

When the 2004 true-up proceeding is completed, TCC intends to file to
recover PUCT-approved stranded costs and other true-up amounts that are
in excess of current securitized amounts, plus appropriate carrying
charges and other true-up amounts, through non-bypassable competition
transition charge in the regulated T&D rates. TCC may also seek to
securitize certain of the approved stranded plant costs and regulatory
assets that were not previously recovered through the non-bypassable
transition charge. The annual costs of securitization are recovered
through a non-bypassable rate surcharge collected by the T&D utility
over the term of the securitization bonds.

In the event we are unable, after the 2004 true-up proceeding, to
recover all or a portion of our stranded plant costs, generation-related
regulatory assets, unrecovered fuel balances, wholesale capacity auction
true-up regulatory assets, other restructuring true-up items and costs,
it could have a material adverse effect on results of operations, cash
flows and possibly financial condition.

MICHIGAN RESTRUCTURING - Affecting I&M
--------------------------------------

Customer choice commenced for I&M's Michigan customers on January 1,
2002. Effective with that date the rates on I&M's Michigan customers'
bills for retail electric service were unbundled to allow customers the
opportunity to evaluate the cost of generation service for comparison
with other offers. I&M's total rates in Michigan remain unchanged and
reflect cost of service. At December 31, 2003, none of I&M's customers
have elected to change suppliers and no alternative electric suppliers
are registered to compete in I&M's Michigan service territory.

Management has concluded that as of December 31, 2003 the requirements
to apply SFAS 71 continue to be met since I&M's rates for generation in
Michigan continue to be cost-based regulated.

ARKANSAS RESTRUCTURING - Affecting SWEPCo
-----------------------------------------

In February 2003, Arkansas repealed customer choice legislation
originally enacted in 1999. Consequently, SWEPCo's Arkansas operations
reapplied SFAS 71 regulatory accounting, which had been discontinued in
1999. The reapplication of SFAS 71 had an insignificant effect on
results of operations and financial condition. As a result of reapplying
SFAS 71, derivative contract gains/losses for transactions within AEP's
traditional marketing area allocated to Arkansas will not affect income
until settled. That is, such positions will be recorded on the balance
sheet as either a regulatory asset or liability until realized.

WEST VIRGINIA RESTRUCTURING - Affecting APCo
--------------------------------------------

APCo reapplied SFAS 71 for its West Virginia (WV) jurisdiction in the
first quarter of 2003 after new developments during the quarter prompted
an analysis of the probability of restructuring becoming effective.

In 2000, the WVPSC issued an order approving an electricity
restructuring plan, which the WV Legislature approved by joint
resolution. The joint resolution provided that the WVPSC could not
implement the plan until the WV legislature made tax law changes
necessary to preserve the revenues of state and local governments.

In the 2001 and 2002 legislative sessions, the WV Legislature failed to
enact the required legislation that would allow the WVPSC to implement
the restructuring plan. Due to this lack of legislative activity, the
WVPSC closed two proceedings related to electricity restructuring during
the summer of 2002.

In the 2003 legislative session, the WV Legislature failed to enact the
required tax legislation. Also, legislation enacted in March 2003
clarified the jurisdiction of the WVPSC over electric generation
facilities in WV. In March 2003, APCo's outside counsel advised us that
restructuring in WV was no longer probable and confirmed facts relating
to the WVPSC's jurisdiction and rate authority over APCo's WV
generation. APCo has concluded that deregulation of the WV generation
business is no longer probable and operations in WV meet the
requirements to reapply SFAS 71.

Reapplying SFAS 71 in WV had an insignificant effect on results of
operations and financial condition. As a result, derivative contract
gains/losses related to transactions within AEP's traditional marketing
area allocated to WV will not affect income until settled. That is, such
positions will be recorded on the balance sheet as either a regulatory
asset or liability until realized. Positions outside AEP's traditional
marketing area will continue to be marked-to-market.


7.  COMMITMENTS AND CONTINGENCIES
---------------------------------


ENVIRONMENTAL
-------------

Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M, and OPCo
----------------------------------------------------------------------

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

Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might
be triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997). In
2001, the District Court ruled claims for civil penalties based on
activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.

On August 7, 2003, the District Court issued a decision following a
liability trial in a case pending in the Southern District of Ohio
against Ohio Edison Company, an unaffiliated utility. The District Court
held that replacements of major boiler and turbine components that are
infrequently performed at a single unit, that are performed with the
assistance of outside contractors, that are accounted for as capital
expenditures, and that require the unit to be taken out of service for a
number of months are not "routine" maintenance, repair, and replacement.
The District Court also held that a comparison of past actual emissions
to projected future emissions must be performed prior to any non-routine
physical change in order to evaluate whether an emissions increase will
occur, and that increased hours of operation that are the result of
eliminating forced outages due to the repairs must be included in that
calculation. Based on these holdings, the District Court ruled that all
of the challenged activities in that case were not routine, and that the
changes resulted in significant net increases in emissions for certain
pollutants. A remedy trial is scheduled for July 2004.

Management believes that the Ohio Edison decision fails to properly
evaluate and apply the applicable legal standards. The facts in the AEP
case also vary widely from plant to plant. Further, the Ohio Edison
decision is limited to liability issues, and provides no insight as to
the remedies that might ultimately be ordered by the Court.

On August 26, 2003, the District Court for the Middle District of South
Carolina issued a decision on cross-motions for summary judgment prior
to a liability trial in a case pending against Duke Energy Corporation,
an unaffiliated utility. The District Court denied all the pending
motions, but set forth the legal standards that will be applied at the
trial in that case. The District Court determined that Federal EPA bears
the burden of proof on the issue of whether a practice is "routine
maintenance, repair, or replacement" and on whether or not a
"significant net emissions increase" results from a physical change or
change in the method of operation at a utility unit. However, the
Federal EPA must consider whether a practice is "routine within the
relevant source category" in determining if it is "routine." Further,
the Federal EPA must calculate emissions by determining first whether a
change in the maximum achievable hourly emission rate occurred as a
result of the change, and then must calculate any change in annual
emissions holding hours of operation constant before and after the
change. The Federal EPA has requested reconsideration of this decision,
or in the alternative, certification of an interlocutory appeal to the
Fourth Circuit Court of Appeals.

On June 24, 2003, the United States Court of Appeals for the 11th
Circuit issued an order invalidating the administrative compliance order
issued by the Federal EPA to the Tennessee Valley Authority for similar
alleged violations. The 11th Circuit determined that the administrative
compliance order was not a final agency action, and that the enforcement
provisions authorizing the issuance and enforcement of such orders under
the Clean Air Act are unconstitutional.

On June 26, 2003, the United States Court of Appeals for the District of
Columbia Circuit granted a petition by the Utility Air Regulatory Group
(UARG), of which the AEP subsidiaries are members, to reopen petitions
for review of the 1980 and 1992 Clean Air Act rulemakings that are the
basis for the Federal EPA claims in the AEP case and other related
cases. On August 4, 2003, UARG filed a motion to separate and expedite
review of their challenges to the 1980 and 1992 rulemakings from other
unrelated claims in the consolidated appeal. The Circuit Court denied
that motion on September 30, 2003. The central issue in these petitions
concerns the lawfulness of the emissions increase test, as currently
interpreted and applied by the Federal EPA in its utility enforcement
actions. A decision by the D. C. Circuit Court could significantly
impact further proceedings in the AEP case.

On August 27, 2003, the Administrator of the Federal EPA signed a final
rule that defines "routine maintenance repair and replacement" to
include "functionally equivalent equipment replacement." Under the new
final rule, replacement of a component within an integrated industrial
operation (defined as a "process unit") with a new component that is
identical or functionally equivalent will be deemed to be a "routine
replacement" if the replacement does not change any of the fundamental
design parameters of the process unit, does not result in emissions in
excess of any authorized limit, and does not cost more than twenty
percent of the replacement cost of the process unit. The new rule is
intended to have prospective effect, and will become effective in
certain states 60 days after October 27, 2003, the date of its
publication in the Federal Register, and in other states upon completion
of state processes to incorporate the new rule into state law. On
October 27, 2003 twelve states, the District of Columbia and several
cities filed an action in the United States Court of Appeals for the
District of Columbia Circuit seeking judicial review of the new rule.
The UARG has intervened in this case. On December 24, 2003, the Circuit
Court granted a motion from the petitioners to stay the effective date
of this rule, which had been December 26, 2003.

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

In December 2000, Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement
with the Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are
continuing between the parties in an attempt to reach final settlement
terms. Cinergy's settlement could impact the operation of Zimmer Plant
and W.C. Beckjord Generating Station Unit 6 (owned 25.4% and 12.5%,
respectively, by CSPCo). Until a final settlement is reached, CSPCo will
be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.

NUCLEAR
-------

Nuclear Plants - Affecting I&M and TCC
--------------------------------------

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses
granted by the NRC. TCC owns 25.2% of the two-unit 2,500 MW STP. STPNOC
operates STP on behalf of the joint owners under licenses granted by the
NRC. The operation of a nuclear facility involves special risks,
potential liabilities, and specific regulatory and safety requirements.
Should a nuclear incident occur at any nuclear power plant facility in
the U.S., the resultant liability could be substantial. By agreement I&M
and TCC are partially liable together with all other electric utility
companies that own nuclear generating units for a nuclear power plant
incident at any nuclear plant in the U.S. In the event nuclear losses or
liabilities are underinsured or exceed accumulated funds and recovery
from customers is not possible, results of operations, cash flows and
financial condition would be adversely affected.

Nuclear Incident Liability - Affecting I&M and TCC
--------------------------------------------------

The Price-Anderson Act establishes insurance protection for public
liability arising from a nuclear incident at $10.6 billion and covers
any incident at a licensed reactor in the U.S. Commercially available
insurance provides $300 million of coverage. In the event of a nuclear
incident at any nuclear plant in the U.S., the remainder of the
liability would be provided by a deferred premium assessment of $101
million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $202
million per nuclear incident payable in annual installments of $20
million. TCC could be assessed $50 million per nuclear incident payable
in annual installments of $5 million as its share of a STPNOC
assessment. The number of incidents for which payments could be required
is not limited. Under an industry-wide program insuring workers at
nuclear facilities, I&M and TCC are also obligated for assessments of up
to $6 million and $2 million, respectively, for potential claims. These
obligations will remain in effect until December 31, 2007.

Insurance coverage for property damage, decommissioning and
decontamination at the Cook Plant and STP is carried by I&M and STPNOC
in the amount of $1.8 billion each. I&M and STPNOC jointly purchase $1
billion of excess coverage for property damage, decommissioning and
decontamination. Additional insurance provides coverage for extra costs
resulting from a prolonged accidental outage. I&M and STPNOC utilize an
industry mutual insurer for the placement of this insurance coverage.
Participation in this mutual insurer requires a contingent financial
obligation of up to $43 million for I&M and $2 million for TCC which is
assessable if the insurer's financial resources would be inadequate to
pay for losses.

The current Price-Anderson Act expired in August 2002. Its contingent
financial obligations still apply to reactors licensed by the NRC as of
its expiration date. It is anticipated that the Price-Anderson Act will
be renewed in 2004 with increases in required third party financial
protection for nuclear incidents.

SNF Disposal - Affecting I&M and TCC
------------------------------------

Federal law provides for government responsibility for permanent SNF
disposal and assesses nuclear plant owners fees for SNF disposal. A fee
of one mill per KWH for fuel consumed after April 6, 1983 at Cook Plant
and STP is being collected from customers and remitted to the U.S.
Treasury. Fees and related interest of $226 million for fuel consumed
prior to April 7, 1983 at Cook Plant have been recorded as long-term
debt. I&M has not paid the government the Cook Plant related pre-April
1983 fees due to continued delays and uncertainties related to the
federal disposal program. At December 31, 2003, funds collected from
customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and exceed the liability amount. TCC is
not liable for any assessments for nuclear fuel consumed prior to April
7, 1983 since the STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal - Affecting
I&M and TCC
---------------------------------------------------------------------

Decommissioning costs are accrued over the service lives of the Cook
Plant and STP. The licenses to operate the two nuclear units at Cook
Plant expire in 2014 and 2017. In November 2003, I&M filed to extend the
operating licenses of the two Cook Plant units for up to an additional
20 years. The review of the license extension application is expected to
take at least two years. After expiration of the licenses, Cook Plant is
expected to be decommissioned using the prompt decontamination and
dismantlement (DECON) method. The estimated cost of decommissioning and
low level radioactive waste accumulation disposal costs for Cook Plant
ranges from $821 million to $1,080 million in 2003 nondiscounted
dollars. The wide range is caused by variables in assumptions including
the estimated length of time SNF may need to be stored at the plant site
subsequent to ceasing operations. This, in turn, depends on future
developments in the federal government's SNF disposal program. Continued
delays in the federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated Cook Plant
decommissioning costs in its three rate-making jurisdictions based on at
least the lower end of the range in the most recent decommissioning
study at the time of the last rate proceeding. The amount recovered in
rates for decommissioning the Cook Plant and deposited in the external
fund was $27 million in 2003, 2002 and 2001.

The licenses to operate the two nuclear units at STP expire in 2027 and
2028. After expiration of the licenses, STP is expected to be
decommissioned using the DECON method. TCC estimates its portion of the
costs of decommissioning STP to be $289 million in 1999 nondiscounted
dollars. TCC is accruing and recovering these decommissioning costs
through rates based on the service life of STP at a rate of $8 million
per year.

Decommissioning costs recovered from customers are deposited in external
trusts. In 2003, 2002 and 2001, I&M deposited in its decommissioning
trust an additional $12 million each year related to special regulatory
commission approved funding for decommissioning of the Cook Plant. Trust
fund earnings increase the fund assets and decrease the amount needed to
be recovered from ratepayers. Decommissioning costs including interest,
unrealized gains and losses and expenses of the trust funds are recorded
in Other Operation expense for Cook Plant. For STP, nuclear
decommissioning costs are recorded in Other Operation expense, interest
income of the trusts are recorded in Nonoperating Income and interest
expense of the trust funds are included in Interest Charges.

TCC's nuclear decommissioning trust asset and liability are included in
held for sale amounts on its Consolidated Balance Sheet.

OPERATIONAL
-----------

Construction and Commitments - Affecting AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC
-----------------------------------------------------------------------

The AEP System has substantial construction commitments to support its
operations. The following table shows the estimated construction
expenditures by company for 2004 - 2006 including amounts for proposed
environmental rules:
                                (in millions)

      AEGCo                             $73.3
      APCo                            1,307.2
      CSPCo                             391.4
      I&M                               645.1
      KPCo                              153.3
      OPCo                            1,686.4
      PSO                               296.2
      SWEPCo                            414.3
      TCC                               531.2
      TNC                               179.9

AEP subsidiaries have entered into long-term contracts to acquire fuel
for electric generation. The expiration date of the longest fuel
contract is 2007 for APCo, 2005 for CSPCo, 2007 for I&M, 2005 for KPCo,
2012 for OPCo, 2014 for PSO and 2006 for SWEPCo. The contracts provide
for periodic price adjustments and contain various clauses that would
release us from our obligations under certain conditions.

I&M has unit contingent contracts to supply approximately 250 MW of
capacity to unaffiliated entities through December 31, 2009. The
commitment is pursuant to a unit power agreement requiring the delivery
of energy only if the unit capacity is available.

Potential Uninsured Losses - Affecting AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC
---------------------------------------------------------------------

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

Power Generation Facility - Affecting OPCo
------------------------------------------

AEP has agreements with Juniper Capital L.P. (Juniper) for Juniper to
develop, construct, and finance a non-regulated merchant power
generation facility (Facility) near Plaquemine, Louisiana and lease the
Facility to AEP. Juniper will own the Facility and lease it to AEP after
construction is completed. AEP will sublease the Facility to The Dow
Chemical Company (Dow).

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

OPCo has entered an agreement with an affiliate that eliminates OPCo's
market exposure related to the PPA. AEP has guaranteed this affiliate's
performance under the agreement.

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

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

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

Merger Litigation - Affecting AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, TCC  and TNC
-----------------------------------------------------------------------

In 2002, the U.S. Court of Appeals for the District of Columbia ruled
that the SEC failed to prove that the June 15, 2000 merger of AEP with
CSW meets the requirements of the PUHCA and sent the case back to the
SEC for further review. Specifically, the court told the SEC to revisit
its conclusion that the merger met PUHCA requirements that utilities be
"physically interconnected" and confined to a "single area or region."

In its June 2000 approval of the merger, the SEC agreed with AEP that
the companies' systems are integrated because they have transmission
access rights to a single high-voltage line through Missouri and also
met the PUCHA's single region requirement because it is now technically
possible to centrally control the output of power plants across many
states. In its ruling, the appeals court said that the SEC failed to
support and explain its conclusions that the integration and single
region requirements are satisfied.

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

Enron Bankruptcy -Affecting APCo, CSPCo, I&M, KPCo and OPCo
-----------------------------------------------------------

On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are pending in the U.S. Bankruptcy Court for the
Southern District of New York. At the date of Enron's bankruptcy,
certain subsidiaries of AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1,
2001, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various
HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron's bankruptcy. The timing of the resolution of the
claims by the Bankruptcy Court is not certain.

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

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

During 2002 and 2001, AEP expensed a total of $53 million ($34 million
net of tax) for our estimated loss from the Enron bankruptcy. The
amounts for certain subsidiaries were:

                                                          Amounts
                                    Amounts                Net of
   Registrant                      Expensed                 Tax
   ----------                      --------               -------
                                            (in millions)

   APCo                              $5.3                   $3.4
   CSPCo                              2.7                    1.8
   I&M                                2.8                    1.8
   KPCo                               1.1                    0.7
   OPCo                               3.6                    2.3

The amount expensed was based on an analysis of contracts where AEP and
Enron entities are counterparties, the offsetting of receivables and
payables, the application of deposits from Enron entities and
management's analysis of the HPL related purchase contingencies and
indemnifications. As noted above, Enron has challenged the offsetting of
receivables and payables. 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.

Texas Commercial Energy, LLP Lawsuit - Affecting TCC and TNC
------------------------------------------------------------

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit in
federal District Court in Corpus Christi, Texas, in July 2003, against
AEP and four AEP subsidiaries, including TCC and TNC, certain
unaffiliated energy companies and ERCOT. The action alleges violations
of the Sherman Antitrust Act, fraud, negligent misrepresentation, breach
of fiduciary duty, breach of contract, civil conspiracy and negligence.
The allegations, not all of which are made against the AEP companies,
range from anticompetitive bidding to withholding power. TCE alleges
that these activities resulted in price spikes requiring TCE to post
additional collateral and ultimately forced it into bankruptcy when it
was unable to raise prices to its customers due to fixed price
contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court
costs. Two additional parties, Utility Choice, LLC and Cirro Energy
Corporation, have sought leave to intervene as plaintiffs asserting
similar claims. AEP and its subsidiaries filed a Motion to Dismiss in
September 2003. In February 2004, TCE filed an amended complaint. AEP
and its subsidiaries intend to file a motion to dismiss the amended
complaint and otherwise vigorously defend against the claims.

Energy Market Investigation - Affecting AEP System
--------------------------------------------------

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

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

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

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

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

FERC Proposed Standard Market Design - Affecting AEP System
-----------------------------------------------------------

In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
"white paper" on the proposal in April 2003, in response to the numerous
comments FERC received on its proposal. Management does not know if or
when the FERC will finalize a rule for SMD. Until the potential rule is
finalized, management cannot predict its effect on cash flows and
results of operations.

FERC Market Power Mitigation - Affecting AEP System
---------------------------------------------------

A FERC order issued in November 2001 on AEP's triennial market based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. Management is unable to predict
the timing of any further action by the FERC or its affect of future
results of operations and cash flows.


8.  GUARANTEES
--------------


There are no liabilities recorded for guarantees entered into prior to
December 31, 2002 by registrant subsidiaries in accordance with FIN 45.
There are certain immaterial liabilities recorded for guarantees entered
into subsequent to December 31, 2002. There is no collateral held in
relation to any guarantees and there is no recourse to third parties in
the event any guarantees are drawn unless specified below.

Letters of Credit
-----------------

Certain registrant subsidiaries have entered into standby letters of
credit (LOC) with third parties. These LOCs cover gas and electricity
risk management contracts, construction contracts, insurance programs,
security deposits, debt service reserves, and credit enhancements for
issued bonds. All of these LOCs were issued in the registrant
subsidiaries' ordinary course of business. At December 31, 2003, the
maximum future payments of the LOCs include $43 million, $1 million, $5
million and $4 million for TCC, I&M, OPCo and SWEPCo, respectively, with
maturities ranging from March 2004 to November 2005. AEP holds all
assets of the subsidiaries as collateral. There is no recourse to third
parties in the event these letters of credit are drawn.

SWEPCo
------

In connection with reducing the cost of the lignite mining contract for
its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
conditions, to assume the obligations under capital lease obligations
and term loan payments of the mining contractor, Sabine Mining Company
(Sabine). In the event Sabine defaults under any of these agreements,
SWEPCo's total future maximum payment exposure is approximately $58
million with maturity dates ranging from June 2005 to February 2012.

As part of the process to receive a renewal of a Texas Railroad
Commission permit for lignite mining, SWEPCo has agreed to provide
guarantees of mine reclamation in the amount of approximately $85
million. Since SWEPCo uses self-bonding, the guarantee provides for
SWEPCo to commit to use its resources to complete the reclamation in the
event the work is not completed by a third party miner. At December 31,
2003, the cost to reclaim the mine in 2035 is estimated to be
approximately $36 million. This guarantee ends upon depletion of
reserves estimated at 2035 plus 6 years to complete reclamation.

On July 1, 2003, SWEPCo consolidated Sabine due to the application of FIN 46
(see Note 2). Upon consolidation, SWEPCo recorded the assets and
liabilities of Sabine ($78 million). Also, after consolidation, SWEPCo
currently records all expenses (depreciation, interest and other
operation expense) of Sabine and eliminates Sabine's revenues against
SWEPCo's fuel expenses. There is no cumulative effect of an accounting
change recorded as a result of the requirement to consolidate, and there
is no change in net income due to the consolidation of Sabine.

Indemnifications and Other Guarantees
-------------------------------------

All of the registrant subsidiaries enter into certain types of
contracts, which would require indemnifications. Typically these
contracts include, but are not limited to, sale agreements, lease
agreements, purchase agreements and financing agreements. Generally
these agreements may include, but are not limited to, indemnifications
around certain tax, contractual and environmental matters. With respect
to sale agreements, exposure generally does not exceed the sale price.
Registrant subsidiaries cannot estimate the maximum potential exposure
for any of these indemnifications entered into prior to December 31,
2002 due to the uncertainty of future events. In 2003 registrant
subsidiaries entered into sale agreements which included
indemnifications with a maximum exposure that was not significant for
any individual registrant subsidiary. There are no material liabilities
recorded for any indemnifications entered into during 2003. There are no
liabilities recorded for any indemnifications entered prior to December
31, 2002.

Certain registrant subsidiaries lease certain equipment under a master
operating lease. Under the lease agreement, the lessor is guaranteed to
receive up to 87% of the unamortized balance of the equipment at the end
of the lease term. If the fair market value of the leased equipment is
below the unamortized balance at the end of the lease term, we have
committed to pay the difference between the fair market value and the
unamortized balance, with the total guarantee not to exceed 87% of the
unamortized balance. At December 31, 2003, the maximum potential loss by
subsidiary for these lease agreements assuming the fair market value of
the equipment is zero at the end of the lease term is as follows:

                            Maximum Potential Loss
                 Subsidiary                       (in millions)
                 ----------                       -------------

                    APCo                               $ 1
                    CSPCo                                1
                    I&M                                  2
                    KPCo                                 1
                    OPCo                                 3
                    PSO                                  4
                    SWEPCo                               4
                    TCC                                  6
                    TNC                                  2

See Note 15 "Leases" for disclosure of lease residual value guarantees.


9.  SUSTAINED EARNINGS IMPROVEMENT INITIATIVE
---------------------------------------------


In response to difficult conditions in AEP's business, a Sustained
Earnings Improvement (SEI) initiative was undertaken company-wide in the
fourth quarter of 2002, as a cost-saving and revenue-building effort to
build long-term earnings growth.

The registrant subsidiaries recorded termination benefits expense
relating to 389 terminated employees totaling $57.9 million pre-tax in
the fourth quarter of 2002. Of this amount, the registrant subsidiaries
paid $5.0 million to these terminated employees in the fourth quarter of
2002. No additional termination benefits expense related to the SEI
initiative was recorded in 2003, and the remaining SEI related payments
were made in 2003. The termination benefits expense is classified as
Other Operation expense on the registrant subsidiaries' statements of
operations. We determined that the termination of the employees under
our SEI initiative did not constitute a plan curtailment of any of our
retirement benefit plans.

The following table shows the staff reductions, termination benefits
expense and the remaining termination benefits expense accrual as of
December 31, 2002:

                      Total             Total Expense        Total Termination
                    Number of            Recorded in             Benefits
                    Terminated               2002           Accrued at 12/31/02
                     Employees          (in millions)          (in millions)
                    ----------          -------------       -------------------
AEGCo                     -                 $ 0.3                 $ 0.3
APCo                     93                  13.1                  12.2
CSPCo                    19                   5.0                   4.5
I&M                     146                  15.0                  13.1
KPCo                     16                   2.6                   2.5
OPCo                     33                   7.5                   7.1
PSO                      17                   3.1                   3.0
SWEPCo                    8                   3.3                   3.1
TCC                      37                   6.0                   5.5
TNC                      20                   2.0                   1.6

10.  ACQUISITIONS, DISPOSITIONS, IMPAIRMENTS, ASSETS HELD FOR SALE AND ASSETS
-----------------------------------------------------------------------------
     HELD AND USED
     -------------

ACQUISITIONS
------------

2001
----

SWEPCo purchased the Dolet Hills mining operations and assumed the
existing mine reclamation liabilities at its jointly owned lignite
reserves in Louisiana during 2001. Management recorded the assets
acquired and liabilities assumed at their estimated fair values in
accordance with APB Opinion No. 16 and SFAS 141 as appropriate based on
currently available information and on current assumptions as to future
operations.

DISPOSITIONS
------------

2003
----

Water Heater Assets - APCo, CSPCo, I&M, KPCo and OPCo
-----------------------------------------------------

APCo, CSPCo, I&M, KPCo and OPCo participated in a program to lease
electric water heaters to residential and commercial customers until a
decision was reached in the fourth quarter of 2002 to discontinue the
program and offer the assets for sale. We sold our water heater rental
program and recorded a pre-tax loss in the first quarter of 2003 based
upon final terms of the sale agreement. We provided for pre-tax charges
in the fourth quarter 2002 based on an estimated sales price. See below
for amounts by company:
<TABLE>
<CAPTION>


               Asset Impairment             Lease Prepayment              Loss on Sale
               Charge Recorded              Penalty Recorded           Recorded in First
Subsidiary    in Fourth Quarter            in Fourth Quarter                Quarter
Company         2002 (Pre-tax)               2002 (Pre-tax)              2003 (Pre-tax)
----------    -----------------            -----------------           -----------------
                                              (in millions)
<C>               <C>                            <C>                         <C>
APCo              $0.050                         $0.062                      $0.056
CSPCo              0.615                          0.758                       0.740
I&M                0.643                          0.792                       0.787
KPCo               0.011                          0.011                       0.011
OPCo               1.757                          2.163                       2.165
</TABLE>

Ft. Davis Wind Farm - TNC
-------------------------

In the 1990's TNC developed a 6MW facility wind energy project located
on a lease site near Ft. Davis, Texas. In the fourth quarter of 2002
TNC's engineering staff determined that operation of the facility was no
longer technically feasible and the lease of the underlying site should
not be renewed. Dismantling of the facility is expected to be completed
during 2004. An estimated pre-tax loss on abandonment of $4.7 million
was recorded in December 2002. The loss was recorded in Asset
Impairments on TNC's Statements of Operations.

2001
----

Coal Mines - OPCo
-----------------

In July 2001, OPCo sold coal mines in Ohio and West Virginia and agreed
to purchase approximately 34 million tons of coal from the purchaser of
the mines through 2008. The sale had a nominal impact on OPCo's results
of operations and cash flows.

ASSETS HELD FOR SALE
--------------------

Texas Plants - TCC and TNC
--------------------------

In September 2002, AEP indicated to ERCOT its intent to deactivate 16
gas-fired power plants (8 TCC plants and 8 TNC plants). ERCOT
subsequently conducted reliability studies, which determined that seven
plants (4 TCC plants and 3 TNC plants) would be required to ensure
reliability of the electricity grid. As a result of those studies, ERCOT
and AEP mutually agreed to enter into reliability must run (RMR)
agreements, which expired in December 2002, and were subsequently
renewed through December 2003. However, certain contractual provisions
provided ERCOT with a 90-day termination clause, if the contracted
facility was no longer needed to ensure reliability of the electricity
grid. With ERCOT's approval, AEP proceeded with its planned deactivation
of the remaining nine plants. In August 2003, pursuant to contractual
terms, ERCOT provided notification to AEP of its intent to cancel a RMR
agreement at one of the TNC plants. Upon termination of the agreement,
AEP proceeded with its planned deactivation of the plant. In December
2003, AEP and ERCOT mutually agreed to new RMR contracts at six plants
(4 TCC plants and 2 TNC plants) through December 2004, subject to
ERCOT's 90-day termination clause and the divestiture of the TCC
facilities.

As a result of the decision to deactivate TNC plants, a write-down of
utility assets of approximately $34.2 million (pre-tax) was recorded in
Asset Impairments expense during the third quarter 2002 on TNC's
Statements of Operations. The decision to deactivate the TCC plants
resulted in a write-down of utility assets of approximately $95.6
million (pre-tax), which was deferred and recorded in Regulatory Assets
during the third quarter 2002 in TCC's Consolidated Balance Sheets.

During the fourth quarter 2002, evaluations continued as to whether
assets remaining at the deactivated plants, including materials,
supplies and fuel oil inventories, could be utilized elsewhere within
the AEP System. As a result of such evaluations, TNC recorded an
additional asset impairment charge to Asset Impairments expense of $3.9
million (pre-tax) in the fourth quarter 2002. In addition, TNC recorded
related inventory write-downs of $2.6 million ($1.2 million of fuel
inventory in Fuel for Electric Generation expense and $1.4 million of
materials and supplies recorded in Other Operation expense). Similarly,
TCC recorded an additional asset impairment write-down of $6.7 million
(pre-tax), which was deferred and recorded in Regulatory Assets
Designated for Securitization in the fourth quarter 2002. TCC also
recorded related inventory write-downs of $14.9 million which was
deferred and recorded in Regulatory Assets in the fourth quarter 2002.

The total Texas plant asset impairment of $38.1 million in 2002 related
to TNC is included in Asset Impairments expense in TNC's Statements of
Operations.

In December 2002, TCC filed a plan of divestiture with the PUCT
proposing to sell all of its power generation assets, including the
eight gas-fired generating plants that were either deactivated or
designated as RMR status. During the fourth quarter of 2003, after
receiving bids from interested buyers, TCC recorded a $938 million
impairment loss and changed the classification of the plant assets from
plant in service to assets held for sale. In accordance with Texas
legislation, the $938 million impairment was offset by the establishment
of a regulatory asset, which is expected to be recovered through a wires
charge, subject to the final outcome of the 2004 Texas true-up
proceeding. See Texas Restructuring section of Note 6 "Customer Choice
and Industry Restructuring" for further discussion of the divestiture
plan, anticipated timeline and true-up proceeding.

The assets and liabilities of the entities held for sale at December 31,
2003 and 2002 are as follows:

                                             Texas
                                             Plants
                                              (TCC)
                                             ------
December 31,  2003                        (in millions)
------------------
Assets:
  Current Assets                               $57
  Property, Plant and Equipment, Net           797
  Regulatory Assets                             49
  Nuclear Decommissioning Trust Fund           125
                                            -------
  Total Assets Held for Sale                $1,028
                                            =======

Liabilities:
  Regulatory Liabilities - Other                $9
  Other Noncurrent Liabilities                 219
                                            -------
  Total Liabilities Held for Sale             $228
                                            =======


                                             Texas
                                             Plants
                                             (TCC)
                                             ------
December 31,  2002
------------------                        (in millions)
Assets:
 Current Assets                                $70
 Property, Plant and Equipment, Net          1,647
 Nuclear Decommissioning Trust Fund             98
                                            -------
 Total Assets Held for Sale                 $1,815
                                            =======

Liabilities:
  Deferred Credits and Other                    $9
                                            -------
  Total Liabilities Held for Sale               $9
                                            =======

ASSETS HELD AND USED
--------------------

Blackhawk Coal Company - I&M
----------------------------

Blackhawk Coal Company (Blackhawk) is a wholly-owned subsidiary of I&M
and was formerly engaged in coal mining operations until they ceased due
to gas explosions in the mine. During the fourth quarter of 2003, it was
determined that the value of the investment needed to be written down
based on an updated valuation reflecting management's decision not to
pursue development of potential gas reserves. As a result, a $10.4
million charge was recorded to reduce the value of the coal and gas
reserves to their estimated realizable value. This charge was recorded
in Nonoperating Expenses in I&M's Consolidated Statements of Income.


11.   BENEFIT PLANS
-------------------


APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in
AEP sponsored U.S. qualified pension plans and nonqualified pension
plans. A substantial majority of employees are covered by either one
qualified plan or both a qualified and a nonqualified pension plan. In
addition, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWPECo, TCC and TNC
participate in other postretirement benefit plans sponsored by AEP to
provide medical and death benefits for retired employees in the U.S.

The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two-year
period ending at the plan's measurement date of December 31, 2003, and a
statement of the funded status as of December 31 for both years:
<TABLE>
<CAPTION>

                                                                                                      U.S.
                                                                     U.S.                    Other Post Retirement
                                                                 Pension Plans                   Benefit Plans
                                                                 -------------               ---------------------
                                                             2003           2002              2003               2002
                                                             ----           ----              ----               ----
<C>                                                        <C>             <C>              <C>               <C>
Change in Benefit Obligation:                                                  (in millions)
Obligation at January 1                                    $3,583          $3,292            $1,877            $1,645
Service Cost                                                   80              72                42                34
Interest Cost                                                 233             241               130               114
Participant Contributions                                       -               -                14                13
Plan Amendments                                                 -              (2)                -                 -
Actuarial (Gain) Loss                                          91             258               192               152
Benefit Payments                                             (299)           (278)              (92)              (81)
                                                           -------         -------          --------          --------
Obligation at December 31                                  $3,688          $3,583            $2,163            $1,877
                                                           =======         =======          ========          ========

Change in Fair Value
 of Plan Assets:
Fair Value of Plan Assets at January 1                     $2,795          $3,438              $723              $711
Actual Return on Plan Assets                                  619            (371)              122               (57)
Company Contributions (a)                                      65               6               183               137
Participant Contributions                                       -               -                14                13
Benefit Payments (a)                                         (299)           (278)              (92)              (81)
                                                           -------         -------          --------          --------
Fair Value of Plan Assets at December, 31                  $3,180          $2,795              $950              $723
                                                           =======         =======          ========          ========


Funded Status:
Funded Status at December 31                                $(508)          $(788)          $(1,213)          $(1,154)
Unrecognized Net Transition
 (Asset) Obligation                                             2              (7)              206               233
Unrecognized Prior Service Cost                               (12)            (13)                6                 6
Unrecognized Actuarial (Gain) Loss                            797           1,020               977               896
                                                           -------         -------          --------          --------
Net Asset (Liability) Recognized                             $279            $212              $(24)             $(19)
                                                           =======         =======          ========          ========
</TABLE>


(a) AEP contributions and benefit payments include only those amounts
contributed directly to or paid directly from plan assets.


Accumulated Benefit Obligation:                 2003                 2002
                                                ----                 ----
                                                     (in millions)
U.S. Qualified Pension Plans                  $3,549               $3,456
U.S. Nonqualified Pension Plans                   76                   71
<TABLE>
<CAPTION>
                                                                                                         U.S.
                                                                   U.S.                          Other Post Retirement
                                                               Pension Plans                          Benefit Plans
                                                            ---------------------               ----------------------
                                                            2003             2002               2003            2002
                                                            ----             ----               ----            ----
                                                                                 (in millions)
<C>                                                        <C>              <C>                <C>              <C>
Prepaid Benefit Costs                                       $325            $255                 $-               $-
Accrued Benefit Liability                                    (46)            (44)               (24)             (19)
Additional Minimum Liability                                (723)           (944)               N/A              N/A
Unrecognized Prior Service Costs                              39              45                N/A              N/A
Accumulated Other Comprehensive Income                       684             900                N/A              N/A
                                                           ------           -----              -----             ----
Net Asset (Liability) Recognized                            $279            $212               $(24)            $(19)
                                                           ======           =====              =====            =====

Increase (Decrease) in Minimum Liability
  Included in Other Comprehensive
  Income (Pre-tax)                                         $(216)           $894                N/A              N/A
                                                           =======          =====              =====            =====
</TABLE>


N/A = Not Applicable

The asset allocations for the U.S. pension plans at the end of 2003 and
2002, and the target allocation for 2004, by asset category, are as
follows:

                       Target Allocation   Percentage of Plan Assets at Yearend
                       -----------------   ------------------------------------
Asset Category               2004                2003               2002
--------------               ----                ----               ----
                                             (in percentage)
Equity                         70                 71                 67
Fixed Income                   28                 27                 32
Cash and Cash Equivalents       2                  2                  1
                              ----               ----               ----
Total                         100                100                100
                              ====               ====               ====

The asset allocations for the U.S. other postretirement benefit plans at
the end of 2003 and 2002, and target allocation for 2004, by asset
category, are as follows:

                       Target  Allocation  Percentage of Plan Assets at Yearend
                       ------------------  -----------------------------------
Asset Category                2004                2003               2002
--------------                ----                ----               ----
                                                      (in percentage)
Equity                         70                 61                 41
Fixed Income                   28                 36                 38
Cash and Cash Equivalents       2                  3                 21
                              ----               ----               ----
Total                         100                100                100
                              ====               ====               ====


AEP's investment strategy for the employee benefit trust funds is to use
a diversified mixture of equity and fixed income securities to preserve
the capital of the funds and to maximize the investment earnings in
excess of inflation within acceptable levels of risk.

The value of the AEP qualified plans' assets increased from $2.795
billion at December 31, 2002 to $3.180 billion at December 31, 2003. The
qualified plans paid $292 million in benefits to plan participants
during 2003 (nonqualified plans paid $7 million in benefits). AEP's
plans remain in an underfunded position (plan assets are less than
projected benefit obligations) of $508 million at December 31, 2003. Due
to the pension plans currently being underfunded, AEP recorded income in
Other Comprehensive Income (OCI) of $154 million, and a reduction in the
Deferred Income Tax Asset of $76 million, offset by a reduction to
Minimum Pension Liability of $234 million and a reduction in adjustments
for unrecognized costs of $4 million. The charge to OCI does not affect
earnings or cash flow. Also, due to the current underfunded status of
AEP's qualified plans, AEP expects to make cash contributions to the
U.S. pension plans of approximately $41 million in 2004.

At December 31, 2003 and 2002, the projected benefit obligation,
accumulated benefit obligation, and fair value of U.S. plan assets of
the U.S. pension plans with an accumulated benefit obligation in excess
of plan assets, were as follows:

                                                          U.S. Plans
                                                       ----------------
 End of Year                                           2003        2002
 -----------                                           ----        ----
                                                         (in millions)
Projected Benefit Obligation                          $3,688      $3,583
Accumulated Benefit Obligation                         3,625       3,527
Fair Value of Plan Assets                              3,180       2,795
Accumulated Benefit Obligation
  Exceeds the Fair Value of Plan Assets                  445         732

AEP bases its determination of pension expense or income on a
market-related valuation of assets which reduces year-to-year
volatility. This market-related valuation recognizes investment gains or
losses over a five-year period from the year in which they occur.
Investment gains or losses for this purpose are the difference between
the expected return calculated using the market-related value of assets
and the actual return based on the market-related value of assets. Since
the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as
previously deferred gains or losses are recorded.

The  weighted-average assumptions as of December 31, used in the measurement
of AEP's benefit obligations are shown in the following tables:
<TABLE>
<CAPTION>

                                         U.S.                               U.S.
                                     Pension Plans              Other Postretirement Benefit Plans
                                     -------------              ----------------------------------
                                   2003          2002                  2003            2002
                                   ----          ----                  ----            ----
                                                      (in percentage)
<C>                                <C>           <C>                    <C>              <C>
Discount Rate                      6.25          6.75                   6.25             6.75
Rate of Compensation Increase       3.7           3.7                    N/A              N/A
</TABLE>


In determining the discount rate in the calculation of future pension
obligations AEP reviews the interest rates of long-term bonds that
receive one of the two highest ratings given by a recognized rating
agency. As a result of a decrease in this benchmark rate during 2003,
AEP determined that a decrease in its discount rate from 6.75% at
December 31, 2002 to 6.25% at December 31, 2003 was appropriate.

The rate of compensation increase assumed varies with the age of the
employee, ranging from 3.5% per year to 8.5% per year, with an average
increase of 3.7%.

Information about the expected cash flows for the U.S. pension
(qualified and non-qualified) and other postretirement benefit plans is
as follows:

                                                             U.S.
                                                     Other Postretirement
                                                           Benefit
                            U. S. Pension Plans             Plans
                            -------------------      --------------------
                                         (in millions)
Employer Contributions
2003                          $65                           $183
2004 (expected)                41                            180


The table below reflects the total benefits expected to be paid from the
plan or from AEP assets, including both AEP's share of the benefit cost
and the participants' share of the cost, which is funded by participant
contributions to the plan. Future benefit payments are dependent on the
number of employees retiring, whether the retiring employees elect to
receive pension benefits as annuities or as lump sum distributions,
future integration of the benefit plans with changes to Medicare and
other legislation, future levels of interest rates, and variances in
actuarial results. The estimated payments for pension benefits and other
postretirement benefits are as follows:


                                                                  U.S.
                                          U.S.             Other Postretirement
                                    Pension Benefits            Benefit Plans
                                    ----------------       --------------------
                                                  (in millions)
2004                                     $293                        $106
2005                                      300                         114
2006                                      310                         123
2007                                      325                         132
2008                                      335                         140
Years 2009 to 2013, in Total            1,840                         836

The contribution to the pension fund is based on the minimum amount
required by the U.S. Department of Labor or the amount of the pension
expense for accounting purposes, whichever is greater. The contribution
to the other postretirement benefit plans' trusts is generally based on
the amount of the other postretirement benefit plans' expense for
accounting purposes and is provided for in agreements with state
regulatory authorities.

The following table provides the components of AEP's net periodic
benefit cost (credit) for the plans for fiscal years 2003, 2002 and
2001:
<TABLE>
<CAPTION>

                                                          U.S.                                  U.S.
                                                      Pension Plans               Other Postretirement Benefit Plans
                                           ------------------------------         ----------------------------------
                                             2003        2002        2001           2003        2002         2001
                                             ----        ----        ----           ----        ----         ----
                                                                        (in millions)
<c>                                          <C>         <C>         <C>            <C>         <C>          <C>
Service Cost                                  $80         $72         $69            $42         $34          $30
Interest Cost                                 233         241         232            130         114          114
Expected Return on Plan Assets               (318)       (337)       (338)           (64)        (62)         (61)
Amortization of  Transition
 (Asset) Obligation                            (8)         (9)         (8)            28          29           30
Amortization of Prior-service
 Cost                                          (1)         (1)          -              -           -            -
Amortization of Net Actuarial
 (Gain) Loss                                   11         (10)        (24)            52          27           18
                                             -----       -----       -----          -----       -----        -----
Net Periodic Benefit Cost (Credit)             (3)        (44)        (69)           188         142          131
Curtailment Loss                                -           -           -              -           -            1
                                             -----       -----       -----          -----       -----        -----
Net Periodic Benefit Cost  (Credit)
 After Curtailments                           $(3)       $(44)       $(69)          $188        $142         $132
                                             =====       =====       =====          =====       =====        =====
</TABLE>


The following table provides the net periodic benefit cost (credit) for
the plans by the following AEP registrant subsidiaries for fiscal years
2003, 2002 and 2001:
<TABLE>
<CAPTION>


                                                        Pension Plans               Other Postretirement Benefit Plans
                                              ------------------------------        ----------------------------------
                                              2003         2002         2001            2003       2002          2001
                                              ----         ----         ----            ----       ----          ----
                                                                           (thousands)
       <C>                                 <C>          <C>         <C>              <C>        <C>           <C>
       APCo                                $(5,202)     $(9,988)    $(13,645)        $33,618    $25,107       $22,810
       CSPCo                                (5,399)      (8,328)     (10,624)         14,684     11,494        10,328
       I&M                                    (812)      (4,206)      (7,805)         22,999     17,608        15,077
       KPCo                                   (566)      (1,406)      (1,922)          4,043      2,986         2,438
       OPCo                                 (6,621)     (11,360)     (14,879)         28,143     22,608        34,444
       PSO                                    (291)      (3,819)      (2,480)          9,885      8,436         6,187
       SWEPCo                                1,012       (2,245)      (3,051)         10,264      8,371         6,399
       TCC                                    (123)      (4,786)      (3,411)         12,951     10,733         8,214
       TNC                                     606       (1,104)      (1,644)          5,875      4,798         3,729
</TABLE>

The weighted-average assumptions as of January 1, used in the
measurement of AEP's benefit costs are shown in the following tables:
<TABLE>
<CAPTION>

                                                         U.S.                                U.S.
                                                     Pension Plans              Other Postretirement Benefit Plans
                                             ----------------------------       ----------------------------------
                                             2003        2002        2001          2003        2002         2001
                                             ----        ----        ----          ----        ----         ----
                                                                       (in percentage)
<C>                                          <C>         <C>         <C>           <C>         <C>          <C>
Discount Rate                                6.75        7.25        7.50          6.75        7.25         7.50
Expected Return on Plan Assets               9.00        9.00        9.00          8.75        8.75         8.75
Rate of Compensation Increase                 3.7         3.7         3.2           N/A         N/A          N/A
</TABLE>


The expected return on plan assets for 2003 was determined by evaluating
historical returns, the current investment climate, rate of inflation,
and current prospects for economic growth. After evaluating the current
yield on fixed income securities as well as other recent investment
market indicators, the expected return on plan assets was reduced to
8.75% for 2004. The expected return on other postretirement benefit plan
assets (a portion of which is subject to capital gains taxes as well as
unrelated business income taxes) was reduced to 8.35%.

The assumptions used for other postretirement benefit plan measurement
purposes are shown below:

          Health Care Trend Rates:                 2003             2002
                                                  ------           -----
                                                     (in percentage)
          Initial                                   10.0            10.0
          Ultimate                                   5.0             5.0
          Year Ultimate Reached                     2008            2008

Assumed health care cost trend rates have a significant effect on the
amounts reported for the other postretirement benefit health care plans.
A 1% change in assumed health care cost trend rates would have the
following effects:

                                                     1% Increase    1% Decrease
                                                     -----------    -----------
                                                            (in millions)
  Effect on Total Service and Interest Cost
   Components of Net Periodic Postretirement
   Health Care Benefit Cost                               $26         $(21)

  Effect on the Health Care Component of the
   Accumulated Postretirement Benefit Obligation          315         (257)

AEP has not yet determined the impact of the Medicare Prescription Drug
Improvement and Modernization Act of 2003 on its other postretirement
benefit plans' accumulated benefit obligation and periodic benefit cost.
See FASB Staff Position No. 106-1 in Note 2 for additional information
on the potential impact on AEP's results of operations, cash flows and
financial condition.

Retirement Savings Plan
-----------------------

APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC participate in an
AEP sponsored defined contribution retirement savings plan eligible to
substantially all non-United Mine Workers of America (UMWA) employees.
This plan includes features under Section 401(k) of the Internal Revenue
Code and provides for company matching contributions. Prior to January
1, 2003, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC
participated in two large AEP sponsored defined contribution retirement
savings plans. Beginning in 2001 and continuing with the single merged
plan, contributions to the plans increased from 50% to 75% of the first
6% of eligible employee compensation.

The following table provides the cost for contributions to the
retirement savings plans by the following AEP registrant subsidiaries
for fiscal years 2003, 2002 and 2001:

                               2003           2002         2001
                               ----           ----         ----
                                         (in thousands)

              APCo            $6,450         $ 6,722      $7,031
              CSPCo            2,745           2,784       2,789
              I&M              7,616           8,039       7,833
              KPCo             1,042           1,043       1,016
              OPCo             5,719           5,785       6,398
              PSO              2,350           2,260       2,235
              SWEPCo           3,418           3,170       2,896
              TCC              2,757           3,054       3,046
              TNC              1,332           1,574       1,558

Other UMWA Benefits
-------------------

OPCo provides UMWA pension, health and welfare benefits for certain
unionized mining employees, retirees, and their survivors who meet
eligibility requirements. UWMA trustees make final interpretive
determinations with regard to all benefits. The pension benefits are
administered by UMWA trustees and contributions are made to their trust
funds. The health and welfare benefits are administered by AEP and
benefits are paid from AEP's general assets. Contributions are expensed
as paid as part of the cost of active mining operations and were not
material in 2003, 2002 and 2001. In July 2001, OPCo sold certain coal
mines in Ohio and West Virginia.


12.  BUSINESS SEGMENTS
----------------------


All of AEP's registrant subsidiaries have one reportable segment. The
one reportable segment is a vertically integrated electricity
generation, transmission and distribution business except AEGCo, an
electricity generation business. All of the registrants' other
activities are insignificant. The registrant subsidiaries' operations
are managed on an integrated basis because of the substantial impact of
bundled cost-based rates and regulatory oversight on the business
process, cost structures and operating results.


13.  DERIVATIVES, HEDGING AND FINANCIAL INSTRUMENTS
---------------------------------------------------


Derivatives and Hedging
-----------------------

In the first quarter of 2001, we adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. Registrant
Subsidiaries recorded a transition adjustment to Accumulated Other
Comprehensive Income (Loss) on January 1, 2001 in connection with the
adoption of SFAS 133. Derivatives included in the transition adjustment
are interest rate swaps, foreign currency swaps and commodity swaps,
options and futures.

SFAS 133 requires recognition of all derivative instruments as either
assets or liabilities in the statement of financial position at fair
value. Registrant subsidiaries accounting for the changes in the fair
value of a derivative instrument depends on whether it qualifies, and
has been designated, as part of a hedging relationship and further, on
the type of hedging relationship. Registrant subsidiaries designate the
hedging instrument, based on the exposure being hedged, as a fair value
hedge or a cash flow hedge. Certain qualifying derivative instruments
have been designated as normal purchase or normal sale contracts, as
provided in SFAS 133. These contracts are not reported at fair value, as
otherwise required by SFAS 133.

For fair value hedges (i.e. hedging the exposure to changes in the fair
value of an asset, liability or an identified portion thereof that is
attributable to a particular risk), registrant subsidiaries recognize
the gain or loss on the derivative instrument as well as the offsetting
loss or gain on the hedged item associated with the hedged risk in
Revenues in the Consolidated Statements of Operations during the period
of change. For cash flow hedges (i.e., hedging the exposure to
variability in expected future cash flows that is attributable to a
particular risk), registrant subsidiaries initially report the effective
portion of the gain or loss on the derivative instrument as a component
of Other Accumulated Comprehensive Income and subsequently reclassify it
to Revenues in the Consolidated Statements of Operations when the
forecasted transaction affects earnings. The remaining gain or loss on
the derivative instrument in excess of the cumulative change in the
present value of future cash flows of the hedged item, if any, is
recognized currently in revenues during the period of change. Registrant
subsidiaries recognize any ineffective portions of in revenues
immediately during the period of change.

Fair Value Hedging Strategies
-----------------------------

Certain registrant subsidiaries enter into interest rate forward and
swap transactions for interest rate risk exposure management purposes.
The interest rate forward and swap transactions effectively modifies our
exposure to interest risk by converting a portion of our fixed-rate debt
to a floating rate. Registrant subsidiaries do not hedge all interest
rate exposure.

Cash Flow Hedging Strategies
----------------------------

Certain registrant subsidiaries enter into forward contracts to protect
against the reduction in value of forecasted cash flows resulting from
transactions denominated in foreign currencies. When the dollar
strengthens significantly against the foreign currencies, the decline in
value of future foreign currency revenue is offset by gains in the value
of the forward contracts designated as cash flow hedges. Conversely,
when the dollar weakens, the increase in the value of future foreign
currency cash flows is offset by losses in the value of forward
contracts. Registrant subsidiaries do not hedge all foreign currency
exposure.

Certain registrant subsidiaries enter into interest rate forward and
swap transactions in order to manage interest rate risk exposure. These
transactions effectively modify our exposure to interest risk by
converting a portion of our floating-rate debt to a fixed rate.
Registrant subsidiaries do not hedge all interest rate exposure.

Registrant subsidiaries enter into forward and swap transactions for the
purchase and sale of electricity to manage the variable price risk
related to the forecasted purchase and sale of electricity. We closely
monitor the potential impact of commodity price changes and, where
appropriate, enter into contracts to protect margin for a portion of
future sales and generation revenues. Registrant Subsidiaries do not
hedge all variable price risk exposure related to the forecasted
purchase and sale of electricity.

The following table represents the activity in Accumulated Other
Comprehensive Income (Loss) related to the effect of adopting SFAS 133
for derivative contracts that qualify as cash flow hedges at December 31, 2003:

                                                          (in thousands)
APCo
  Beginning Balance, January 1, 2003                           $(1,920)
  Effective portion of changes in fair value                      (448)
  Reclasses from AOCI to net income                                799
                                                               --------
  Ending Balance, December 31, 2003                            $(1,569)
                                                               ========

CSPCo
  Beginning Balance, January 1, 2003                             $(267)
  Effective portion of changes in fair value                       194
  Reclasses from AOCI to net income                                275
                                                               --------
 Ending Balance, December 31, 2003                                $202
                                                               ========

I&M
  Beginning Balance, January 1, 2003                             $(286)
  Effective portion of changes in fair value                       209
  Reclasses from AOCI to net income                                299
                                                               --------
  Ending Balance, December 31, 2003                               $222
                                                               ========

KPCo
  Beginning Balance, January 1, 2003                              $322
  Effective portion of changes in fair value                        75
  Reclasses from AOCI to net income                                 23
                                                               --------
  Ending Balance, December 31, 2003                               $420
                                                               ========

OPCo
  Beginning Balance, January 1, 2003                             $(738)
  Effective portion of changes in fair value                       256
  Reclasses from AOCI to net income                                379
                                                               --------
  Ending Balance, December 31, 2003                              $(103)
                                                               ========

PSO
  Beginning Balance, January 1, 2003                              $(42)
  Effective portion of changes in fair value                        18
  Reclasses from AOCI to net income                                180
                                                               --------
  Ending Balance, December 31, 2003                               $156
                                                               ========

SWEPCo
  Beginning Balance, January 1, 2003                              $(48)
  Effective portion of changes in fair value                        21
  Reclasses from AOCI to net income                                211
                                                               --------
  Ending Balance, December 31, 2003                               $184
                                                               ========

TCC
  Beginning Balance, January 1, 2003                              $(36)
  Effective portion of changes in fair value                    (1,931)
  Reclasses from AOCI to net income                                139
                                                               --------
  Ending Balance, December 31, 2003                            $(1,828)
                                                               ========

TNC
  Beginning Balance, January 1, 2003                              $(15)
  Effective portion of changes in fair value                      (641)
  Reclasses from AOCI to net income                                 55
                                                               --------
  Ending Balance, December 31, 2003                              $(601)
                                                               ========

The following table approximates net gain (losses) from cash flow hedges
in Accumulated Other Comprehensive Income (Loss) at December 31, 2003
that are expected to be reclassified to net income in the next twelve
months as the items being hedged settle. The actual amounts reclassified
from AOCI to Net Income can differ as a result of market price changes.
The maximum term for which the exposure to the variability of future
cash flows is being hedged is five years.

                                      (in thousands)
APCo                                      $1,325
CSPCo                                        940
I&M                                        1,031
KPCo                                         466
OPCo                                       1,231
PSO                                          724
SWEPCo                                       853
TCC                                       (1,413)
TNC                                         (435)


Financial Instruments
---------------------

Market Valuation of Non-Derivative Financial Instrument
-------------------------------------------------------

The fair values of Long-term Debt and preferred stock subject to
mandatory redemption are based on quoted market prices for the same or
similar issues and the current dividend or interest rates offered for
instruments with similar maturities. These instruments are not
marked-to-market. The estimates presented are not necessarily indicative
of the amounts that could be realized in a current market exchange. The
book values and fair values of significant financial instruments for
registrant subsidiaries at December 31, 2003 and 2002 are summarized in
the following tables.
<TABLE>
<CAPTION>

                                                        2003                                               2002
                                           Book  Value             Fair Value             Book Value               Fair Value
                                           -----------             ----------             ----------               ----------
                                                    (in thousands)                                   (in thousands)

<C>                                         <C>                    <C>                    <C>                      <C>
AEGCo
Long-term Debt                                 $44,811                $47,882                $44,802                  $48,103

APCo
Long-term Debt                              $1,864,081             $1,926,518             $1,893,861               $1,953,087
Cumulative Preferred Stock
  Subject to Mandatory
  Redemption (a)                                 5,360                  5,287                 10,860                    9,774

CSPCo
Long-term Debt                                $897,564               $938,595               $621,626                 $643,715

I&M
Long-term Debt                              $1,339,359             $1,400,937             $1,617,062               $1,673,363
Cumulative Preferred Stock
  Subject to Mandatory                          63,445                 63,293                 64,945                   58,948
  Redemption (a)

KPCo
Long-term Debt                                $427,602               $439,636               $466,632                 $475,455

OPCo
Long-term Debt                              $2,039,940             $2,117,131             $1,067,314               $1,095,197
Cumulative Preferred Stock
  Subject to Mandatory
  Redemption (a)                                 7,250                  7,214                  8,850                    7,965

PSO
Long-term Debt                                $574,298               $589,956               $545,437                 $570,761
Trust Preferred Securities (b)                       -                      -                 75,000                   75,900

SWEPCo
Long-term Debt                                $884,308               $917,982               $693,448                 $727,085
Trust Preferred Securities (b)                       -                      -                110,000                  110,880

TCC
Long-term Debt                              $2,291,625             $2,393,468             $1,438,565               $1,522,373
Trust Preferred Securities (b)                       -                      -                136,250                  136,959

TNC
Long-term Debt                                $356,754               $374,420               $132,500                 $144,060
</TABLE>


(a) See Registrants Statements of Capitalization for the effect of SFAS 150 in
    2003.
(b) See Note 16 on Trust Preferred Securities.

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value
--------------------------------------------------------------------------

The trust investments are classified as available for sale for
decommissioning (I&M, TCC) and SNJ disposal for I&M. I&M reports trusts
in "Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds"
on the Consolidated Balance Sheets. TCC reports trusts in "Assets Held
for Sale - Texas Generating Plants" on their Consolidated Balance
Sheets. The following table provides fair values, cost basis and net
unrealized gains or losses at December 31:
<TABLE>
<CAPTION>



                                                 I&M                                              TCC
                                                 ---                                              ---
                                            (in thousands)                                   (in thousands)
                                        2003            2002                                2003            2002
                                        ----             ----                               ----            ----

<c>                                   <C>             <C>                                 <C>             <C>
Fair Value                            $982,400        $870,700                            $125,400        $98,400
Cost Basis                            $900,000        $823,900                             $94,800        $84,600
</TABLE>


<TABLE>
<CAPTION>

                                     2003        2002           2001                  2003         2002            2001
                                     ----        ----           ----                  ----         ----            ----
                                            (in thousands)                                  (in thousands)
<c>                               <C>         <C>            <C>                   <C>          <C>             <C>
Net Unrealized
Holding Gain (Loss)               $35,500     $(25,400)      $(8,300)              $16,700      $(7,500)        $(3,000)
</TABLE>

<TABLE>
<CAPTION>



14.  INCOME TAXES
-----------------


The details of the registrant subsidiaries income taxes before
extraordinary items and cumulative effect of accounting changes as reported are
as follows:

                                                          AEGCo          APCo          CSPCo          I&M           KPCo
                                                          -----          ----          -----          ---           ----
<C>                                                    <C>            <C>           <C>            <C>           <C>
Year Ended December 31, 2003                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                               $7,481        $84,449       $83,469        $58,190       $(7,840)
   Deferred                                              (5,838)        37,024         3,982             66        21,183
   Deferred Investment Tax Credits                           -          (1,884)       (3,041)        (7,330)       (1,168)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                              1,643        119,589        84,410         50,926        12,175
                                                       ---------      ---------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                                 (196)          (646)       (2,183)         5,283        (1,382)
   Deferred                                                   -        (12,461)       (8,496)       (14,960)       (1,076)
   Deferred Investment Tax Credits                       (3,354)        (1,262)          (69)          (101)          (42)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                             (3,550)       (14,369)      (10,748)        (9,778)       (2,500)
                                                       ---------      ---------     ---------      ---------     ---------
Total Income Tax as Reported                            $(1,907)      $105,220       $73,662        $41,148        $9,675
                                                       =========      =========     =========      =========     =========


                                                          OPCo           PSO           SWEPCo         TCC           TNC
                                                          ----           ---           ------         ---           ---
Year Ended December 31, 2003                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                             $116,316        $55,834       $51,564        $88,530       $33,822
   Deferred                                              32,191        (17,036)        7,230         14,769        (5,113)
   Deferred Investment Tax Credits                       (2,493)        (1,790)       (4,326)        (5,207)       (1,520)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                            146,014         37,008        54,468         98,092        27,189
                                                       ---------      ---------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                                  708         (1,566)       (6,108)         2,456         1,454
   Deferred                                              (7,709)         2,395         2,712          4,624         1,620
   Deferred Investment Tax Credits                         (614)             -             -              -             -
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                             (7,615)           829        (3,396)         7,080         3,074
                                                       ---------      ---------     ---------      ---------     ---------
Total Income Tax as Reported                           $138,399        $37,837       $51,072       $105,172       $30,263
                                                       =========      =========     =========      =========     =========


                                                          AEGCo          APCo          CSPCo          I&M           KPCo
                                                          -----          ----          -----          ---           ----
Year Ended December 31, 2002                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                               $6,607        $99,140       $81,538        $66,063          $680
   Deferred                                              (5,028)        17,626        25,771        (19,870)        9,451
   Deferred Investment Tax Credits                            2         (3,229)       (3,095)        (7,340)       (1,173)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                              1,581        113,537       104,214         38,853         8,958
                                                       ---------      ---------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                                 (173)          (354)        9,442          3,435         1,583
   Deferred                                                   -           (849)       (2,479)         2,949           388
   Deferred Investment Tax Credits                       (3,363)        (1,408)         (174)          (400)          (67)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                             (3,536)        (2,611)        6,789          5,984         1,904
                                                       ---------      ---------     ---------      ---------     ---------
Total Income Tax as Reported                            $(1,955)      $110,926      $111,003        $44,837       $10,862
                                                       ========       =========     =========      =========     =========


                                                          OPCo           PSO           SWEPCo         TCC           TNC
                                                          ----           ---           ------         ---           ---
Year Ended December 31, 2002                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                              $86,026       $(49,673)      $41,354        $30,494          $109
   Deferred                                              30,048         75,659        (3,134)       113,726       (10,652)
   Deferred Investment Tax Credits                       (2,493)        (1,791)       (4,524)        (5,206)       (1,271)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                            113,581         24,195        33,696        139,014       (11,814)
                                                       ---------      ---------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                                2,732         (1,812)        1,772          3,223         1,334
   Deferred                                              15,962              -             -            (71)       (1,623)
   Deferred Investment Tax Credits                         (684)             -             -               -            -
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                             18,010         (1,812)        1,772          3,152          (289)
                                                       ---------      ---------     ---------      ---------     ---------
Total Income Tax as Reported                           $131,591        $22,383       $35,468       $142,166      $(12,103)
                                                       =========      =========     =========      =========     =========


                                                          AEGCo          APCo          CSPCo          I&M           KPCo
                                                          -----          ----          -----          ---           ----
Year Ended December 31, 2001                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                               $9,126        $71,623       $88,013       $107,286        $7,726
   Deferred                                              (6,224)        27,198        14,923        (45,785)        2,812
   Deferred Investment Tax Credits                            -         (3,237)       (3,899)        (7,377)       (1,180)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                              2,902         95,584        99,037         54,124         9,358
                                                       ---------      ---------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                                  (56)       (19,165)      (13,803)       (10,590)       (2,726)
   Deferred                                                   -         21,832        17,885         16,580         3,481
   Deferred Investment Tax Credits                       (3,414)        (1,528)         (159)          (947)          (71)
                                                       ---------      ---------     ---------      ---------     ---------
       Total                                             (3,470)         1,139         3,923          5,043           684
                                                       ---------      ---------     ---------      ---------     ---------
Total Income Tax as Reported                              $(568)       $96,723      $102,960        $59,167       $10,042
                                                       ============   =========     =========      =========     =========


                                                          OPCo           PSO           SWEPCo         TCC           TNC
                                                          ----           ---           ------         ---           ---
Year Ended December 31, 2001                                                  (in thousands)
Charged (Credited) to Operating
 Expenses (net):
   Current                                             $(62,298)       $53,030       $77,965       $190,672       $19,424
   Deferred                                             166,166        (16,726)      (31,396)       (72,568)      (11,891)
   Deferred Investment Tax Credits                       (2,495)        (1,791)       (4,453)        (5,208)       (1,271)
                                                       ---------     ----------     ---------      ---------     ---------
       Total                                            101,373         34,513        42,116        112,896         6,262
                                                       ---------     ----------     ---------      ---------     ---------
Charged (Credited) to Nonoperating
  Income (net):
   Current                                              (21,600)           352           542         (1,749)         (691)
   Deferred                                              20,014              -             -              -             -
   Deferred Investment Tax Credits                         (794)             -             -              -             -
                                                       ---------     ----------     ---------      ---------     ---------
       Total                                             (2,380)           352           542         (1,749)         (691)
                                                       ---------     ----------     ---------      ---------     ---------
Total Income Tax as Reported                            $98,993        $34,865       $42,658       $111,147        $5,571
                                                       ===========   ==========     =========      =========     =========
</TABLE>



Shown below is a reconciliation for each registrant subsidiary of the
difference between the amount of federal income taxes computed by
multiplying book income before federal income taxes by the statutory
rate, and the amount of income taxes reported.
<TABLE>
<CAPTION>

                                                         AEGCo          APCo          CSPCo          I&M           KPCo
                                                         -----          ----          -----          ---           ----
Year Ended December 31, 2003                                                   (in thousands)
<C>                                                   <C>             <C>          <C>             <C>           <C>
Net Income                                              $7,964        $280,040     $200,430         $86,388       $32,330
Cumulative Effect of Accounting Change                       -         (77,257)     (27,283)          3,160         1,134
Income Taxes                                            (1,907)        105,220       73,662          41,148         9,675
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income                                          $6,057        $308,003     $246,809        $130,696       $43,139
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income at
 Statutory Rate (35%)                                   $2,120        $107,801      $86,383         $45,744       $15,099
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
    Depreciation                                           371           9,263        2,220          19,288         1,538
    Nuclear Fuel Disposal Costs                              -               -            -          (6,465)            -
    Allowance for Funds Used During
     Construction                                       (1,053)         (2,048)        (232)         (4,127)         (851)
    Rockport Plant Unit 2 Investment Tax
     Credit                                                374               -            -             397             -
    Removal Costs                                            -          (2,280)          (7)           (693)         (735)
    Investment Tax Credits (net)                        (3,354)         (3,146)      (3,110)         (7,431)       (1,210)
    State Income Taxes                                     372           1,123       (3,074)          4,634           (58)
    Other                                                 (737)         (5,493)      (8,518)        (10,199)       (4,108)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                         $(1,907)       $105,220      $73,662         $41,148        $9,675
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                  N.M.           34.2%        29.8%           31.5%         22.4%

                                                          OPCo           PSO           SWEPCo           TCC         TNC
                                                          ----           ---           ------           ---         ---
Year Ended December 31, 2003                                                   (in thousands)
Net Income                                            $375,663         $53,891      $98,141        $217,669       $58,557
Cumulative Effect of Accounting Change                (124,632)              -       (8,517)           (122)       (3,071)
Extraordinary Loss                                           -               -            -               -           177
Income Taxes                                           138,399          37,837       51,072         105,172        30,263
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income                                        $389,430         $91,728     $140,696        $322,719       $85,926
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income at
 Statutory Rate (35%)                                 $136,301         $32,105      $49,244        $112,952       $30,074
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                           4,388           1,166          834             486           286
  Investment Tax Credits (net)                          (3,107)         (1,791)      (4,326)         (5,207)       (1,521)
  State Income Taxes                                     4,717           2,886        9,723         (10,434)        3,078
  Other                                                 (3,900)          3,471       (4,403)          7,375        (1,654)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                        $138,399         $37,837      $51,072        $105,172       $30,263
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                 35.5%           41.2%        36.3%           32.6%         35.2%

                                                          AEGCo          APCo          CSPCo            I&M         KPCo
                                                          -----          ----          -----            ---         ----
Year Ended December 31, 2002                                                   (in thousands)
Net Income                                              $7,552        $205,492     $181,173         $73,992       $20,567
Income Taxes                                            (1,955)        110,926      111,003          44,837        10,862
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income                                          $5,597        $316,418     $292,176        $118,829       $31,429
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income at
 Statutory Rate (35%)                                   $1,959        $110,746     $102,262         $41,590       $11,000
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
   Depreciation                                            286           3,082        2,899          21,812         2,057
   Nuclear Fuel Disposal Costs                               -               -            -          (3,087)            -
   Allowance for Funds Used During
    Construction                                        (1,136)              -            -          (3,453)            -
   Rockport Plant Unit 2 Investment Tax
    Credit                                                 374               -            -               -             -
   Removal Costs                                             -               -            -               -          (735)
   Investment Tax Credits (net)                         (3,361)         (4,637)      (3,270)         (7,740)       (1,240)
   State Income Taxes                                      335           6,469       11,387             124         1,058
   Other                                                  (412)         (4,734)      (2,275)         (4,409)       (1,278)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                         $(1,955)       $110,926     $111,003         $44,837       $10,862
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                  N.M.           35.1%        38.0%           37.7%         34.6%

                                                          OPCo           PSO           SWEPCo           TCC         TNC
                                                          ----           ---           ------           ---         ---
Year Ended December 31, 2002                                                  (in thousands)
Net Income (Loss)                                     $220,023         $41,060      $82,992        $275,941      $(13,677)
Income Taxes                                           131,591          22,383       35,468         142,166       (12,103)
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income (Loss)                                 $351,614         $63,443     $118,460        $418,107      $(25,780)
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income (Loss) at
 Statutory Rate (35%)                                 $123,065         $22,205      $41,461        $146,337       $(9,023)
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                           4,227            (583)      (2,790)           (295)          (32)
  Investment Tax Credits (net)                          (3,177)         (1,791)      (4,524)         (5,207)       (1,271)
  State Income Taxes                                    18,051           2,639        3,987           2,202        (1,577)
  Other                                                (10,575)            (87)      (2,666)           (871)         (200)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                        $131,591         $22,383      $35,468        $142,166      $(12,103)
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                 37.4%           35.3%        29.9%           34.0%         46.9%

                                                          AEGCo          APCo          CSPCo            I&M         KPCo
                                                          -----          ----          -----            ---         ----
Year Ended December 31, 2001                                                   (in thousands)
Net Income                                              $7,875        $161,818     $161,876         $75,788       $21,565
Extraordinary Loss                                           -               -       30,024               -             -
Income Taxes                                              (568)         96,723      102,960          59,167        10,042
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income                                          $7,307        $258,541     $294,860        $134,955       $31,607
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income at
 Statutory Rate (35%)                                   $2,557         $90,489     $103,201         $47,234       $11,062
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
   Depreciation                                            230           2,977        2,757          21,224         1,581
   Nuclear Fuel Disposal Costs                               -               -            -          (3,292)            -
   Allowance for Funds Used During
    Construction                                        (1,078)              -            -          (1,606)            -
   Rockport Plant Unit 2 Investment Tax
    Credit                                                 374               -            -               -             -
   Removal Costs                                             -               -            -               -          (420)
   Investment Tax Credits (net)                         (3,414)         (4,765)      (4,058)         (8,324)       (1,252)
   State Income Taxes                                    1,050           9,613        5,727           6,137           318
   Other                                                  (287)         (1,591)      (4,667)         (2,206)       (1,247)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                           $(568)        $96,723     $102,960         $59,167       $10,042
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                  N.M.           37.4%        34.9%           43.8%         31.8%

                                                          OPCo           PSO           SWEPCo           TCC         TNC
                                                          ----           ---           ------           ---         ---
Year Ended December 31, 2001                                                   (in thousands)
Net Income                                            $147,445         $57,759      $89,367        $182,278       $12,310
Extraordinary Loss                                      18,348               -            -               -             -
Income Taxes                                            98,993          34,865       42,658         111,147         5,571
                                                      ---------       ---------    ---------       ---------     ---------
Pre-Tax Income                                        $264,786         $92,624     $132,025        $293,425       $17,881
                                                      =========       =========    =========       =========     =========

Income Tax on Pre-Tax Income at
 Statutory Rate (35%)                                  $92,675         $32,418      $46,209        $102,699        $6,258
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
   Depreciation                                          7,972           1,127         (501)          8,477         1,463
   Investment Tax Credits (net)                         (3,289)         (1,791)      (4,453)         (5,207)       (1,271)
   State Income Taxes                                    9,752           5,137        5,451           9,652         1,283
   Other                                                (8,117)         (2,026)      (4,048)         (4,474)       (2,162)
                                                      ---------       ---------    ---------       ---------     ---------
Total Income Taxes as Reported                         $98,993         $34,865      $42,658        $111,147        $5,571
                                                      =========       =========    =========       =========     =========

Effective Income Tax Rate                                 37.4%           37.6%        32.3%           37.9%         31.2%
</TABLE>


The following tables show the elements of the net deferred tax liability
and the significant temporary differences for each registrant subsidiary:
<TABLE>
<CAPTION>

                                                          AEGCo          APCo          CSPCo            I&M         KPCo
                                                          -----          ----          -----            ---         ----
December 31, 2003                                                              (in thousands)
<C>                                                 <C>             <C>            <C>           <C>             <C>
Deferred Tax Assets                                    $79,545        $237,873      $122,453        $695,037       $44,413
Deferred Tax Liabilities                              (103,874)     (1,041,228)     (580,951)     (1,032,413)     (256,534)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                       $(24,329)      $(803,355)    $(458,498)      $(337,376)    $(212,121)
                                                    ===========     ===========    ==========    ============    ==========

Property Related Temporary Differences                $(62,271)      $(623,126)    $(357,980)       $(74,501)    $(151,404)
Amounts Due From Customers For
 Future Federal Income Taxes                             6,949         (94,457)       (5,575)        (37,233)      (23,203)
Deferred State Income Taxes                             (4,350)        (87,484)      (26,972)        (45,736)      (33,535)
Transition Regulatory Assets                                 -         (10,799)      (66,002)              -             -
Deferred Income Taxes on Other
 Comprehensive Loss                                          -          28,047        24,946          13,519         3,345
Net Deferred Gain on Sale and
 Leaseback-Rockport Plant Unit 2                        36,916               -             -          24,563             -
Accrued Nuclear Decommissioning Expense                      -               -             -        (173,054)            -
Deferred Fuel and Purchased Power                            -          24,047          (273)            (19)          496
Deferred Cook Plant Restart Costs                            -               -             -         (20,064)            -
Nuclear Fuel                                                 -               -             -          (7,027)            -
All Other (Net)                                         (1,573)        (39,583)      (26,642)        (17,824)       (7,820)
                                                    -----------     -----------    ----------    ------------    ---------
   Net Deferred Tax Liabilities                       $(24,329)      $(803,355)    $(458,498)      $(337,376)    $(212,121)
                                                    ===========     ===========    ==========    ============    ==========

                                                        OPCo             PSO          SWEPCo          TCC            TNC
                                                        ----             ---          ------          ---            ---
December 31, 2003                                                              (in thousands)
Deferred Tax Assets                                   $192,026        $164,801      $163,457        $298,648       $67,794
Deferred Tax Liabilities                            (1,125,608)       (500,235)     (512,521)     (1,543,560)     (180,813)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                      $(933,582)      $(335,434)    $(349,064)    $(1,244,912)    $(113,019)
                                                    ===========     ===========    ==========    ============    ==========

Property Related Temporary Differences               $(721,118)      $(297,809)    $(307,023)      $(698,554)    $(118,876)
Amounts Due From Customers For
 Future Federal Income Taxes                           (55,143)          8,728        (5,800)       (191,615)        9,979
Deferred State Income Taxes                            (80,573)        (56,413)      (33,651)        (42,044)       (2,946)
Transition Regulatory Assets                          (109,150)              -             -         (68,076)            -
Accrued Nuclear Decommissioning Expense                      -               -             -          (1,470)            -
Nuclear Fuel                                                 -               -             -          (7,240)            -
Deferred Income Taxes on Other
 Comprehensive Loss                                     26,280          23,607        23,644          33,316        14,387
Deferred Fuel and Purchased Power                           12          (8,460)      (10,996)         (1,738)      (10,143)
Regulatory Assets Designated for
 Securitization                                              -               -             -        (281,260)            -
All Other (Net)                                          6,110          (5,087)      (15,238)         13,769        (5,420)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                      $(933,582)      $(335,434)    $(349,064)    $(1,244,912)    $(113,019)
                                                    ===========     ===========    ==========    ============    ==========


                                                      AEGCo             APCo         CSPCo           I&M            KPCo
                                                      -----             ----         -----           ---            ----
December 31, 2002                                                              (in thousands)
Deferred Tax Assets                                    $82,889        $247,080      $106,597        $436,361       $45,231
Deferred Tax Liabilities                              (111,891)       (948,881)     (544,368)       (792,558)     (223,544)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                       $(29,002)      $(701,801)    $(437,771)      $(356,197)    $(178,313)
                                                    ===========     ===========    ==========    ============    ==========

Property Related Temporary Differences                $(74,291)      $(555,806)    $(331,166)      $(343,362)    $(127,069)
Amounts Due From Customers For
 Future Federal Income Taxes                             7,626         (58,246)       (8,895)        (38,752)      (20,488)
Deferred State Income Taxes                             (5,119)        (77,693)      (23,448)        (52,528)      (28,722)
Transition Regulatory Assets                                 -         (28,735)      (71,752)              -             -
Deferred Income Taxes on Other
 Comprehensive Loss                                          -          38,823        31,961          21,800         5,089
Net Deferred Gain on Sale and
 Leaseback-Rockport Plant Unit 2                        38,866               -             -          25,860             -
Accrued Nuclear Decommissioning Expense                      -               -             -          65,856             -
Deferred Fuel and Purchased Power                            -          (1,878)         (273)        (13,144)          415
Deferred Cook Plant Restart Costs                            -               -             -         (14,000)            -
Nuclear Fuel                                                 -               -             -          (5,153)            -
All Other (Net)                                          3,916         (18,266)      (34,198)         (2,774)       (7,538)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                       $(29,002)      $(701,801)    $(437,771)      $(356,197)    $(178,313)
                                                    ===========     ===========    ==========    ============    ==========

                                                       OPCo               PSO       SWEPCo           TCC             TNC
                                                       ----               ---       ------           ---             ---
December 31, 2002                                                              (in thousands)
Deferred Tax Assets                                   $189,281        $141,571      $158,925        $164,343       $62,211
Deferred Tax Liabilities                              (983,668)       (482,967)     (499,989)     (1,425,595)     (179,732)
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                      $(794,387)      $(341,396)    $(341,064)    $(1,261,252)    $(117,521)
                                                    ===========     ===========    ==========    ============    ==========

Property Related Temporary Differences               $(620,019)      $(303,888)    $(315,821)      $(709,246)    $(127,038)
Amounts Due From Customers For
 Future Federal Income Taxes                           (53,256)          9,490        (4,078)       (198,595)        5,726
Deferred State Income Taxes                            (46,990)        (57,911)      (48,372)        (66,333)       (4,080)
Transition Regulatory Assets                          (131,833)              -             -               -             -
Accrued Nuclear Decommissioning Expense                      -               -             -          (1,117)            -
Nuclear Fuel                                                 -               -             -          (7,023)            -
Deferred Income Taxes on Other
 Comprehensive Loss                                     39,246          29,332        28,906          39,394        16,565
Deferred Fuel and Purchased Power                          540         (28,696)        3,192           2,655        (9,933)
Regulatory Assets Designated For
 Securitization                                              -               -             -        (310,410)            -
All Other (Net)                                         17,925          10,277        (4,891)        (10,577)        1,239
                                                    -----------     -----------    ----------    ------------    ----------
   Net Deferred Tax Liabilities                      $(794,387)      $(341,396)    $(341,064)    $(1,261,252)    $(117,521)
                                                    ===========     ===========    ==========    ============    ==========
</TABLE>


Registrant subsidiaries have settled with the IRS all issues from the
audits of our consolidated federal income tax returns for the years
prior to 1991. Registrant Subsidiaries have received Revenue Agent's
Reports from the IRS for the years 1991 through 1996, and have filed
protests contesting certain proposed adjustments. Returns for the years
1997 through 2000 are presently being audited by the IRS. Management is
not aware of any issues for open tax years that upon final resolution
are expected to have a material adverse effect on results of operations.

Registrant Subsidiaries join in the filing of a consolidated federal
income tax return with the AEP System. The allocation of the AEP
System's current consolidated federal income tax to the System companies
is in accordance with SEC rules under the 1935 Act. These rules permit
the allocation of the benefit of current tax losses to the System
companies giving rise to them in determining their current tax expense.
The tax loss of the System parent company, AEP Co., Inc., is allocated
to its subsidiaries with taxable income. With the exception of the loss
of the parent company, the method of allocation approximates a separate
return result for each company in the consolidated group.


15.  LEASES
-----------


Leases of property, plant and equipment are for periods up to 99 years
and require payments of related property taxes, maintenance and
operating costs. The majority of the leases have purchase or renewal
options and will be renewed or replaced by other leases.

Lease rentals for both operating and capital leases are generally
charged to operating expenses in accordance with rate-making treatment
for regulated operations. Capital leases for non-regulated property are
accounted for as if the assets were owned and financed. The components
of rental costs are as follows:
<TABLE>
<CAPTION>

                                             AEGCo         APCo        CSPCo       I&M          KPCo         OPCo
                                             -----         ----        -----       ---          ----         ----
Year Ended December 31, 2003                                      (in thousands)
<C>                                        <C>           <C>          <C>       <C>            <C>         <C>
Lease Payments on
 Operating Leases                          $76,322       $6,148       $5,277    $110,714       $1,258      $27,337
Amortization of Capital Leases                 269        9,217        4,898       7,370        1,951        9,437
Interest on Capital Leases                       -        1,123          899       1,276          148        2,472
                                           --------     --------     --------   ---------      -------     --------
Total Lease Rental Costs                   $76,591      $16,488      $11,074    $119,360       $3,357      $39,246
                                           ========     ========     ========   =========      =======     ========

                                               PSO       SWEPCo        TCC         TNC
                                               ---       ------        ---         ---
Year Ended December 31, 2003                                     (in thousands)
Lease Payments on
 Operating Leases                           $4,883       $4,708       $6,360      $2,132
Amortization of Capital Leases                 174        1,434          161          83
Interest on Capital Leases                      17          899           16           9
                                           --------     --------     --------   ---------
Total Lease Rental Costs                    $5,074       $7,041       $6,537      $2,224
                                           ========     ========     ========   =========



                                             AEGCo         APCo        CSPCo       I&M          KPCo         OPCo
                                             -----         ----        -----       ---          ----         ----
Year Ended December 31, 2002                                     (in thousands)
Lease Payments on
 Operating Leases                          $76,143       $6,634       $5,209    $110,833       $1,597      $68,816
Amortization of Capital Leases                 238        9,729        6,010       8,319        2,171       12,637
Interest on Capital Leases                      19        2,240        1,717       2,221          469        4,501
                                           --------     --------     --------   ---------      -------     --------
Total Lease Rental Costs                   $76,400      $18,603      $12,936    $121,373       $4,237      $85,954
                                           ========     ========     ========   =========      =======     ========

                                               PSO       SWEPCo        TCC         TNC
                                               ---       ------        ---         ---
Year Ended December 31, 2002                                     (in thousands)
Lease Payments on
 Operating Leases                           $4,403       $3,240       $7,184      $1,981
Amortization of Capital Leases                   -            -            -           -
Interest on Capital Leases                       -            -            -           -
                                           --------     --------     --------   ---------
Total Lease Rental Costs                    $4,403       $3,240       $7,184      $1,981
                                           ========     ========     ========   =========


                                             AEGCo         APCo        CSPCo       I&M          KPCo         OPCo
                                             -----         ----        -----       ---          ----         ----
Year Ended December 31, 2001                                     (in thousands)
Lease Payments on
 Operating Leases                          $76,262       $6,142       $7,063    $104,574       $1,191      $63,913
Amortization of Capital Leases                 281       12,099        7,206      17,933        2,740       14,443
Interest on Capital Leases                      55        3,789        2,396       4,424          808        5,818
                                           --------     --------     --------   ---------      -------     --------
Total Lease Rental Costs                   $76,598      $22,030      $16,665    $126,931       $4,739      $84,174
                                           ========     ========     ========   =========      =======     ========




                                               PSO       SWEPCo        TCC         TNC
                                               ---       ------        ---         ---
Year Ended December 31, 2001                                     (in thousands)
Lease Payments on
 Operating Leases                           $4,010       $2,277       $5,948      $1,534
Amortization of Capital Leases                   -            -            -           -
Interest on Capital Leases                       -            -            -           -
                                           --------     --------     --------   ---------
Total Lease Rental Costs                    $4,010       $2,277       $5,948      $1,534
                                           ========     ========     ========   =========
</TABLE>


Property, plant and equipment under capital leases and related
obligations recorded on the Consolidated Balance Sheets are as follows:
<TABLE>
<CAPTION>


                                                AEGCo      APCo         CSPCo        I&M           KPCo
                                                -----      ----         -----        ---           ----
<C>                                          <C>         <C>          <C>          <C>            <C>
Year Ended December 31, 2003                                      (in thousands)
Property, Plant and Equipment
 Under Capital Leases
Production                                      $865      $2,758       $7,104       $4,492        $1,138
Distribution                                       -           -            -       14,589             -
Other                                              -      55,640       25,345       52,536        11,562
                                             --------    --------     --------     --------       -------
 Total Property, Plant and Equipment             865      58,398       32,449       71,617        12,700
Accumulated Amortization                         596      33,036       16,828       33,774         7,408
                                             --------    --------     --------     --------       -------
Net Property, Plant and
  Equipment Under
  Capital Leases                                $269     $25,362      $15,621      $37,843        $5,292
                                             ========    ========     ========     ========       =======

Obligations Under Capital Leases:
 Noncurrent Liability                           $182     $16,134      $11,397      $31,315        $3,549
 Liability Due Within One Year                    87       9,218        4,221        6,528         1,743
                                             --------    --------     --------     --------       -------
Total Obligations Under
  Capital Leases                                $269     $25,352      $15,618      $37,843        $5,292
                                             ========    ========     ========     ========       =======



                                                OPCo       PSO          SWEPCo       TCC           TNC
                                                ----       ---          ------       ---           ---
Year Ended December 31, 2003                                      (in thousands)
Property, Plant and Equipment
 Under Capital Leases
Production                                   $21,099          $-           $-           $-            $-
Distribution                                       -           -            -            -             -
Other                                         53,752       1,176       52,695        1,204           556
                                             --------    --------     --------     --------       -------
 Total Property, Plant and Equipment          74,851       1,176       52,695        1,204           556
Accumulated Amortization                      40,565         166       31,153          160            83
                                             --------    --------     --------     --------       -------
Net Property, Plant and Equipment Under
Capital Leases                               $34,286      $1,010      $21,542       $1,044          $473
                                             ========    ========     ========     ========       =======

Obligations Under Capital Leases:
 Noncurrent Liability                        $25,064        $558      $18,383         $636          $270
 Liability Due Within One Year                 9,624         452        3,159          407           203
                                             --------    --------     --------     --------       -------
Total Obligations Under
  Capital Leases                             $34,688      $1,010      $21,542       $1,043          $473
                                             ========    ========     ========     ========       =======



                                                AEGCo      APCo         CSPCo        I&M           KPCo
                                                -----      ----         -----        ---           ----
Year Ended December 31, 2002                                      (in thousands)
Property, Plant and Equipment
 Under Capital Leases
Production                                    $1,793      $3,368       $6,380       $5,728        $1,138
Distribution                                       -           -            -       14,589             -
Other:
 Mining Assets and Other                           -      67,395       46,791       70,140        14,258
                                             --------    --------     --------     --------       -------
 Total Property, Plant and Equipment           1,793      70,763       53,171       90,457        15,396
Accumulated Amortization                       1,294      37,452       26,551       41,141         8,168
                                             --------    --------     --------     --------       -------
Net Property, Plant and Equipment Under
  Capital Leases                                $499     $33,311      $26,620      $49,316        $7,228
                                             ========    ========     ========     ========       =======


Obligations Under Capital Leases:
 Noncurrent Liability                           $301     $23,991      $21,643      $42,619        $5,093
 Liability Due Within One Year                   200       9,598        5,967        8,229         2,155
                                             --------    --------     --------     --------       -------
Total Obligations Under
  Capital Leases                                $501     $33,589      $27,610      $50,848        $7,248
                                             ========    ========     ========     ========       =======

                                                OPCo       SWEPCo
                                                ----       ------
Year Ended December 31, 2002                      (in thousands)
Property, Plant and Equipment
 Under Capital Leases
Production                                   $21,360          $-
Distribution                                       -           -
Other:
 Mining Assets and Other                     103,018      45,699
                                             --------     -------
 Total Property, Plant and Equipment         124,378      45,699
Accumulated Amortization                      63,810      45,699
                                             --------     -------
Net Property, Plant and Equipment Under
Capital Leases                               $60,568          $-
                                             ========     =======

Obligations Under Capital Leases:
 Noncurrent Liability                        $51,266          $-
 Liability Due Within One Year                14,360           -
                                             --------     -------
Total Obligations Under
  Capital Leases                             $65,626          $-
                                             ========     =======
</TABLE>


Future minimum lease payments consisted of the following at December 31, 2003:
<TABLE>
<CAPTION>

                                                APCo         CSPCo        I&M        KPCo         OPCo
                                                ----         -----        ---        ----         ----
                                                                 (in thousands)
<C>                                        <C>            <C>          <C>        <C>            <C>         <C>
Capital Leases
2004                                          $11,735      $4,959      $10,050        $2,107     $11,046
2005                                            6,853       4,025        7,478         1,640       8,093
2006                                            5,183       2,676        6,239           957       7,536
2007                                            2,664       1,773       12,616           785       5,582
2008                                            2,645       2,050        3,669           256       3,677
Later Years                                     1,802       2,096        5,994           116       4,627
                                           -----------    --------     --------   -----------    --------
Total Future Minimum Lease
  Payments                                     30,882      17,579       46,046         5,861      40,561
Less Estimated Interest Element                 5,530       1,961        8,203           569       5,874
                                           -----------    --------     --------   -----------    --------
Estimated Present Value of  Future Minimum
Lease Payments                                $25,352     $15,618      $37,843        $5,292     $34,687
                                           ===========    ========     ========   ===========    ========

                                                  PSO       SWEPCo         TCC          TNC
                                                  ---       ------         ---          ---
                                                                 (in thousands)
Capital Leases
2004                                             $492      $4,737         $450          $223
2005                                              368       4,641          373           188
2006                                              194       4,533          198            87
2007                                               46       4,410           86             8
2008                                                4       4,389           24             1
Later Years                                         -       4,380            -             2
                                           -----------    --------     --------   -----------
Total Future Minimum Lease
  Payments                                      1,104      27,090        1,131           509
Less Estimated Interest Element                    94       5,548           88            36
                                           -----------    --------     --------   -----------
Estimated Present Value of Future
  Minimum Lease Payments                       $1,010     $21,542       $1,043          $473
                                           ===========    ========     ========   ===========


                                                AEGCo       APCo          CSPCo        I&M         KPCo         OPCo
                                                -----       ----          -----        ---         ----         ----
                                                                 (in thousands)
Noncancellable Operating Leases
2004                                          $73,854      $5,998       $5,078      $103,909      $1,209      $12,655
2005                                           73,854       5,154        4,920        97,447       1,084       11,886
2006                                           73,854       4,455        2,518        93,993         793       11,576
2007                                           73,854       3,302        2,205        91,328         771       11,132
2008                                           73,854       2,394        1,609        90,749         475       10,787
Later Years                                 1,033,956       6,094        2,726     1,096,567       1,785       66,918
                                           -----------    --------     --------   -----------    --------    ---------
Total Future Minimum Lease
  Payments                                 $1,403,226     $27,397      $19,056    $1,573,993      $6,117     $124,954
                                           ===========    ========     ========   ===========    ========    =========

                                                PSO        SWEPCo         TCC           TNC
                                                ---        ------         ---           ---
                                                                 (in thousands)
Noncancellable Operating Leases
2004                                           $4,684      $5,522       $6,112        $1,964
2005                                            4,520       6,020        5,886         1,945
2006                                            4,079       6,844        5,218         1,846
2007                                            3,424       7,218        4,397         1,532
2008                                            1,218       7,451        3,950         1,238
Later Years                                     8,616      17,849       11,272         4,981
                                           -----------    --------     --------   -----------
Total Future Minimum Lease
  Payments                                    $26,541     $50,904      $36,835       $13,506
                                           ===========    ========     ========   ===========
</TABLE>


Gavin Lease
-----------

OPCo has entered into an agreement with JMG, an unrelated special
purpose entity. JMG has a capital structure of which 3% is equity from
investors with no relationship to AEP or any of its subsidiaries and 97%
is debt from commercial paper, pollution control bonds and other bonds.
JMG was formed to design, construct and lease the Gavin Scrubber for the
Gavin Plant to OPCo. JMG owns the Gavin Scrubber and leases it to OPCo.
Prior to July 1, 2003, the lease was accounted for as an operating
lease. Payments under the lease agreement are based on JMG's cost of
financing (both debt and equity) and include an amortization component
plus the cost of administration. OPCo and AEP do not have an ownership
interest in JMG and do not guarantee JMG's debt.

At any time during the lease, OPCo has the option to purchase the Gavin
Scrubber for the greater of its fair market value or adjusted
acquisition cost (equal to the unamortized debt and equity of JMG) or
sell the Gavin Scrubber on behalf of JMG. The initial 15-year lease term
is non-cancelable. At the end of the initial term, OPCo can renew the
lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
the Gavin Scrubber on behalf of JMG. In case of a sale at less than the
adjusted acquisition cost, OPCo must pay the difference to JMG.

On March 31, 2003, OPCo made a prepayment of $90 million under this
lease structure. AEP recognizes lease expense on a straight-line basis
over the remaining lease term, in accordance with SFAS 13 "Accounting
for Leases." The asset will be amortized over the remaining lease term,
which ends in the first quarter of 2010.

On July 1, 2003, OPCo consolidated JMG due to the application of FIN 46.
Upon consolidation, OPCo recorded the assets and liabilities of JMG
($469.6 million). OPCo now records the depreciation, interest and other
operating expenses of JMG and eliminates JMG's revenues against OPCo's
operating lease expenses. There was no cumulative effect of an
accounting change recorded as a result of AEP's requirement to
consolidate JMG, and there was no change in net income due to the
consolidation of JMG. Since the debt obligations of JMG are now
consolidated, the JMG lease is no longer accounted for on a consolidated
basis as an operating lease and has been excluded from the above table
of future minimum lease payments.

Rockport Lease
--------------

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

The FASB and other accounting constituencies continue to interpret the
application of FIN 46 (revised December 2003) (FIN 46R). As a result,
AEGCo and I&M are continuing to review the application of this new
interpretation as it relates to the Rockport Plant Unit 2 transaction.
The gain from the sale was deferred and is being amortized over the term
of the lease, which expires in 2022. The Owner Trustee owns the plant
and leases it to AEGCo and I&M. The lease is accounted for as an
operating lease with the payment obligations included in the future
minimum lease payments schedule earlier in this note. The lease term is
for 33 years with potential renewal options. At the end of the lease
term, AEGCo and I&M have the option to renew the lease or the Owner
Trustee can sell the plant. Neither AEGCo, I&M nor AEP has an ownership
interest in the Owner Trustee and do not guarantee its debt.


16.  FINANCING ACTIVITIES
-------------------------


Trust Preferred Securities
--------------------------

PSO, SWEPCo and TCC have wholly-owned business trusts that have issued
trust preferred securities. The trusts which hold mandatorily redeemable
trust preferred securities were deconsolidated effective July 1, 2003 due
to the implementation of FIN 46. Therefore, $321 million ($75 million
PSO, $110 million SWEPCo and $136 million TCC), previously reported at
December 31, 2002 as Certain Subsidiary Obligated, Mandatorily
Redeemable, Preferred Securities of Subsidiary Trusts Holding Solely
Junior Subordinated Debentures of Such Subsidiaries, is now reported as
two components on the Balance Sheet. The investment in the trust is now
reported as Other Investments within Other Property and Investments of
$10 million ($2 million PSO, $3 million SWEPCo and $5 million TCC) and
the subordinated debentures are now reported as Notes Payable to Trust
within Long-term Debt of $331 million ($77 million PSO, $113 million
SWEPCo and $141 million TCC).

The Junior Subordinated Debentures of PSO and TCC mature on April 30,
2037. In October 2003, SWEPCo refinanced its Junior Subordinated
Debentures which are now due October 1, 2043. The following Trust
Preferred Securities issued by the wholly-owned statutory business trusts
of PSO, SWEPCo and TCC were outstanding at December 31, 2003 and 2002:

<TABLE>
<CAPTION>

                                                                                               Amount
                                        Units          Amount in          Amount in            Reported         Description of
                                        Issued/          Other          Notes Payable          Prior to           Underlying
                                        Outstanding   Investments          to Trust             FIN 46          Debentures of
Business Trust           Security       at 12/31/03  at 12/31/03 (a)    at 12/31/03 (b)      at 12/31/02 (c)      Registrant
--------------           --------       -----------  ---------------    ---------------      ---------------    --------------
                                                     (in millions)      (in millions)         (in millions)
<C>                   <C>               <C>                <C>               <C>                 <C>         <C>
CPL Capital I         8.00%, Series A   5,450,000           $5               $141                $136        TCC, $141 million,
                                                                                                              8.00%, Series A

PSO Capital I         8.00%, Series A   3,000,000            2                 77                  75        PSO, $77 million,
                                                                                                              8.00%, Series A

SWEPCo Capital I      7.875%, Series A          -            -                  -                 110        SWEPCo, $113 million,
                                                                                                              7.875%, Series A

SWEPCo Capital I      5.25%, Series B     110,000            3                113                   -        SWEPCo, $113 million,
                                        ----------         ----              -----               -----        5.25% five year fixed
                                                                                                              rate period, Series B

                                        8,560,000          $10               $331                $321
                                        ==========         ====              =====               =====
</TABLE>


(a) Amounts are in Other Investments within Other Property and Investments.
(b) Amounts are in Notes Payable to Trust within Long-term Debt.
(c) Amounts reported on Balance Sheet prior to FIN 46.

Each of the business trusts is treated as a non-consolidated subsidiary
of its parent company. The only assets of the business trusts are the
subordinated debentures issued by their parent company as specified
above. In addition to the obligations under their subordinated
debentures, each of the parent companies has also agreed to a security
obligation which represents a full and unconditional guarantee of its
capital trust obligation.

Lines of Credit - AEP System
----------------------------

The AEP System uses a corporate borrowing program to meet the short-term
borrowing needs of its subsidiaries. The corporate borrowing program
includes a utility money pool, which funds the utility subsidiaries, and
a non-utility money pool, which funds the majority of the non-utility
subsidiaries. In addition, the AEP System also funds, as direct
borrowers, the short-term debt requirements of other subsidiaries that
are not participants in the non-utility money pool for regulatory or
operational reasons. The AEP System Corporate Borrowing Program operates
in accordance with the terms and conditions outlined by the SEC. AEP has
authority from the SEC through March 31, 2006 for short-term borrowings
sufficient to fund the utility money pool and the non-utility money pool
as well as its own requirements in an amount not to exceed $7.2 billion.
Utility money pool participants include AEGCo, APCo, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, TCC and TNC (domestic utility companies). The
following are the SEC-authorized limits for short-term borrowings for
the domestic utility companies as of December 31, 2003:

                                                                 Authorized
                                                                 ----------
                                                               (in millions)
                    AEP Generating Company                          $125
                    AEP Texas Central Company (a)                    438
                    AEP Texas North Company (a)                      275
                    Appalachian Power Company                        600
                    Columbus Southern Power Company (a)              150
                    Indiana Michigan Power Company                   500
                    Kentucky Power Company                           200
                    Ohio Power Company (a)                           200
                    Public Service Company of Oklahoma               300
                    Southwestern Electric Power Company              350

(a)  Short-term borrowing limits for these domestic utility companies are
     reduced by long-term debt issued commencing with the SEC order dated
     December 18, 2002, which authorized financing transactions through
     March 31, 2006.

As of December 31, 2003, AEP had credit facilities totaling $2.9 billion
to support its commercial paper program. At December 31, 2003, AEP had
$326 million outstanding in short-term borrowings of which $282 million
was commercial paper supported by the revolving credit facilities. In
addition, JMG has commercial paper outstanding in the amount of $26
million. This commercial paper is specifically associated with the Gavin
scrubber lease identified in Note 15 "Leases". This commercial paper
does not reduce available liquidity to AEP. The maximum amount of
commercial paper outstanding during the year, which had a weighted
average interest rate during 2003 of 1.98%, was $1.5 billion during
January 2003. On December 11, 2002, Moody's Investor Services placed
AEP's Prime-2 short-term rating for commercial paper under review for
possible downgrade. On January 24, 2003, Standard & Poor's Rating
Services placed AEP's A-2 short-term rating for commercial paper under
review for possible downgrade. On February 10, 2003, Moody's Investor
Services downgraded AEP's short-term rating for commercial paper to
Prime-3 from Prime-2. On March 7, 2003, Standard & Poor's Rating
Services reaffirmed AEP's A-2 short-term rating for commercial paper.

Net interest income (expense) recorded by each registrant subsidiary
related to amounts advanced to (borrowed from) the AEP money pool were:


                                Year Ended December 31,
                       -------------------------------------------

                       2003              2002                 2001
                       ----              ----                 ----
                                    (in millions)
AEGCo                 $(0.3)            $(0.2)               $(0.7)
APCo                    1.4              (4.1)                (9.9)
CSPCo                     -              (1.1)                (4.9)
I&M                     1.5               1.0                (12.6)
KPCo                   (0.9)             (1.6)                (2.3)
OPCo                   (1.6)             (5.7)               (13.2)
PSO                    (1.1)             (4.1)                (5.8)
SWEPCo                  0.1              (2.8)                (2.3)
TCC                       -              (6.3)               (11.1)
TNC                    (0.3)             (3.2)                (3.0)


Outstanding short-term debt for AEP Consolidated consisted of:


                                                    Year Ended December 31,
                                                  ---------------------------
                                                  2003                   2002
                                                  ----                   ----
                                                         (in millions)
Balance Outstanding:
  Notes Payable                                    $18                  $1,322
  Commercial Paper - AEP                           282                   1,417
  Commercial Paper - JMG                            26                      -
                                                  -----                 -------
Total                                             $326                  $2,739
                                                  =====                 =======

Sale of Receivables - AEP Credit
--------------------------------

AEP Credit has a sale of receivables agreement with banks and commercial
paper conduits. Under the sale of receivables agreement, AEP Credit
sells an interest in the receivables it acquires to the commercial paper
conduits and banks and receives cash. This transaction constitutes a
sale of receivables in accordance with SFAS 140, allowing the
receivables to be taken off of AEP Credit's balance sheet and allowing
AEP Credit to repay any debt obligations. AEP has no ownership interest
in the commercial paper conduits and does not consolidate these entities
in accordance with GAAP. We continue to service the receivables. This
off-balance sheet transaction was entered into to allow AEP Credit to
repay its outstanding debt obligations, continue to purchase the AEP
operating companies' receivables, and accelerate its cash collections.

AEP Credit extended its sale of receivables agreement to July 25, 2003
from its May 28, 2003 expiration date. The agreement was then renewed
for an additional 364 days and now expires on July 23, 2004. This new
agreement provides commitments of $600 million to purchase receivables
from AEP Credit. At December 31, 2003, $385 million was outstanding. As
collections from receivables sold occur and are remitted, the
outstanding balance for sold receivables is reduced and as new
receivables are sold, the outstanding balance of sold receivables
increases. All of the receivables sold represented affiliate
receivables. AEP Credit maintains a retained interest in the receivables
sold and this interest is pledged as collateral for the collection of
the receivables sold. The fair value of the retained interest is based
on book value due to the short-term nature of the accounts receivable
less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements
with certain registrant subsidiaries and, until the first quarter of
2002, with non-affiliated companies. These subsidiaries include CSPCo,
I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not
have regulatory authority to sell accounts receivable in all of its
regulatory jurisdictions, only a portion of APCo's accounts receivable
are sold to AEP Credit. As a result of the restructuring of electric
utilities in the State of Texas, the purchase agreement between AEP
Credit and Reliant Energy, Incorporated was terminated as of January 25,
2002 and the purchase agreement between AEP Credit and Texas-New Mexico
Power Company, the last remaining non-affiliated company, was terminated
on February 7, 2002. In addition, the purchase agreements between AEP
Credit and its Texas affiliates, AEP Texas Central Company (formerly
Central Power and Light Company) and AEP Texas North Company (formerly
West Texas Utilities Company) were terminated effective March 20, 2002.

 Comparative accounts receivable information for AEP Credit:
<TABLE>
<CAPTION>

                                                                      Year Ended December 31,
                                                                    ----------------------------

                                                                    2003                    2002
                                                                    ----                    ----
                                                                           (in millions)
<C>                                                                <C>                     <C>
Proceeds from Sale of Accounts Receivable                          $5,221                  $5,513
Accounts Receivable Retained Interest Less Uncollectible
 Accounts and Amounts Pledged as Collateral                           124                      76
Deferred Revenue from Servicing Accounts Receivable                     1                       1
Loss on Sale of Accounts Receivable                                     7                       4
Average Variable Discount Rate                                      1.33%                   1.92%
Retained Interest if 10% Adverse Change in
 Uncollectible Accounts                                               122                      74
Retained Interest if 20% Adverse Change in
 Uncollectible Accounts                                               121                      72
</TABLE>


Historical loss and delinquency amount for the AEP System's customer
accounts receivable managed portfolio:
<TABLE>
<CAPTION>

                                                                       Face Value
                                                                       ----------
                                                                 Year Ended December 31,
                                                                 -----------------------
                                                                 2003             2002
                                                                 ----             ----
                                                                      (in millions)
<C>                                                             <C>             <C>
Customer Accounts Receivable Retained                           $1,155          $1,553
Accrued Unbilled Revenues Retained                                 596             551
Miscellaneous Accounts Receivable Retained                          83              93
Allowance for Uncollectible Accounts Retained                     (124)           (108)
                                                                -------         -------
Total Net Balance Sheet Accounts Receivable                      1,710           2,089

Customer Accounts Receivable Securitized (Affiliate)               385             454
                                                                -------         -------
Total Accounts Receivable Managed                               $2,095          $2,543
                                                                =======         =======

Net Uncollectible Accounts Written Off                             $39             $48
                                                                =======         =======
</TABLE>


Customer accounts receivable retained and securitized for the domestic
electric operating companies are managed by AEP Credit. Miscellaneous
accounts receivable have been fully retained and not securitized.

At December 31, 2003, delinquent customer accounts receivable for the
electric utility affiliates that AEP Credit currently factors was $30
million.

Under the factoring arrangement, participating registrant subsidiaries
sell, without recourse, certain of their customer accounts receivable
and accrued unbilled revenue balances to AEP Credit and are charged a
fee based on AEP Credit financing costs, uncollectible accounts
experience for each company's receivables and administrative costs. The
costs of factoring customer accounts receivable are reported as an
operating expense. The amount of factored accounts receivable and
accrued unbilled revenues for each registrant subsidiary was as follows:

                                                     December 31,
                                                 ---------------------
                                                 2003             2002
                                                 ----             ----
                                                     (in millions)
       APCo                                     $60.2             $67.6
       CSPCo                                    100.2             114.3
       I&M                                       93.0             103.7
       KPCo                                      30.4              29.5
       OPCo                                      99.3             109.8
       PSO                                       99.6              83.7
       SWEPCo                                    64.4              65.2

The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:

                                         Year Ended December 31,
                                    ------------------------------------
                                    2003           2002             2001
                                    ----           ----             ----
                                               (in millions)
       APCo                         $3.4          $ 4.8            $ 5.2
       CSPCo                         9.8           15.8             15.2
       I&M                           6.1            7.4              8.5
       KPCo                          2.4            2.7              2.7
       OPCo                          8.7           11.4             12.8
       PSO                           5.8            7.2              9.6
       SWEPCo                        4.9            5.4              7.4
       TCC                             -            2.2             14.7
       TNC                             -            1.4              3.8


17.   RELATED PARTY TRANSACTIONS
--------------------------------


AEP System Power Pool
---------------------

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection
Agreement, dated July 6, 1951, as amended (the Interconnection
Agreement), defining how they share the costs and benefits associated
with their generating plants. This sharing is based upon each company's
"member-load-ratio," which is calculated monthly on the basis of each
company's maximum peak demand in relation to the sum of the maximum peak
demands of all five companies during the preceding 12 months. In
addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been parties
to the AEP System Interim Allowance Agreement which provides, among
other things, for the transfer of SO2 Allowances associated with
transactions under the Interconnection Agreement. As part of AEP's
restructuring settlement agreement filed with FERC, under certain
conditions CSPCo and OPCo would no longer be parties to the
Interconnection Agreement and certain other modifications to its terms
would also be made.

Power and Gas and risk management activities are conducted by the AEP
Power Pool and shared among the parties under the System Integration
Agreement. Risk management activities involve the purchase and sale of
electricity and gas under physical forward contracts at fixed and
variable prices and the risk management of electricity and to a lesser
extent gas contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions
represent physical forward contracts in the AEP System's traditional
marketing area and are typically settled by entering into offsetting
contracts. In addition, the AEP Power Pool enters into transactions for
the purchase and sale of electricity and gas options, futures and swaps,
and for the forward purchase and sale of electricity outside of the AEP
System's traditional marketing area.

AEP West Companies
------------------

PSO, SWEPCo, TCC, TNC operating companies of the west zone and AEPSC are
parties to a Restated and Amended Operating Agreement originally dated
as of January 1, 1997 (CSW Operating Agreement). The CSW Operating
Agreement requires the AEP West operating companies to maintain
specified annual planning reserve margins and requires the operating
companies that have capacity in excess of the required margins to make
such capacity available for sale to other operating companies as
capacity commitments. The CSW Operating Agreement also delegates to
AEPSC the authority to coordinate the acquisition, disposition,
planning, design and construction of generating units and to supervise
the operation and maintenance of a central control center. As part of
AEP's restructuring settlement agreement filed with the FERC, under
certain conditions TCC and TNC would no longer be parties to the CSW
Operating Agreement.

AEP's System Integration Agreement provides for the integration and
coordination of AEP's east and west zone operating subsidiaries, joint
dispatch of generation within the AEP System, and the distribution,
between the two operating zones, of costs and benefits associated with
the System's generating plants. It is designed to function as an
umbrella agreement in addition to the AEP Interconnection Agreement and
the CSW Operating Agreement, each of which will continue to control the
distribution of costs and benefits within each zone.

The following table shows the revenues derived from sales to the pools
and direct sales to affiliates for years ended December 31, 2003, 2002
and 2001:
<TABLE>
<CAPTION>


                                                 APCo         CSPCo         I&M          KPCo           OPCo         AEGCo
                                                 ----         -----         ----         ----           ----         -----
<C>                                           <C>           <C>        <C>            <C>            <C>          <C>
Related Party Revenues                                                         (in thousands)
2003      Sales to East System Pool           $130,921      $59,113      $228,667      $32,827       $503,334           $-
          Sales to West System Pool                 27            9            17            6             21            -
          Direct Sales To East Affiliates       60,638            -             -            -         50,764      232,955
          Direct Sales To West Affiliates       27,951       16,428        17,674        6,425         21,759            -
          Other                                  3,256        8,819         2,845          550          8,400            -
                                              ---------     --------   -----------    ---------      ---------    ---------
          Total Revenues                      $222,793      $84,369      $249,203      $39,808       $584,278     $232,955
                                              =========     ========   ===========    =========      =========    =========

2002      Sales to East System Pool           $106,651      $42,986      $197,525      $22,369       $397,248           $-
          Sales to West System Pool             18,300       12,107        13,036        4,717         16,265            -
          Direct Sales To East Affiliates       58,213            -             -            -         50,599      213,071
          Direct Sales To West Affiliates            -            -             -            -              -            -
          Other                                  3,313        2,109         3,577          878          1,090            -
                                              ---------     --------   -----------    ---------      ---------    ---------
          Total Revenues                      $186,477      $57,202      $214,138      $27,964       $465,202     $213,071
                                              =========     ========   ===========    =========      =========    =========

2001      Sales to East System Pool            $91,977      $44,185      $239,277      $34,735       $431,637           $-
          Sales to West System Pool             24,892       13,971        15,596        6,117         19,797            -
          Direct Sales To East Affiliates       54,777            -             -            -         55,450      227,338
          Direct Sales To West Affiliates       (3,133)      (1,705)       (1,905)        (744)        (2,590)           -
          Other                                  2,772       11,060         2,071        2,258          7,072            -
                                              ---------     --------   -----------    ---------      ---------    ---------
          Total Revenues                      $171,285      $67,511      $255,039      $42,366       $511,366     $227,338
                                              =========     ========   ===========    =========      =========    =========

                                                   PSO       SWEPCo          TCC           TNC
                                                   ---       ------          ---           ---
Related Party Revenues                                           (in thousands)

2003      Sales to East System Pool                 $-           $-            $-           $-
          Sales to West System Pool                793          600        15,157          651
          Direct Sales To East Affiliates        1,159          706           677            6
          Direct Sales To West Affiliates       17,855       64,802        23,248        1,929
          Other                                  3,323        2,746       114,486       52,567
                                              ---------     --------   -----------    ---------
         Total Revenues                        $23,130      $68,854      $153,568      $55,153
                                              =========     ========   ===========    =========

2002      Sales to East System Pool                 $-           $-            $-           $-
          Sales to West System Pool                674        1,334        18,416        1,280
          Direct Sales To East Affiliates          611          270           366          (23)
          Direct Sales To West Affiliates        6,047       75,674       956,751      228,404
          Other                                  2,107       (4,979)       32,911       10,764
                                              ---------     --------   -----------    ---------
          Total Revenues                        $9,439      $72,299    $1,008,444     $240,425
                                              =========     ========   ===========    =========

2001      Sales to East System Pool                 $4           $-            $-           $-
          Sales to West System Pool              3,317        8,073        19,865          322
          Direct Sales To East Affiliates        2,833        3,238         3,697        1,228
          Direct Sales To West Affiliates       30,668       67,930        12,617        9,350
          Other                                    (51)          (4)        5,583        7,781
                                              ---------     --------   -----------    ---------
          Total Revenues                       $36,771      $79,237       $41,762      $18,681
                                              =========     ========   ===========    =========
</TABLE>



The following table shows the purchased power expense incurred from
purchases from the pools and affiliates for the years ended December 31,
2003, 2002, and 2001:
<TABLE>
<CAPTION>


                                                           APCo        CSPCo             I&M             KPCo           OPCo
                                                           ----        -----             ---             ----           ----
<C>                                                     <C>          <C>              <C>             <C>             <C>
Related Party Purchases                                                             (in thousands)
2003      Purchases from East System Pool               $348,899     $335,916         $109,826        $71,259         $88,962
          Purchases from West System Pool                     -             -                -              -               -
          Direct Purchases from East Affiliates            1,546          936          164,069         70,249           1,234
          Direct Purchases from West Affiliates              765          471              505            182             625
                                                        ---------    ---------        ---------      ---------        --------
              Total Purchases                           $351,210     $337,323         $274,400       $141,690         $90,821
                                                        =========    =========        =========      =========        ========

2002      Purchases from East System Pool               $233,677     $309,999          $83,918        $68,846         $70,338
          Purchases from West System Pool                    337          219              237             86             297
          Direct Purchases from East Affiliates              583          387          149,569         64,070             519
          Direct Purchases from West Affiliates                -            -                -              -               -
                                                        ---------    ---------        ---------      ---------        --------
              Total Purchases                           $234,597     $310,605         $233,724       $133,002         $71,154
                                                        =========    =========        =========      =========        ========

2001      Purchases from East System Pool               $346,582     $292,034          $79,030        $61,816         $62,350
          Purchases from West System Pool                    296          165              185             72             235
          Direct Purchases from East Affiliates                -            -          159,022         68,316               -
          Direct Purchases from West Affiliates                -            -                -              -               -
                                                        ---------    ---------        ---------      ---------        --------
              Total Purchases                           $346,878     $292,199         $238,237       $130,204         $62,585
                                                        =========    =========        =========      =========        ========


                                                             PSO        SWEPCo            TCC           TNC
                                                             ---        ------            ---           ---
Related Party Purchases                                                             (in thousands)
2003      Purchases from East System Pool                   $639           $-               $-             $-
          Purchases from West System Pool                    704          741              289         15,467
          Direct Purchases from East Affiliates           46,384       28,376           10,238          4,677
          Direct Purchases from West Affiliates           61,912       18,087            8,570         19,265
          Other                                                -          710               -               -
                                                        ---------    ---------        ---------      ---------
              Total Purchases                           $109,639      $47,914          $19,097        $39,409
                                                        =========    =========        =========      =========

2002      Purchases from East System Pool                   $343           $-               $-             $-
          Purchases from West System Pool                    874         (456)           1,366         15,475
          Direct Purchases from East Affiliates           29,029       17,242            8,236          2,669
          Direct Purchases from West Affiliates           59,208       25,236           13,804         19,438
                                                        ---------    ---------        ---------      ---------
              Total Purchases                            $89,454      $42,022          $23,406        $37,582
                                                        =========    =========        =========      =========

2001      Purchases from East System Pool                 $1,327           $-               $-             $4
          Purchases from West System Pool                  5,877        3,810              415         11,689
          Direct Purchases from East Affiliates            1,951        2,352           12,657          4,614
          Direct Purchases from West Affiliates           34,603        9,696           45,569         40,349
                                                        ---------    ---------        ---------      ---------
              Total Purchases                            $43,758      $15,858          $58,641        $56,656
                                                        =========    =========        =========      =========
</TABLE>


The above summarized related party revenues and expenses are reported in
their entirety, without elimination, and are presented as operating
revenues affiliated and purchased power affiliated on the statements of
operations of each AEP Power Pool member. Since all of the above pool
members are included in AEP's consolidated results, the above summarized
related party transactions are eliminated in total in AEP's consolidated
revenues and expenses.

AEP System Transmission Pool
----------------------------

APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission
Agreement, dated April 1, 1984, as amended (the Transmission Agreement),
defining how they share the costs associated with their relative
ownership of the extra-high-voltage transmission system (facilities
rated 345 kV and above) and certain facilities operated at lower
voltages (138 kV and above). Like the Interconnection Agreement, this
sharing is based upon each company's "member-load-ratio."

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


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

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

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

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


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

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

o  The allocation of transmission costs and revenues
o  The allocation of third-party transmission costs and revenues and System
   dispatch costs

The Transmission Integration Agreement anticipates that additional
service schedules may be added as circumstances warrant.

AEP Coal, Inc.
--------------

AEP Coal, Inc. and CSPCo are parties to a 2003 coal purchase agreement,
dated October 15, 2002. The agreement provides for the sale of up to
960,000 tons of coal mined by AEP Coal to be delivered (at CSP's
expense) to the Conesville Plant for a price ranging from $23.15 per ton
to $26.15 per ton plus quality adjustments. In 2002, AEP Coal, Inc. and
CSPCo were parties to a 2002 coal purchase agreement, dated February 1,
2002. The agreement provided for the sale of up to 785,000 tons of coal
mined by AEP Coal to be delivered (at CSP's expense) to the Conesville
Plant for a price ranging from $24.00 per ton to $27.00 per ton plus
quality adjustments. During 2003 and 2002, AEP Coal derived revenues
from sales to CSPCo of $23.9 million and $21 million, respectively.

AEP Coal, Inc. and CSPCo are parties to a 1998 coal transloading
agreement, dated June 12, 1998. Pursuant to the agreement, AEP Coal
transfers coal from railcars into trucks at AEP Coal's Muskie
Transloading Facility and delivers the coal via trucks to CSPCo's
Conesville Preparation Plant or CSPCo's Power Plant for a rate of $1.25
per ton and $1.03 per ton, respectively. During 2003 and 2002, AEP Coal
derived revenues from sales to CSPCo of $3.4 million and $3.5 million,
respectively.

AEP East Companies
------------------

Effective October 31, 2003, AEPES assigned to AEPSC, as agent for the
AEP East operating companies, approximately $97 million (negative value)
associated with its natural gas contracts with DETM. The assignment was
executed in order to consolidate DETM positions within AEP.
Concurrently, in order to ensure that there would be no financial impact
to the operating companies as a result of the assignment, AEPES and
AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any
related cash settlements and all income related to the assigned
contracts. There is no impact to the AEP consolidated financial
statements. The following table represents registrant subsidiary
liabilities at December 31, 2003 in thousands:


        APCo                                             $(32,287)
        CSPCo                                             (18,185)
        I&M                                               (19,932)
        KPCo                                               (7,349)
        OPCo                                              (24,055)
                                                        ----------
        Total                                           $(101,808)
                                                        ==========

Unit Power Agreements and Other
-------------------------------

A unit power agreement between AEGCo and I&M (the I&M Power Agreement)
provides for the sale by AEGCo to I&M of all the power (and the energy
associated therewith) available to AEGCo at the Rockport Plant unless it
is sold to another utility. I&M is obligated, whether or not power is
available from AEGCo, to pay as a demand charge for the right to receive
such power (and as an energy charge for any associated energy taken by
I&M) such amounts, as when added to amounts received by AEGCo from any
other sources, will be at least sufficient to enable AEGCo to pay all
its operating and other expenses, including a rate of return on the
common equity of AEGCo as approved by FERC. The I&M Power Agreement will
continue in effect until the expiration of the lease term of Unit 2 of
the Rockport Plant unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power
agreement between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and
the energy associated therewith) available to AEGCo from both units of
the Rockport Plant. KPCo has agreed to pay to AEGCo in consideration for
the right to receive such power the same amounts which I&M would have
paid AEGCo under the terms of the I&M Power Agreement for such
entitlement. The KPCo unit power agreement expires on December 31, 2004.

APCo and OPCo, jointly own two power plants. The costs of operating
these facilities are apportioned between the owners based on ownership
interests. Each company's share of these costs is included in the
appropriate expense accounts on each company's consolidated statements
of income. Each company's investment in these plants is included in
electric utility plant on its consolidated balance sheets.

I&M provides barging and other transportation services to affiliates.
I&M records revenues from barging services as nonoperating income. The
affiliates record costs paid to I&M for barging services as fuel expense
or operation expense. The amount of affiliated revenues and affiliated
expenses were:

                                              Year Ended December 31,
                                        -------------------------------------
                                        2003           2002              2001
                                        ----           ----              ----
Company                                           (in millions)
I&M - revenues                        $31.9           $34.3              $30.2
AEGCo - expense                         8.1             7.8                8.5
APCo - expense                         12.3            12.8               11.5
KEPCo - expense                         0.1               -                  -
OPCo - expense                          4.3             7.9               10.2
MEMCo - expense (Non-Utility
  subsidiary of AEP)                    7.1             5.7                  -
AEP Energy Services (Non-Utility
  subsidiary of AEP)                      -             0.1                  -

In conjunction with a 500 MW agreement between OPCo and National Power
Cooperative, Inc (NPC), AEPES entered into a fuel management agreement
with those two parties to manage and procure fuel needs for the plant,
which is owned by NPC. The plant went into service in July 2002. Because
APCo, CSPCo, I&M, KPCo and OPCo purchase 100% of the available
generating capacity from the plant, they also share in paying fuel
expense to AEPES. The related purchases from AEPES were as follows:

                           Year Ended December 31,
                        ------------------------------
                        2003                      2002
                        ----                      ----
                                (in thousands)
KPCo                    $363                      $150
I&M                    1,000                       418
CSPCo                    936                       387
OPCo                   1,234                       519
APCo                   1,546                       583
                      -------                   -------
Total                 $5,079                    $2,057
                      =======                   =======

There was no activity in 2001.

HPL purchases physical gas in the spot market, which in turn, is sold to
certain operating companies at cost for their fuel requirements. The
related sales are as follows:

                           Year Ended December 31,
                           -----------------------
                        2003                      2002
                        ----                      ----
                                (in thousands)
TCC                   $195,527                  $157,346
TNC                     44,197                    64,385

There was no activity in 2001.

AEPSC provides certain managerial and professional services to AEP
System companies. The costs of the services are billed to its affiliated
companies by AEPSC on a direct-charge basis, whenever possible, and on
reasonable bases of proration for shared services. The billings for
services are made at cost and include no compensation for the use of
equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation
of the SEC under the PUHCA.


18.  JOINTLY OWNED ELECTRIC UTILITY PLANT
-----------------------------------------


CSPCo, PSO, SWEPCo, TCC and TNC have generating units that are jointly
owned with affiliated and unaffiliated companies. Each of the
participating companies is obligated to pay its share of the costs of
any such jointly owned facilities in the same proportion as its
ownership interest. Each AEP registrant subsidiary's proportionate share
of the operating costs associated with such facilities is included in
its statements of operations and the investments are reflected in its
balance sheets under utility plant as follows:
<TABLE>
<CAPTION>

                                                                                           Company's Share
                                                                 -----------------------------------------------------------------
                                                                                              December 31,
                                                                 -----------------------------------------------------------------
                                                                               2003                             2002
                                                                 --------------------------        -------------------------------
                                               Percent             Utility      Construction        Utility           Construction
                                                 of                Plant           Work              Plant                Work
                                              Ownership           In Service     In Progress        In Service         In Progress
                                              ---------           ----------    ------------        ----------       -------------
                                                                      (in thousands)                       (in thousands)
CSPCo
-----
<C>                                              <C>            <C>               <C>              <C>               <C>
W.C. Beckjord Generating Station
  (Unit No. 6)                                   12.5              $15,455           $127            $15,487             $49
Conesville Generating Station
  (Unit No. 4)                                   43.5               82,115            722             81,960             279
J.M. Stuart Generating Station                   26.0              204,820         50,326            197,276          44,865
Wm. H. Zimmer Generating Station                 25.4              707,281         31,249            705,620          14,077
Transmission                                       (a)              62,061            742             61,187           2,281
                                                                -----------       --------        -----------        --------
Total                                                           $1,071,732        $83,166         $1,061,530         $61,551
                                                                ===========       ========        ===========        ========

PSO
---
Oklaunion Generating Station
  (Unit No. 1)                                   15.6              $85,064           $518            $83,562            $777
                                                                ===========       ========        ===========        ========


SWEPCo
------
Dolet Hills Generating Station
  (Unit No. 1)                                   40.2             $236,116         $2,304           $235,366          $1,313
Flint Creek Generating Station
  (Unit No. 1)                                   50.0               93,309            737             91,567           1,052
Pirkey Generating Station
  (Unit No. 1)                                   85.9              454,303          3,125            451,136           2,197
                                                                -----------       --------        -----------        --------
Total                                                             $783,728         $6,166           $778,069          $4,562
                                                                ===========       ========        ===========        ========

TCC (b)
---
Oklaunion Generating Station
  (Unit No. 1)                                    7.8              $38,798           $252            $38,055            $369
South Texas Project Generation
  Station (Units No. 1 and 2)                    25.2            2,386,579            934          2,364,359          43,887
                                                                -----------       --------        -----------        --------
Total                                                           $2,425,377         $1,186         $2,402,414         $44,256
                                                                ===========       ========        ===========        ========

TNC
---
Oklaunion Generating Station
  (Unit No. 1)                                   54.7             $285,314         $1,351           $277,946          $3,650
                                                                ===========       ========        ===========        ========
</TABLE>




(a) Varying percentages of ownership.
(b) Included in Assets Held for Sale - Texas Generation Plants on TCC's
    Consolidated Balance Sheets.

    The accumulated depreciation with respect to each AEP registrant
    subsidiary's share of jointly owned facilities is shown below:

                                                 December 31,
                                         -------------------------------
                                         2003                       2002
                                         ----                       ----
                                                   (in thousands)
       CSPCo                            $435,249                  $436,683
       PSO                                50,968                    49,085
       SWEPCo                            465,871                   450,057
       TCC (a)                           991,665                   927,193
       TNC                               103,642                   102,542

(a) Included in Assets Held for Sale - Texas Generation Plants on TCC's
    Consolidated Balance Sheets.


19.  UNAUDITED QUARTERLY FINANCIAL INFORMATION
----------------------------------------------


     The unaudited quarterly financial information for each AEP registrant
     subsidiary follows:
<TABLE>
<CAPTION>

     Quarterly Periods Ended                                    AEGCo         APCo           CSPCo           I&M           KPCo
     -----------------------                                    -----         ----           -----           ---           ----
                                                                                         (in thousands)
     <C>                                                      <C>           <C>             <C>           <C>           <C>
     March 31, 2003
     --------------
         Operating Revenues                                    $60,428      $536,228        $359,205      $418,598      $112,094
         Operating Income                                        1,851       112,684          55,151        58,990        19,834
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                1,796        79,153          38,359        30,687        11,021
         Net Income                                              1,796       156,410          65,642        27,527         9,887

     June 30, 2003
     -------------
         Operating Revenues                                    $59,568      $444,751        $333,071      $376,906       $95,464
         Operating Income                                        1,514        49,056          43,417        19,229        10,964
         Income (Loss) Before Extraordinary Items
          and Cumulative Effect of Accounting Changes            1,768        14,636          29,331        (1,191)        4,095
         Net Income (Loss)                                       1,768        14,636          29,331        (1,191)        4,095

     September 30, 2003
     ------------------
         Operating Revenues                                    $59,008      $483,611        $397,655      $423,004      $103,693
         Operating Income                                        1,809        67,134          71,193        56,242        13,097
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                2,021        45,715          62,825        37,116         6,501
         Net Income                                              2,021        45,715          62,825        37,116         6,501

     December 31, 2003
     -----------------
         Operating Revenues                                    $54,161      $492,768        $341,920      $377,088      $105,219
         Operating Income                                        2,000        89,937          55,725        51,606        20,849
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                2,379        63,279          42,632        22,936        11,847
         Net Income                                              2,379        63,279          42,632        22,936        11,847



     Quarterly Periods Ended                                    OPCo          PSO            SWEPCo          TCC           TNC
     -----------------------                                    ----          ---            ------          ---           ---
                                                                                         (in thousands)
     March 31, 2003
     --------------
         Operating Revenues                                   $590,631      $242,662        $255,278      $428,358      $116,262
         Operating Income                                       98,870        13,146          26,044        92,010         9,865
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               68,350           691          10,491        64,437         6,765
         Net Income                                            192,982           691          19,008        64,559         9,836

     June 30, 2003
     -------------
         Operating Revenues                                   $539,386      $277,236        $281,306      $482,446      $136,806
         Operating Income                                       79,831        28,715          35,588        96,603        23,243
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               56,277        17,927          20,590        63,587        17,922
         Net Income                                             56,277        17,927          20,590        63,587        17,922

     September 30, 2003
     ------------------
         Operating Revenues                                   $565,318      $358,575        $361,622      $485,129      $114,455
         Operating Income                                       93,798        43,527          59,229        84,502        17,419
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               70,367        38,090          42,181        66,221        17,347
         Net Income                                             70,367        38,090          42,181        66,221        17,347

     December 31, 2003
     -----------------
         Operating Revenues                                   $549,318      $224,349        $248,636      $351,578       $98,423
         Operating Income                                       87,168         7,475          29,275        48,425        17,500
         Income (Loss) Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               56,037        (2,817)         16,362        23,302        13,629
         Net Income (Loss)                                      56,037        (2,817)         16,362        23,302        13,452


     Quarterly Periods Ended                                    AEGCo         APCo           CSPCo           I&M           KPCo
     -----------------------                                    -----         ----           -----           ---           ----
                                                                                         (in thousands)
     March 31, 2002
     --------------
         Operating Revenues                                    $49,875      $462,605        $314,826      $352,235       $99,185
         Operating Income                                        1,767        81,554          45,548        30,363        15,484
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                1,893        55,341          33,858        11,058        10,246
         Net Income                                              1,893        55,341          33,858        11,058        10,246

     June 30, 2002
     -------------
         Operating Revenues                                    $53,356      $432,015        $343,813      $369,043       $92,164
         Operating Income                                        1,504        65,224          58,040        19,865         9,550
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                1,718        46,608          51,721         7,494         5,246
         Net Income                                              1,718        46,608          51,721         7,494         5,246

     September 30, 2002
     ------------------
         Operating Revenues                                    $55,988      $464,409        $421,892      $414,414       $97,811
         Operating Income                                        1,436        81,365          89,033        57,004        11,119
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes                1,947        53,947          76,117        35,312         5,994
         Net Income                                              1,947        53,947          76,117        35,312         5,994

     December 31, 2002
     -----------------
         Operating Revenues                                    $54,062      $455,441        $319,629      $391,072       $89,523
         Operating Income                                        1,422        73,920          27,158        43,957         6,044
         Income (Loss) Before Extraordinary Items
          and Cumulative Effect of Accounting Changes            1,994        49,596          19,477        20,128          (919)
         Net Income (Loss)                                       1,994        49,596          19,477        20,128          (919)


     Quarterly Periods Ended                                    OPCo          PSO            SWEPCo          TCC           TNC
     -----------------------                                    ----          ---            ------          ---           ---
                                                                                         (in thousands)
     March 31, 2002
     --------------
         Operating Revenues                                   $520,652      $148,986        $222,259      $278,910      $103,626
         Operating Income                                       83,716         8,410          22,469        55,445        11,145
         Income (Loss) Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               64,051        (1,648)          8,159        24,445         3,992
         Net Income (Loss)                                      64,051        (1,648)          8,159        24,445         3,992

     June 30, 2002
     -------------
         Operating Revenues                                   $521,365      $158,330        $263,074      $360,391      $104,452
         Operating Income                                       61,046        20,201          31,988        64,319         5,547
         Income Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               55,348        11,620          18,155        33,535           675
         Net Income                                             55,348        11,620          18,155        33,535           675

     September 30, 2002
     ------------------
         Operating Revenues                                   $557,574      $230,098        $362,423      $546,260      $152,667
         Operating Income (Loss)                                97,210        50,710          60,254       118,204          (308)
         Income (Loss) Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               80,258        41,002          45,794        93,383        (4,193)
         Net Income (Loss)                                      80,258        41,002          45,794        93,383        (4,193)

     December 31, 2002
     -----------------

         Operating Revenues                                   $513,534      $256,233        $236,964      $504,932       $89,995
         Operating Income (Loss)                                56,357         5,400          27,758       155,765        (8,513)
         Income (Loss) Before Extraordinary Items and
          Cumulative Effect of Accounting Changes               20,366        (9,914)         10,884       124,578       (14,151)
         Net Income (Loss)                                      20,366        (9,914)         10,884       124,578       (14,151)

        For each of the AEP registrant subsidiaries, there were no significant,
        non-recurring events in the fourth quarter of 2003 or 2002.
</TABLE>



20.  SUBSEQUENT EVENTS (UNAUDITED)
----------------------------------


After December 31, 2003 we entered into separate agreements to dispose of the
following investments:
<TABLE>
<CAPTION>


Investment                                                     Sales Price              Date of Agreement
----------                                                     -----------              -----------------
                                                              (in millions)
<C>                                                               <C>                    <C>
Oklaunion Power Station (TCC's 7.8%                                $42.8                 January 30, 2004
  ownership interest)

STP (TCC's 25.2% ownership interest)                              $332.6                 February 27, 2004
</TABLE>


We anticipate these sales to be completed during 2004 and that the impact on
results of operations will not be significant.
<PAGE>


        REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
        ----------------------------------------------------------

The following is a combined presentation of certain components of the
registrants' management's discussion and analysis. The information in
this section completes the information necessary for management's
discussion and analysis of financial condition and results of operations
and is meant to be read with (i) Management's Financial Discussion and
Analysis, (ii) financial statements, (iii) footnotes and (iv) the
schedules of each individual registrant.

Source of Funding
-----------------

Short-term funding for AEP's electric subsidiaries comes from AEP's
commercial paper program and revolving credit facilities. Proceeds are
loaned to the subsidiaries through intercompany notes. AEP and its
subsidiaries also operate a money pool to minimize the AEP System's
external short-term funding requirements and sell accounts receivable to
provide liquidity for certain electric subsidiaries. The electric
subsidiaries generally use short-term funding sources (the money pool or
receivables sales) to provide for interim financing of capital
expenditures that exceed internally generated funds and periodically
reduce their outstanding short-term debt through issuances of long-term
debt, sale-leaseback, leasing arrangements and additional capital
contributions from their parent company.

Sale of Receivables Through AEP Credit
--------------------------------------

AEP Credit has a sale of receivables agreement with banks and commercial
paper conduits. Under the sale of receivables agreement, AEP Credit
sells an interest in the receivables it acquires to the commercial paper
conduits and banks and receives cash. This transaction constitutes a
sale of receivables in accordance with SFAS 140, allowing the
receivables to be removed from of AEP Credit's balance sheet and
allowing AEP Credit to repay any debt obligations. AEP has no ownership
interest in the commercial paper conduits and does not consolidate these
entities in accordance with GAAP. The electric subsidiaries continue to
service the receivables. This off-balance sheet transaction was entered
into to allow AEP Credit to repay its outstanding debt obligations,
continue to purchase the AEP operating companies' receivables, and
accelerate its cash collections.

AEP Credit extended its sale of receivables agreement to July 25, 2003
from its May 28, 2003 expiration date. The agreement was then renewed
for an additional 364 days and now expires on July 23, 2004. This new
agreement provides commitments of $600 million to purchase receivables
from AEP Credit. At December 31, 2003, $385 million was outstanding. As
collections from receivables sold occur and are remitted, the
outstanding balance for sold receivables is reduced and as new
receivables are sold, the outstanding balance of sold receivables
increases. All of the receivables sold represented affiliate
receivables. AEP Credit maintains a retained interest in the receivables
sold and this interest is pledged as collateral for the collection of
the receivables sold. The fair value of the retained interest is based
on book value due to the short-term nature of the accounts receivable
less an allowance for anticipated uncollectible accounts.

AEP Credit purchases accounts receivable through purchase agreements
with certain registrant subsidiaries. These subsidiaries include CSPCo,
I&M, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not
have regulatory authority to sell accounts receivable in all of its
regulatory jurisdictions, only a portion of APCo's accounts receivable
are sold to AEP Credit. In addition, the purchase agreements between AEP
Credit and TCC and TNC were terminated effective March 20, 2002.

Budgeted Construction Expenditures
----------------------------------

Construction expenditures for certain registrant subsidiaries for the next
three years are:

                                    Projected                 Construction
                                   Construction           Expenditures Financed
                                   Expenditures            With Internal Funds
                                   ------------           ---------------------
                                              (in millions)
              APCo                    $1,307                      70%
              I&M                        645                     100
              OPCo                     1,686                      60
              SWEPCo                     414                     100
              TCC                        531                     100

Significant Factors
-------------------

Possible Divestitures
---------------------

AEP's management is firmly committed to continually evaluating the need
to reallocate resources to areas that effectively match investments with
our business strategy, providing the greatest potential for financial
returns and to disposing of investments that no longer meet these goals.

TCC is seeking to divest significant components of its non-regulated
domestic generation assets. In June 2003, TCC began actively seeking
buyers for 4,497 megawatts of its generating capacity in Texas. The
value received from this disposition will also be used to calculate
stranded costs in Texas (see Note 6). Management is currently evaluating
bids received during the fourth quarter of 2003 and is in negotiations
to sell these assets. See Note 10 for discussion of impairments recorded
related to the generating units in Texas. The ultimate sale of these
assets may have a material impact on results of operations, cash flows
and financial condition if losses are not recovered through the 2004
true-up proceeding in Texas.

Management continues to have periodic discussions with various parties
on business alternatives for certain other investments. The ultimate
timing for a disposition of one or more of these assets will depend upon
market conditions and the value of any buyer's proposal.

Corporate Separation
--------------------

In compliance with certain provisions in the Texas and Ohio
restructuring laws, AEP filed in 2001 for regulatory approvals related
to efforts at that time to separate regulated and unregulated
operations, and amend certain affiliate pooling arrangements. Although
certain regulatory approvals have been obtained, with the changes in the
regulatory environment and AEP's business strategy, management continues
to evaluate corporate separation plans.

In Texas, TCC is in the process of divesting its generating assets in
accordance with provisions of the Texas Legislation concerning stranded
cost recovery (see Note 6). In order to sell these assets, TCC
anticipates retiring first mortgage bonds by making open market
purchases or defeasing the bonds. Once such generating assets are sold,
which management expect to be finalized in 2004, TCC will effectively
accomplish the structural separation requirements of the Texas
Legislation for those assets.

In Ohio, the PUCO has encouraged utilities to file rate stabilization
plans to provide rate certainty and stability for customers who do not
choose alternative suppliers, for the period of January 1, 2006 through
December 31, 2008, which is after the expiration of the current market
development period. On February 9, 2004, CSPCo and OPCo filed such a
rate stabilization plan with the PUCO. The plan, in part, provides that
both CSPCo and OPCo will remain functionally separated. Approval of the
rate stabilization plan is currently pending before the PUCO.

Unless otherwise directed by the PUCO in an order on the rate
stabilization plan, CSPCo and OPCo will remain functionally separated
through at least the end of the rate stabilization plan period, December
31, 2008, and therefore, are not planning to legally separate, or to
change the affiliate pooling agreement for the AEP East companies, in
the foreseeable future.

Management continues to evaluate the most appropriate approach for
complying with the Texas Legislation's structural separation
requirements for TNC, including appropriate regulatory approvals to
implement its structural separation.

RTO Formation
-------------

The FERC's AEP-CSW merger approval and many of the settlement agreements
with the state regulatory commissions to approve the AEP-CSW merger
required the transfer of functional control of our subsidiaries'
transmission systems to RTOs. Further, legislation in some of AEP's
states requires RTO participation.

In May 2002, AEP announced an agreement with PJM to pursue terms for
participation in its RTO for AEP East companies with final agreements to
be negotiated. In July 2002, FERC issued an order accepting our decision
to participate in PJM, subject to specified conditions. AEP and other
parties continue to work on the resolution of those conditions.

In December 2002, AEP's subsidiaries that operate in the states of
Indiana, Kentucky, Ohio and Virginia filed for state regulatory
commission approval of their plans to transfer functional control of
their transmission assets to PJM. Proceedings in Ohio remain pending.

In February 2003, the state of Virginia enacted legislation preventing
APCo from joining an RTO prior to July 1, 2004 and thereafter only with
the approval of the Virginia SCC, but required such transfers by January
1, 2005. In January 2004, APCo filed a cost/benefit study with the
Virginia SCC covering the time period through 2014 as required by the
Virginia SCC. The study results show a net benefit of approximately $98
million for APCo over the 11-year study period from AEP's participation
in PJM.

In July 2003, the KPSC denied KPCo's request to join PJM based in part
on a lack of evidence that it would benefit Kentucky retail customers.
In December 2003, AEP filed with the KPSC a cost/benefit study showing a
net benefit of approximately $13 million for KPCo over the five-year
study period from AEP's participation in PJM. A hearing has been
scheduled in April 2004.

In September 2003, the IURC issued an order approving I&M's transfer of
functional control over its transmission facilities to PJM, subject to
certain conditions included in the order. The IURC's order stated that
AEP shall request and the IURC shall complete a review of Alliance
formation costs before any deferral of the costs for future recovery.

In April 2003, FERC approved our transfer of functional control of the
AEP East companies' transmission system to PJM. FERC also accepted our
proposed rates for joining PJM, but set a number of rate issues for
resolution through settlement proceedings or FERC hearings. Settlement
discussions continue on certain rate matters.

On September 29 and 30, 2003, the FERC held a public inquiry regarding
RTO formation, including delays in AEP's participation in PJM. In
November 2003, the FERC issued an order preliminarily finding that AEP
must fulfill its CSW merger commitment to join an RTO by fully
integrating into PJM (transmission and markets) by October 1, 2004. The
FERC set several issues for public hearing before an ALJ. Those issues
include whether the laws, rules, or regulations of Virginia and Kentucky
are preventing AEP from joining an RTO and whether the states'
provisions meet either of the two exceptions under PURPA. The FERC
directed the ALJ to issue his initial decision by March 15, 2004.

If AEP East companies do not obtain regulatory approval to join PJM,
they are committed to reimburse PJM for certain project implementation
costs (presently estimated at $24 million for AEP's share of the entire
PJM integration project). These costs, if incurred, will be allocated to
the AEP East companies. AEP East companies also plan to seek recovery of
deferred RTO formation/integration costs in the future. At December 31,
2003, the deferred amounts per company are as follows:

                    Company                      (in millions)
                    APCo                             $7.8
                    CSPCo                             3.3
                    I&M                               6.0
                    KPCo                              1.8
                    OPCo                              8.6

See Note 4 for further discussion.

AEP West companies are members of ERCOT or SPP. In 2002, FERC
conditionally accepted filings related to a proposed consolidation of
MISO and SPP. State public utility commissions also regulate AEP's SPP
companies. The Louisiana and Arkansas commissions filed responses to the
FERC's RTO order indicating that additional analysis was required.
Subsequently, the proposed SPP/MISO combination was terminated. On
October 15, 2003, SPP filed a proposal at the FERC for recognition as an
RTO. In February 2004, the FERC granted RTO status to the SPP, subject
to fulfilling specified requirements. Regulatory activities concerning
various RTO issues are ongoing in Arkansas and Louisiana.

Management is unable to predict the outcome of these regulatory actions
and proceedings or their impact on transmission operations, results of
operations and cash flows or the timing and operation of RTOs.

Pension Plans
-------------

AEP maintains qualified defined benefit pension plans (Qualified Plans),
which cover a substantial majority of non-union and certain union
associates, and unfunded excess plans to provide benefits in excess of
amounts permitted to be paid under the provisions of the tax law to
participants in the Qualified Plans. Additionally, AEP has entered into
individual retirement agreements with certain current and retired
executives that provide additional retirement benefits.

AEP's net periodic pension expense was an income item for all pension
plans approximating $3 million and $44 million for the years ended
December 31, 2003 and 2002, respectively, and is calculated based upon a
number of actuarial assumptions, including an expected long-term rate of
return on the Qualified Plans' assets. In 2002 and 2003, the long-term
return was assumed to be 9.00%, and for 2004, the long-term rate of
return was lowered to 8.75%. In developing the expected long-term rate
of return assumption, AEP evaluated input from actuaries and investment
consultants, including their reviews of asset class return expectations
as well as long-term inflation assumptions. Projected returns by such
actuaries and consultants are based on broad equity and bond indices.
AEP also considered historical returns of the investment markets as well
as the 10-year average return, for the period ended December 2003, of
approximately 10.0%. AEP anticipates that the investment managers it
employs for the pension fund will continue to generate long-term returns
of at least 8.75%.

The expected long-term rate of return on the Qualified Plan's assets is
based on AEP's targeted asset allocation and expected investment returns
for each investment category. AEP's assumptions are summarized in the
following table:
<TABLE>
<CAPTION>
                                                      2003                  2004             Assumed/Expected
                                                     Actual                Target             Long-term Rate
                                                Asset Allocation      Asset Allocation           of Return
                                                ----------------      ----------------       ----------------
                                                                      (in percentage)
<C>                                                      <C>                  <C>                   <C>
Equity                                                    71                   70                    10.5
Fixed Income                                              27                   28                       5
Cash and Cash Equivalents                                  2                    2                       2
                                                         ----                 ----
Total                                                    100                  100
                                                         ====                 ====

Overall Expected Return (weighted average)                                                            8.75
                                                                                                      =====
</TABLE>


AEP regularly reviews the actual asset allocation and periodically
rebalances the investments to its targeted allocation when considered
appropriate. AEP believes that 8.75% is a reasonable long-term rate of
return on the Qualified Plans' assets despite the recent market
volatility in which the Qualified Plans' assets had a loss of 11.2% for
the twelve months ended December 31, 2002, and a gain of 23.8% for the
twelve months ended December 31, 2003. AEP will continue to evaluate the
actuarial assumptions, including the expected rate of return, at least
annually, and will adjust them as necessary.

AEP bases its determination of pension expense or income on a
market-related valuation of assets which reduces year-to-year
volatility. This market-related valuation recognizes investment gains or
losses over a five-year period from the year in which they occur.
Investment gains or losses for this purpose are the difference between
the expected return calculated using the market-related value of assets
and the actual return based on the market-related value of assets. Since
the market-related value of assets recognizes gains or losses over a
five-year period, the future value of assets will be impacted as
previously deferred gains or losses are recorded. As of December 31,
2003, AEP has cumulative losses of approximately $325 million which
remain to be recognized in the calculation of the market-related value
of assets. These unrecognized net actuarial losses result in increases
in the future pension costs depending on several factors, including
whether such losses at each measurement date exceed the corridor in
accordance with SFAS No. 87, "Employers' Accounting for Pensions."

The discount rate that AEP utilizes for determining future pension
obligations is based on a review of long-term bonds that receive one of
the two highest ratings given by a recognized rating agency. The
discount rate determined on this basis has decreased from 6.75% at
December 31, 2002, to 6.25% at December 31, 2003. Due to the effect of
the unrecognized actuarial losses and based on an expected rate of
return on the Qualified Plans' assets of 8.75%, a discount rate of 6.25%
and various other assumptions, AEP estimates that the pension expense
for all pension plans will approximate $41 million, $78 million and $103
million in 2004, 2005 and 2006, respectively. Future actual pension cost
will depend on future investment performance, changes in future discount
rates and various other factors related to the populations participating
in the pension plans.

Lowering the expected long-term rate of return on the Qualified Plans'
assets by 0.5% (from 9.0% to 8.5%) would have increased pension cost for
2003 by approximately $18 million (income of $3 million would have
become $15 million in pension expense). Lowering the discount rate by
0.5% would have reduced pension income for 2003 by approximately $0.5
million.

The value of the Qualified Plans' assets has increased from $2.795
billion at December 31, 2002 to $3.180 billion at December 31, 2003. The
Qualified Plans paid out $292 million in benefits to plan participants
during 2003 (the nonqualified plans paid out $7 million in benefits).
AEP's pension plans remain in an underfunded position (plan assets are
less than projected benefit obligations) of $508 million at December 31,
2003. Due to the pension plans currently being underfunded, AEP recorded
a charge to Other Comprehensive Income (OCI) of $585 million in 2002,
and recorded a Deferred Income Tax Asset of $315 million, offset by a
Minimum Pension Liability of $662 million and a reduction to prepaid
costs and adjustment for unrecognized costs of $238 million. In 2003,
the income recorded in OCI was $154 million, and the reduction in the
Deferred Income Tax Asset was $76 million, offset by a reduction in
Minimum Pension Liability of $234 million and a reduction to adjustment
for unrecognized costs of $4 million. The charge to OCI does not affect
earnings or cash flow. AEP's plans are in compliance with the laws and
regulations governing such plans including the Employee Retirement
Income Security Act of 1974, as amended. Due to the current underfunded
status of the Qualified Plans, AEP expects to make cash contributions to
the pension plans of approximately $41 million in 2004.

Certain of the defined benefit pension plans AEP sponsors and maintains
contain a cash balance benefit feature. In recent years, cash balance
benefit features have become a focus of scrutiny, as government
regulators and courts consider how the Employee Retirement Income
Security Act of 1974, as amended, the Age Discrimination in Employment
Act, as amended, and other relevant federal employment laws apply to
plans with such a cash balance plan feature. AEP believes that the
defined benefit pension plans it sponsors and maintains are in
substantial compliance with the applicable requirements of such laws.

See Note 11 of the Notes to Respective Financial Statements for
additional information related to the impact of pension plans on
individual AEP registrant subsidiaries.

Nuclear Plant Outages
---------------------

In April 2003, engineers at STP, during inspections conducted regularly
as part of refueling outages, found wall cracks in two bottom mounted
instrument guide tubes of STP Unit 1. These tubes were repaired and the
unit returned to service in August 2003. TCC's share of the cost of
repair for this outage was approximately $6 million. TCC had commitments
to provide power to customers during the outage. Therefore, TCC was
subject to fluctuations in the market prices of electricity and
purchased replacement energy.

In April 2003, both units of Cook Plant were taken offline due to an
influx of fish in the plant's cooling water system which caused a
reduction in cooling water to essential plant equipment. After repair of
damage caused by the fish intrusion, Cook Plant Unit 1 returned to
service in May and Unit 2 returned to service in June following
completion of a scheduled refueling outage.

Litigation
----------

Federal EPA Complaint and Notice of Violation
---------------------------------------------

See discussion of New Source Review Litigation under "Environmental Matters".

Enron Bankruptcy
----------------

On October 15, 2002, certain subsidiaries of AEP filed claims against
Enron and its subsidiaries in the bankruptcy proceeding filed by the
Enron entities which are pending in the U.S. Bankruptcy Court for the
Southern District of New York. At the date of Enron's bankruptcy,
certain subsidiaries of AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1,
2001, AEP purchased Houston Pipe Line Company (HPL) from Enron. Various
HPL related contingencies and indemnities from Enron remained unsettled
at the date of Enron's bankruptcy. The timing of the resolution of the
claims by the Bankruptcy Court is not certain.

In 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 will assert its right to offset
trading payables owed to various Enron entities against trading
receivables due to several AEP subsidiaries. Management is unable to
predict the outcome of this lawsuit or its impact on results of
operations, cash flows or financial condition.

In December 2003, Enron filed a complaint in the Bankruptcy Court
against AEPSC seeking approximately $93 million plus interest in
connection with a transaction for the sale and purchase of physical
power among Enron, AEP and Allegheny Energy Supply, LLC during November
2001. Enron's claim seeks to unwind the effects of the transaction. AEP
believes it has several defenses to the claims in the action being
brought by Enron. Management is unable to predict the outcome of this
lawsuit or its impact on results of operations, cash flows or financial
condition.

During 2002 and 2001, AEP subsidiaries expensed a total of $53 million
($34 million net of tax) for their estimated loss from the Enron
bankruptcy. The amounts for certain subsidiaries were:

                                                        Amounts
                                    Amounts             Net of
   Registrant                      Expensed               Tax
                                   --------             -------
                                        (in millions)

   APCo                              $5.3                $3.4
   CSPCo                              2.7                 1.8
   I&M                                2.8                 1.8
   KPCo                               1.1                 0.7
   OPCo                               3.6                 2.3

The amounts expensed were based on an analysis of contracts where AEP
and Enron entities are counterparties, the offsetting of receivables and
payables, the application of deposits from Enron entities and
management's analysis of the HPL related purchase contingencies and
indemnifications. As noted above, Enron has challenged the offsetting of
receivables and payables. 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.

Energy Market Investigations
----------------------------

AEP and other energy market participants received data requests,
subpoenas and requests for information from the FERC, the SEC, the PUCT,
the U.S. Commodity Futures Trading Commission (CFTC), the U.S.
Department of Justice and the California attorney general during 2002.
Management responded to the inquiries and provided the requested
information and has continued to respond to supplemental data requests
in 2003 and 2004.

In March 2003, AEP received a subpoena from the SEC as part of the SEC's
ongoing investigation of energy trading activities. In August 2002, AEP
received an informal data request from the SEC seeking that AEP
voluntarily provide information. The subpoena sought additional
information and is part of the SEC's formal investigation. AEP responded
to the subpoena and will continue to cooperate with the SEC.

On September 30, 2003, the CFTC filed a complaint against AEP and AEPES
in federal district court in Columbus, Ohio. The CFTC alleges that AEP
and AEPES provided false or misleading information about market
conditions and prices of natural gas in an attempt to manipulate the
price of natural gas in violation of the Commodity Exchange Act. The
CFTC seeks civil penalties, restitution and disgorgement of benefits.
The case is in the initial pleading stage with our response to the
complaint currently due on May 18, 2004. Although management is unable
to predict the outcome of this case, AEP recorded a provision in 2003
and the action is not expected to have a material effect on results of
operations.

In January 2004, the CFTC issued a request for documents and other
information in connection with a CFTC investigation of activities
affecting the price of natural gas in the fall of 2003. AEP is
responding to that request.

Management cannot predict what, if any further action, any of these
governmental agencies may take with respect to these matters.

TEM Litigation
--------------

See discussion of TEM litigation within OPCo's Management's Financial
Discussion and Analysis.

Texas Commercial Energy, LLP Lawsuit
------------------------------------

Texas Commercial Energy, LLP (TCE), a Texas REP, filed a lawsuit against
AEP and four of its subsidiaries including TCC and TNC, certain
unaffiliated energy companies and ERCOT alleging violations of the
Sherman Antitrust Act, fraud, negligent misrepresentation, breach of
fiduciary duty, breach of contract, civil conspiracy and negligence. The
allegations, not all of which are made against the AEP companies, range
from anticompetitive bidding to withholding power. TCE alleges that
these activities resulted in price spikes requiring TCE to post
additional collateral and ultimately forced it into bankruptcy when it
was unable to raise prices to its customers due to fixed price
contracts. The suit alleges over $500 million in damages for all
defendants and seeks recovery of damages, exemplary damages and court
costs. Management believes that the claims against AEP and its
subsidiaries are without merit. Management intends to vigorously defend
against the claims. See Note 7 for further discussion.

COLI Litigation
---------------

A decision by the U.S. District Court for the Southern District of Ohio
in February 2001 that denied AEP's deduction of interest claimed on
AEP's consolidated federal income tax returns related to a COLI program
resulted in a $319 million reduction in AEP's Net Income for 2000.

The earnings reductions for affected registrant subsidiaries were as follows:

                               (in millions)
   APCo                             $82
   CSPCo                             41
   I&M                               66
   KPCo                               8
   OPCo                             118

AEP filed an appeal of the U.S. District Court's decision with the U.S.
Court of Appeals for the 6th Circuit. In April 2003, the Appeals Court
ruled against AEP. The U.S. Supreme Court has declined to hear this
issue.

Other Litigation
----------------

AEP subsidiaries are involved in a number of other legal proceedings and
claims. While management is unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of these
matters will have a material adverse effect on results of operations,
cash flows or financial condition.

Potential Uninsured Losses
--------------------------

Some potential losses or liabilities may not be insurable or the amount
of insurance carried may not be sufficient to meet potential losses and
liabilities, including, but not limited to, liabilities relating to
damage to the Cook Plant or STP and costs of replacement power in the
event of a nuclear incident at the Cook Plant or STP. Future losses or
liabilities which are not completely insured, unless recovered from
customers, could have a material adverse effect on results of
operations, cash flows and financial condition.

Environmental Matters
---------------------

There are new environmental control requirements that management expects
will result in substantial capital investments and operational costs.
The sources of these future requirements include:

  o  Legislative and regulatory proposals to adopt stringent
     controls on sulfur dioxide (SO2), nitrogen oxide (NOx) and
     mercury emissions from coal-fired power plants,
  o  New Clean Water Act rules to reduce the impacts of water intake
     structures on aquatic species at certain of our power plants, and
  o  Possible future requirements to reduce carbon dioxide emissions
     to address concerns about global climatic change.

In addition to achieving full compliance with all applicable legal
requirements, AEP subsidiaries strive to go beyond compliance in an
effort to be good environmental stewards. For example, AEP subsidiaries
invest in research, through groups like the Electric Power Research
Institute, to develop, implement and demonstrate new emission control
technologies. AEP subsidiaries plan to continue in a leadership role to
protect and preserve the environment while providing vital energy
commodities and services to customers at fair prices. AEP subsidiaries
have a proven record of efficiently producing and delivering electricity
while minimizing the impact on the environment. The AEP System has
invested over $2 billion, from 1990 through 2003, to equip many of its
facilities with pollution control technologies. The AEP System will
continue to make investments to improve the air emissions from its
generating stations because this is the most cost-effective generation
source for its customers electricity needs.

The Current Air Quality Regulatory Framework
--------------------------------------------

The Clean Air Act (CAA) is the legislation that establishes the federal
regulatory authority and oversight for emissions from fossil-fired
generating plants. The states, with oversight and approval from the
Federal EPA, administer and enforce these laws and related regulations.

Title I of the CAA
------------------

National Ambient Air Quality Standards: The Federal EPA periodically
---------------------------------------
reviews the available scientific data for six pollutants and establishes
a standard for concentration levels in ambient air for these substances
to protect the public welfare and public health with an extra margin for
safety. These requirements are known as "national ambient air quality
standards" (NAAQS).

The states identify those areas within their state that meet the NAAQS
(attainment areas) and those that do not (non-attainment areas). States
must develop their individual state implementation plans (SIPs) with the
intention of bringing non-attainment areas into compliance with the
NAAQS. In developing a SIP each state must allow attainment areas to
maintain compliance with the NAAQS. This is accomplished by controlling
sources that emit one or more pollutants or precursors to those
pollutants. The Federal EPA approves SIPs if they meet the minimum
criteria in the CAA. Alternatively, the Federal EPA may prescribe a
federal implementation plan if they conclude that a SIP is deficient.
Additionally, the Federal EPA can impose sanctions, up to and including
withholding of federal highway funds, in states that fail to submit an
adequate SIP or a SIP that fails to bring non-attainment areas into
NAAQS compliance within the time prescribed by the CAA.

The CAA also establishes visibility goals, which are known as the
regional haze program, for certain federally designated areas, including
national parks. States are required to develop and submit SIP provisions
that will demonstrate reasonable progress toward preventing the
impairment and remedying any existing impairment of visibility in these
federally designated areas.

Each state's SIP must include requirements to control sources that emit
pollutants in that state as well as requirements to control sources that
significantly contribute to non-attainment areas in another state. If a
state believes that its air quality is impacted by upwind sources
outside their borders, that state can submit a petition that asks the
Federal EPA to impose control requirements on specific sources in other
states if those states' SIPs do not contain adequate requirements to
control those sources. For example, the Federal EPA issued a NOx Rule in
1997, which affected 22 eastern states (including states in which AEP
subsidiaries operate) and the District of Columbia. The NOx Rule asked
these 23 jurisdictions to adopt requirements, for utility and industrial
boilers and certain other emission sources, to employ cost-effective
control technologies to reduce NOx emissions. The purpose of the request
was to allow certain eastern states to reduce the contribution from
these 23 jurisdictions to ozone non-attainment areas in certain eastern
states.

The Federal EPA also granted four petitions filed by certain eastern
states seeking essentially the same levels of control on emission
sources outside of their states and issued a Section 126 Rule. All of
the states in which we operate that were subject to the NOx Rule have
submitted the required SIP revisions. In response, the Federal EPA
issued the NOx Rule and the Section 126 Rule, which are discussed below.

The compliance date for the NOx Rule is May 31, 2004. In 2000, the
Federal EPA also adopted a revised Section 126 Rule which granted
petitions filed by four northeastern states. The revised Section 126
Rule imposes emissions reduction requirements comparable to the NOx Rule
also beginning May 31, 2004, for most of our coal-fired generating
units.

In 2000, the Texas Commission on Environmental Quality adopted rules
requiring significant reductions in NOx emissions from utility sources,
including TCC and SWEPCo. The compliance requirements began in May 2003
for TCC and begin in May 2005 for SWEPCo.

AEP subsidiaries are installing a variety of emission control
technologies to improve NOx emissions standards and to comply with
applicable state and federal NOx requirements. These include selective
catalytic reduction (SCR) technology on certain units and other
combustion control technologies on a larger number of units.

AEP's electric utility units are currently subject to SIP requirements
that control SO2 and particulate matter emissions in all states, and
that control NOx emissions in certain states. The AEP System's
generating plants comply with applicable SIP limits for SO2, NOx and
particulate matter.

Hazardous Air Pollutants: In 1990 Amendments to the CAA, Congress
-------------------------
required the Federal EPA to identify the sources of 188 hazardous air
pollutants (HAPs) and to develop regulations that prescribe a level of
HAP emission reduction. These reductions must reflect the application of
maximum achievable control technology (MACT). Congress also directed the
Federal EPA to investigate HAP emissions from the electric utility
sector and to submit a report to Congress. The Federal EPA's 1998 report
to Congress identified mercury emissions from coal-fired electric
utility units and nickel emissions from oil-fired utility units as
sources of HAP emissions that warranted further investigation and
possible control.

New Source Performance Standards and New Source Review: The Federal EPA
-------------------------------------------------------
establishes New Source Performance Standards (NSPS) for 28 categories of
major stationary emission sources that reflect the best demonstrated
level of pollution control. Sources that are constructed or modified
after the effective date of an NSPS standard are required to meet those
limitations. For example, many electric utility units are regulated
under the NSPS for SO2, NOx, and particulate matter. Similarly, each SIP
must include regulations that require new sources, and major
modifications at existing emission sources that result in a significant
net increase in emissions, to submit a permit application and undergo a
review of available technologies to control emissions of pollutants.
These rules are called new source review (NSR) requirements.

Different NSR requirements apply in attainment and non-attainment areas.

In attainment areas:
  o  An air quality review must be performed, and
  o  The best available control technology must be employed to reduce new
     emissions.

In non-attainment areas,
  o  Requirements reflecting the lowest achievable emission rate are applied to
     new or modified sources, and
  o  All new emissions must be offset by reductions in
     emissions of the same pollutant from other sources within the same
     control area.

Neither the NSPS nor NSR requirements apply to certain activities,
including routine maintenance, repair or replacement, changes in fuels
or raw materials that a source is capable of accommodating, the
installation of a pollution control project, and other specifically
excluded activities.

Title IV of the CAA (Acid Rain)
-------------------------------

The 1990 Amendments to the CAA included a market-based emission
reduction program designed to reduce the amount of SO2 emitted from
electric utility units by approximately 50 percent from 1980 levels.
This program also established a nationwide cap on utility SO2 emissions
of 8.9 million tons per year. The Federal EPA administers its SO2
program through an allowance allocation and trading system. Allowances
are allocated to specific units based on statutory formulas. Annually
each utility unit must surrender one allowance for each ton of SO2 that
it emits. Emission sources that install controls and no longer need all
of their allowances can bank those allowances for future use or trade
them to other emission sources.

Title IV also contains requirements for utility sources to reduce NOx
emissions through the use of available combustion controls. Units must
meet NOx emission rates standards which are specific to that unit or
units may participate in an annual averaging program for utility units
that are under common control.

Future Reduction Requirements for SO2, NOx, and Mercury
-------------------------------------------------------

In 1997, the Federal EPA adopted new, more stringent NAAQS for fine
particulate matter and ground-level ozone. The Federal EPA is in the
process of developing final designations for fine particulate matter and
ground-level ozone non-attainment areas. The Federal EPA has identified
SO2 and NOx emissions as precursors to the formation of fine particulate
matter. NOx emissions are also identified as a precursor to the
formation of ground-level ozone. As a result, requirements for future
reductions in emissions of NOx and SO2 from the AEP System's generating
units are highly probable. In addition, the Federal EPA has proposed a
set of options for future mercury controls at coal-fired power plants.

Multi-emission control legislation, known as the Clear Skies Act, was
introduced in Congress and is supported by the Bush Administration. This
legislation would regulate NOx, SO2, and mercury emissions from electric
generating plants. AEP supports enactment of this comprehensive,
multi-emission legislation so that compliance planning can be
coordinated and collateral emission reductions maximized. Management
believes the Bush Administration's Clear Skies Act would establish
stringent emission reduction targets and achievable compliance
timetables utilizing a cost-effective nationwide cap and trade program.
Although the prospects for enactment of the Clear Skies Act are low,
there are alternative regulatory approaches which will likely require
the AEP System to substantially reduce SO2, NOx and mercury emissions
over the next ten years.

Regulatory Emissions Reductions
-------------------------------

On January 30, 2004, the Federal EPA published two proposed rules that
would collectively require reductions of approximately 70% in emissions
of SO2, NOx and mercury from coal-fired electric generating units by
2015 (2018 for mercury). This initiative has two major components:

  o  The Federal EPA proposed an interstate air quality rule for
     reducing SO2 and NOx emissions across the eastern half of the
     United States (29 states and the District of Columbia) to
     address attainment of the fine particulate matter and
     ground-level ozone NAAQS. These reductions could also satisfy
     these states' obligations to make reasonable progress towards
     the national visibility goal under the regional haze program.
  o  The Federal EPA proposed to regulate mercury emissions from coal-fired
     electric generating units.

 The interstate air quality rule would require affected states to
 include, in their SIPs, a program to reduce NOx and SO2 emissions from
 coal-fired electric utility units. SO2 and NOx emissions would be
 reduced in two phases, which would be implemented through a
 cap-and-trade program. Regional SO2 emissions would be reduced to 3.9
 million tons by 2010 and to 2.7 million tons by 2015. Regional NOx
 emissions would be reduced to 1.6 million tons by 2010 and to 1.3
 million tons by 2015. Rules to implement the SO2 and NOx trading
 programs have not yet been proposed.

 To control and reduce mercury emissions, the Federal EPA published two
 alternative proposals. The first option requires the installation of
 MACT on a site-specific basis. Mercury emissions would be reduced from
 48 tons to approximately 34 tons by 2008. The Federal EPA believes, and
 the industry concurs, that there are no commercially available mercury
 control technologies in the marketplace today that can achieve the MACT
 standards for bituminous coals, but certain units have achieved
 comparable levels of mercury reduction by installing conventional SO2
 (scrubbers) and NOx (SCR) emission reduction technologies. The proposed
 rule imposes significantly less stringent standards on generating plants
 that burn sub-bituminous coal or lignite, which standards potentially
 could be met without installation of mercury control technologies.

 The Federal EPA recommends, and AEP supports, a second mercury emission
 reduction option. The second option would permit mercury emission
 reductions to be achieved from existing sources through a national
 cap-and-trade approach. The cap-and-trade approach would include a
 two-phase mercury reduction program for coal-fired utilities. This
 approach would coordinate the reduction requirements for mercury with
 the SO2 and NOx reduction requirements imposed on the same sources under
 the proposed interstate air quality rule. Coordination is significantly
 more cost-effective because technologies like scrubbers and SCRs, that
 can be used to comply with the more stringent SO2 and NOx requirements,
 have also proven highly effective in reducing mercury emissions on
 certain coal-fired units that burn bituminous coal. The second option
 contemplates reducing mercury emissions from 48 million tons to 34
 million tons by 2010 and to 15 million tons by 2018.

 The Federal EPA's proposals are the beginning of a lengthy rulemaking
 process, which will involve supplemental proposals on many details of
 the new regulatory programs, written comments and public hearings,
 issuance of final rules, and potential litigation. In addition, states
 have substantial discretion in developing their rules to implement
 cap-and-trade programs, and will have 18 months after publication of the
 notice of final rulemaking to submit their revised SIPs. As a result,
 the ultimate requirements may not be known for several years and may
 depart significantly from the original proposed rules described here.

 While uncertainty remains as to whether future emission reduction
 requirements will result from new legislation or regulation, it is
 certain under either outcome that AEP subsidiaries will invest in
 additional conventional pollution control technology on a major portion
 of their coal-fired power plants. Finalization of new requirements for
 further SO2, NOx and/or mercury emission reductions will result in the
 installation of additional scrubbers, SCR systems and/or the
 installation of emerging technologies for mercury control.

 Estimated Air Quality Environmental Investments
 -----------------------------------------------

 Each of the current and possible future environmental compliance
 requirements discussed above will require significant additional
 investments, some of which are estimable. The proposed rules discussed
 above have not been adopted, will be subject to further revision, and
 will be the subject of a court challenge and further modifications.

 All of management's estimates are subject to significant uncertainties
 about the outcome of several interrelated assumptions and variables,
 including:

  o  Timing of implementation
  o  Required levels of reductions
  o  Allocation requirements of the new rules, and
  o  Selected compliance alternatives.

As a result, management cannot estimate compliance costs with certainty,
and the actual costs to comply could differ significantly from the
estimates discussed below.

All of the costs discussed below are incremental to the AEP
subsidiaries' current investment base and operating cost structure.
These expenditures for pollution control technologies, replacement
generation and associated operating costs are recoverable from customers
through regulated rates (in regulated jurisdictions) and should be
recoverable through market prices (in deregulated jurisdictions). If
not, those costs could adversely affect future results of operations,
cash flows and possibly financial condition.

Estimated Investments for NOx Compliance
----------------------------------------

Management estimates that AEP subsidiaries will make future investments
of approximately $600 million to comply with the Federal EPA's NOx Rule,
the Texas Commission on Environmental Quality Rule and other final
Federal EPA NOx-related requirements. Approximately $500 million of
these investments are reflected in the estimated construction
expenditures for 2004 - 2006. As of December 31, 2003, the AEP System
has invested approximately $1.1 billion to comply with various NOx
requirements. Estimated future compliance costs, amounts in the 2004 -
2006 construction budget and amounts spent by subsidiaries are as
follows:
<TABLE>
<CAPTION>

                                                                   Investment
                                         Future Estimated           Amount in
                                            Compliance            2004 - 2006             Amount
                                           Investment                Budget                Spent
                                        -----------------         -----------            -------
                                                                  (in millions)
        <C>                                    <C>                     <C>                <C>
        AEGCo                                  $10                      $9                $12
        APCo                                   151                     151                307
        CSPCo                                   63                      29                 71
        I&M                                     10                       9                 17
        KPCo                                    11                       1                179
        OPCo                                   305                     273                442
        PSO                                      8                       8                  -
        SWEPCo                                  18                      12                 23
        TCC                                      -                       -                  5
</TABLE>


Estimated Investments for SO2 Compliance
----------------------------------------

The AEP System is complying with Title IV SO2 requirements by installing
scrubbers, other controls and fuel switching at certain generating
units. AEP subsidiaries also use SO2 allowances that were:

  o  Received in the annual allowance allocation by the Federal EPA,
  o  Obtained through participation in the annual allowance auction,
  o  Purchased in the allowance market, and
  o  Obtained as bonus allowances for installing controls early.

Decreasing SO2 allowance allocations, a diminishing SO2 allowance bank,
and increasing allowance prices in the market will require the
installation of additional controls on certain generating units. AEP
subsidiaries plan to install 3,500 MW of additional scrubbers over the
next 4 years to comply with our Title IV SO2 obligations. In total
management estimates these additional capital costs to be approximately
$1.2 billion. Of this total, approximately $900 million will be expended
during 2004-2006 and this amount is included in total estimated
construction expenditures for 2004 - 2006. The following table shows the
estimated additional capital costs and amounts included in the 2004 -
2006 budget for additional scrubbers by subsidiary:

                                Cost of             Amount in
                              Additional          2004 - 2006
                               Scrubbers        Construction Budget
                              ----------        -------------------
                                       (in millions)
        APCo                     $367                $307
        OPCo                      753                 542
        SWEPCo                     27                  21
        TNC                        16                  16


Estimated Investments to Comply with Future Reduction Requirements
------------------------------------------------------------------

The AEP System's planning assumptions for the levels and timing of
emissions reductions parallel the reduction levels and implementation
time periods stated in the proposed rules issued by the Federal EPA in
January 2004. Management has also assumed that the Federal EPA will
implement a mercury trading option and will design its proposed cap and
trade mechanism for SO2, NOx and mercury emissions in a manner similar
to existing cap and trade programs. Based on these assumptions,
compliance would require additional capital investment of approximately
$1.7 billion by 2010, the end of the first phase for each proposed rule.
Management estimates that the subsidiaries will invest $200 million of
this amount through 2006, and this amount is included in our total
estimated construction expenditures for 2004 - 2006.

                                 Estimated            Amount in
                                Compliance            2004 - 2006
                                Investments              Budget
                                -----------           -----------
                                           (in millions)
        APCo                       $698                   $79
        CSPCo                       184                     4
        KPCo                        295                    36
        OPCo                        454                   103
        SWEPCo                       94                     -

Management also estimates that the subsidiaries would incur increases in
variable operation and maintenance expenses of $150 million for the
periods by 2010, due to the costs associated with the maintenance of
additional control systems, disposal of scrubber by-products and the
purchase of reagents.

If the Federal EPA's preferred mercury trading option is not
implemented, then any alternative mercury control program requiring
adherence to MACT standards would also have implementation costs that
could be significant. Management cannot currently estimate the nature or
amount of these costs. Furthermore, scrubber and SCR technologies could
not be deployed at every bituminous-fired plant that the AEP System
operates within the three-year compliance schedule provided under the
proposed MACT rule. These MACT compliance costs, which management is not
able to estimate, would be incremental to other cost estimates that are
discussed above.

Beyond 2010, the AEP System expects to incur additional costs for
pollution control technology retrofits and associated operation and
maintenance of the equipment. Management cannot estimate these
additional costs because of the uncertainties associated with the final
control requirements and the associated compliance strategy, but these
capital and operating costs will be significant.

New Source Review Litigation
----------------------------

Under the CAA, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities such
as routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant.

The Federal EPA and a number of states alleged APCo, CSPCo, I&M, OPCo
and other unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the NSRs of the CAA. The Federal EPA
filed its complaints against AEP subsidiaries in U.S. District Court for
the Southern District of Ohio. The court also consolidated a separate
lawsuit, initiated by certain special interest groups, with the Federal
EPA case. The alleged modifications relate to costs that were incurred
at the generating units over a 20-year period.

Management is unable to estimate the loss or range of loss related to
the contingent liability for civil penalties under the CAA proceedings.
Management is also unable to predict the timing of resolution of these
matters due to the number of alleged violations and the significant
number of issues yet to be determined by the Court. If the AEP System
companies do not prevail, any capital and operating costs of additional
pollution control equipment that may be required, as well as any
penalties imposed, would adversely affect future results of operations,
cash flows and possibly financial condition unless such costs can be
recovered through regulated rates and market prices for electricity.

Superfund and State Remediation
-------------------------------

By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion
by-products, which constitute the overwhelming percentage of these
materials, are typically disposed of or treated in captive disposal
facilities or are beneficially utilized. In addition, our generation
plants and transmission and distribution facilities have used asbestos,
PCBs and other hazardous and non-hazardous materials. AEP subsidiaries
are currently incurring costs to safely dispose of these substances.

Superfund addresses clean-up of hazardous substances at disposal sites
and authorized the Federal EPA to administer the clean-up programs. As
of year-end 2003, APCo, CSPCo, I&M and OPCo are each named by the
Federal EPA as a PRP for one site. There are six additional sites for
which APCo, CSPCo, I&M, KPCo, OPCo and SWEPCo have received information
requests which could lead to PRP designation. OPCo and TCC have also
been named potentially liable at four sites under state law. Liability
has been resolved for a number of sites with no significant effect on
results of operations. In those instances where AEP subsidiaries have
been named a PRP or defendant, disposal or recycling activities were in
accordance with the then-applicable laws and regulations. Unfortunately,
Superfund does not recognize compliance as a defense, but imposes strict
liability on parties who fall within its broad statutory categories.

While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding potential
future liability. Disposal of materials by an AEP subsidiary at a
particular site is often unsubstantiated and the quantity of materials
deposited at a site was small and often nonhazardous. Although superfund
liability has been interpreted by the courts as joint and several,
typically many parties are named as PRPs for each site and several of
the parties are financially sound enterprises. Therefore, present
estimates do not anticipate material cleanup costs for identified sites
for which AEP subsidiaries have been declared PRPs. If significant
cleanup costs are attributed to any AEP subsidiary in the future under
Superfund, its results of operations, cash flows and possibly financial
condition would be adversely affected unless the costs can be included
in its electricity prices.

Global Climate Change
---------------------

At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997, more
than 160 countries, including the U.S., negotiated a treaty requiring
legally-binding reductions in emissions of greenhouse gases, chiefly
CO2, which many scientists believe are contributing to global climate
change. The U.S. signed the Kyoto Protocol on November 12, 1998, but the
treaty was not submitted to the Senate for its advice and consent by
President Clinton. In March 2001, President Bush announced his
opposition to the treaty. Ratification of the treaty by a majority of
the countries' legislative bodies is required for it to be enforceable.
Enforceability of the protocol is now contingent on ratification by
Russia, which has expressed concerns about doing so.

On August 28, 2003, the Federal EPA issued a decision in response to a
petition for rulemaking seeking reductions of CO2 and other greenhouse
gas emissions from mobile sources. The Federal EPA denied the petition
and issued a memorandum stating that it does not have the authority
under the CAA to regulate CO2 or other greenhouse gas emissions that may
affect global warming trends. The Circuit Court of Appeals for the
District of Columbia is reviewing these actions.

AEP does not support the Kyoto Protocol but has been working with the
Bush Administration on a voluntary program aimed at meeting the
President's goal of reducing the greenhouse gas intensity of the economy
by 18% by 2012. For many years, AEP has been a leader in pursuing
voluntary actions to control greenhouse gas emissions. AEP expanded its
commitment in this area in 2002 by joining the Chicago Climate Exchange,
a pilot greenhouse gas emission reduction and trading program, under
which AEP's subsidiaries are obligated to reduce or offset 18 million
tons of CO2 emissions during 2003-2006.

Costs for Spent Nuclear Fuel and Decommissioning
------------------------------------------------

I&M, as the owner of the Cook Plant, and TCC, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF
and to decommission and decontaminate the plants. The Nuclear Waste
Policy Act of 1982 established federal responsibility for the permanent
off-site disposal of SNF and high-level radioactive waste. By law I&M
and TCC participate in the DOE's SNF disposal program which is described
in Note 7. Since 1983 I&M has collected $316 million from customers for
the disposal of nuclear fuel consumed at the Cook Plant. We deposited
$117 million of these funds in external trust funds to provide for the
future disposal of SNF and remitted $199 million to the DOE. TCC has
collected and remitted to the DOE, $56 million for the future disposal
of SNF since STP began operation in the late 1980s. Under the provisions
of the Nuclear Waste Policy Act, collections from customers are to
provide the DOE with money to build a permanent repository for spent
fuel. However, in 1996, the DOE notified the companies that it would be
unable to begin accepting SNF by the January 1998 deadline required by
law. To date, the DOE has failed to comply with the requirements of the
Nuclear Waste Policy Act.

As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for SNF, AEP on
behalf of I&M and STPNOC on behalf of TCC and the other STP owners,
along with a number of unaffiliated utilities and states, filed suit in
the D.C. Circuit Court requesting, among other things, that the D.C.
Circuit Court order DOE to meet its obligations under the law. The D.C.
Circuit Court ordered the parties to proceed with contractual remedies
but declined to order DOE to begin accepting SNF for disposal. DOE
estimates its planned site for the nuclear waste will not be ready until
at least 2010. In 1998, AEP and I&M filed a complaint in the U.S. Court
of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant. Similar lawsuits
were filed by other utilities. In August 2000, in an appeal of related
cases involving other unaffiliated utilities, the U.S. Court of Appeals
for the Federal Circuit held that the delays clause of the standard
contract between utilities and the DOE did not apply to DOE's complete
failure to perform its contract obligations, and that the utilities'
suits against DOE may continue in court. On January 17, 2003, the U.S.
Court of Federal Claims ruled in favor of I&M on the issue of liability.
The case continues on the issue of damages owed to I&M by the DOE with a
trial scheduled in March 2004. As long as the delay in the availability
of a government approved storage repository for SNF continues, the cost
of both temporary and permanent storage of SNF and the cost of
decommissioning will continue to increase.

The cost to decommission nuclear plants is affected by both NRC
regulations and the delayed SNF disposal program. Studies completed in
2003 estimate the cost to decommission the Cook Plant ranges from $821
million to $1.08 billion in 2003 non-discounted dollars. External trust
funds have been established with amounts collected from customers to
decommission the plant. At December 31, 2003, the total decommissioning
trust fund balance for Cook Plant was $720 million which includes
earnings on the trust investments. Studies completed in 1999 for STP
estimate TCC's share of decommissioning cost to be $289 million in 1999
non-discounted dollars. Amounts collected from customers to decommission
STP have been placed in an external trust. At December 31, 2003, the
total decommissioning trust fund for TCC's share of STP was $125 million
which includes earnings on the trust investments. Estimates from the
decommissioning studies could continue to escalate due to the
uncertainty in the SNF disposal program and the length of time that SNF
may need to be stored at the plant site. I&M and TCC will work with
regulators and customers to recover the remaining estimated costs of
decommissioning Cook Plant and STP. However, future results of
operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning
continues to increase and cannot be recovered.

Clean Water Act Regulation
--------------------------

On February 16, 2004, the Federal EPA signed a rule pursuant to the
Clean Water Act that will require all large existing power plants to
meet certain performance standards to reduce the mortality of juvenile
and adult fish or other larger organisms pinned against a plant's
cooling water intake screens. A subset of these plants that are located
on sensitive water bodies will be required to meet additional
performance standards for reducing the number of smaller organisms
passing through the water screens and the cooling system. Sensitive
water bodies are defined as oceans, estuaries, the Great Lakes, and
small rivers with large plants. These rules will result in additional
capital and operation and maintenance expenses to ensure compliance.

Other Environmental Concerns
----------------------------

We perform environmental reviews and audits on a regular basis for the
purpose of identifying, evaluating and addressing environmental concerns
and issues. In addition to the matters discussed above, the AEP
subsidiaries are managing other environmental concerns which are not
believed to be material or potentially material at this time. If they
become significant or if any new matters arise that could be material,
they could have a material adverse effect on results of operations, cash
flows and possibly financial condition.

Critical Accounting Policies
----------------------------

In the ordinary course of business, we use a number of estimates and
assumptions relating to the reporting of results of operations and
financial condition in the preparation of our financial statements in
conformity with accounting principles generally accepted in the United
States of America. Actual results could differ significantly from those
estimates under different assumptions and conditions. We believe that
the following discussion addresses the most critical accounting
policies, which are those that are most important to the portrayal of
the financial condition and results and require management's most
difficult, subjective and complex judgments, often as a result of the
need to make estimates about the effect of matters that are inherently
uncertain.

Revenue Recognition
-------------------

Regulatory Accounting
---------------------

The consolidated financial statements of the registrant subsidiary
companies with cost-based rate-regulated operations (I&M, KPCo, PSO, and
a portion of APCo, OPCo, CSPCo, TCC, TNC and SWEPCo), reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate
regulated. In accordance with SFAS 71, regulatory assets (deferred
expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect
the economic effects of regulation by matching expenses with their
recovery through regulated revenues in the same accounting period and by
matching income with its passage to customers through regulated revenues
in the same accounting period. Regulatory liabilities (unrealized gains)
or regulatory assets (unrealized losses) are also recorded for changes
in the fair value of physical and financial contracts that meet the
definition of a derivative as defined in SFAS 133 and are subject to the
regulated ratemaking process.

When regulatory assets are probable of recovery through regulated rates,
certain registrant subsidiaries record them as assets on the balance
sheet. Registrant subsidiaries test for probability of recovery whenever
new events occur, for example a regulatory commission order or passage
of new legislation. If registrant subsidiaries determine that recovery
of a regulatory asset is no longer probable, they write off that
regulatory asset as a charge against net income. A write off of
regulatory assets may also reduce future cash flows since there may be
no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities
------------------------------------------------------

Revenues are recognized on the accrual or settlement basis for normal
retail and wholesale electricity supply sales and electricity
transmission and distribution delivery services. The revenues are
recognized and recorded when the energy is delivered to the customer and
include estimated unbilled as well as billed amounts. In general,
expenses are recorded when purchased electricity is received and when
expenses are incurred.

Energy Marketing and Risk Management Activities
-----------------------------------------------

Registrant subsidiaries engage in wholesale electricity, natural gas and
coal marketing and risk management activities. Effective in October
2002, these activities were focused on wholesale markets where
registrant subsidiaries own assets. Registrant subsidiaries activities
include the purchase and sale of energy under forward contracts at fixed
and variable prices and the buying and selling of financial energy
contracts which include exchange traded futures and options, and
over-the-counter options and swaps. Prior to October 2002, registrant
subsidiaries recorded wholesale marketing and risk management activities
using the mark-to-market method of accounting.

In October 2002, EITF 02-3 precluded mark-to-market accounting for risk
management contracts that were not derivatives pursuant to SFAS 133.
Registrant subsidiaries implemented this standard for all non-derivative
wholesale and risk management transactions occurring on or after October
25, 2002. For non-derivative risk management transactions entered into
prior to October 25, 2002, registrant subsidiaries implemented this
standard on January 1, 2003 and reported the effects of implementation
as a cumulative effect of an accounting change.

After January 1, 2003, registrant subsidiaries use mark-to-market
accounting for wholesale marketing and risk management transactions that
are derivatives unless the derivative is designated for hedge accounting
or the normal purchase and sale exemption. Revenues and expenses are
recognized from wholesale marketing and risk management transactions
that are not derivatives when the commodity is delivered.

See discussion of EITF 02-3 and rescission of EITF 98-10 in Note 2.

All of the registrant subsidiaries except AEGCo participate in wholesale
marketing and risk management activities in electricity and gas. For
I&M, KPCo, PSO and a portion of TNC and SWEPCo, when the contract
settles the total gain or loss is realized in revenues. Where the
revenues are recorded on the income statement depends on whether the
contract is subject to the regulated ratemaking process. For contracts
subject to the regulated ratemaking process the total gain or loss
realized for sales and the cost of purchased energy are included in
revenues on a net basis. Prior to settlement, changes in the fair value
of physical and financial forward sale and purchase contracts subject to
the regulated ratemaking process are deferred as regulatory liabilities
(gains) or regulatory assets (losses). For contracts not subject to the
ratemaking process only the difference between the accumulated
unrealized net gains or losses recorded in prior periods and the cash
proceeds are recognized in the income statement as nonoperating income.
Prior to settlement, changes in the fair value of physical and financial
forward sale and purchase contracts not subject to the ratemaking
process are included in nonoperating income on a net basis. Unrealized
mark-to-market gains and losses are included in the balance sheet as
Risk Management Assets or Liabilities as appropriate.

For APCo, CSPCo and OPCo, depending on whether the delivery point for
the electricity is in the traditional marketing area or not determines
where the contract is reported in the income statement. Physical forward
risk management sale and purchase contracts with delivery points in the
traditional marketing area are included in revenues on a net basis.
Prior to settlement, changes in the fair value of physical forward sale
and purchase contracts in the traditional marketing area are also
included in revenues on a net basis. Physical forward sale and purchase
contracts for delivery outside of the traditional marketing area are
included in nonoperating income when the contract settles. Prior to
settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of the traditional
marketing area are included in nonoperating income on a net basis.

Accounting for Derivative Instruments
-------------------------------------

For derivative contracts that are not designated as hedges or normal
purchase and sale transactions, registrant subsidiaries recognize
unrealized gains and losses prior to settlement based on changes in fair
value during the period in our results of operations. When registrant
subsidiaries settle mark-to-market derivative contracts and realize
gains and losses, registrant subsidiaries reverse previously recorded
unrealized gains and losses from mark-to-market valuations.

Registrant subsidiaries designate certain derivative instruments as
hedges of forecasted transactions or future cash flows (cash flow
hedges) or as a hedge of a recognized asset, liability or firm
commitment (fair value hedge). Registrant subsidiaries report changes in
the fair value of these instruments on our balance sheet. Registrant
subsidiaries do not recognize changes in the fair value of the
derivative instrument designated as a hedge in the current results of
operations until earnings are impacted by the hedged item. Registrant
subsidiaries also recognize any changes in the fair value of the hedging
instrument, that are not offset by changes in the fair value of the
hedged item, immediately in earnings.

Registrant subsidiaries measure the fair values of derivative instruments
and hedge instruments accounted for using mark-to-market accounting based on
exchange prices and broker quotes. If a quoted market price is not available,
registrant subsidiaries estimate the fair value based on the best information
available including valuation models that estimate future energy prices
based on existing market and broker quotes, supply and demand market
data, and other assumptions. Registrant subsidiaries reduce fair values
by estimated valuation adjustments for items such as discounting,
liquidity and credit quality. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term
derivative contracts. Registrant subsidiaries have independent controls
to evaluate the reasonableness of our valuation models. However, energy
markets, especially electricity markets, are imperfect and volatile.
Unforeseen events can and will cause reasonable price curves to differ
from actual prices throughout a contract's term and at the time a
contract settles. Therefore, there could be significant adverse or
favorable effects on future results of operations and cash flows if
market prices are not consistent with our approach at estimating current
market consensus for forward prices in the current period. This is
particularly true for long-term contracts.

Registrant subsidiaries recognize all derivative instruments at fair
value in our balance sheets as either Risk Management Assets or Risk
Management Liabilities. Registrant subsidiaries do not consider
contracts that have been elected normal purchase or normal sale under
SFAS 133 to be derivatives. Unrealized and realized gains and losses on
all derivative instruments are ultimately included in revenues in the
income statements on a net basis.

Long-Lived Assets
-----------------

Long-lived assets are evaluated periodically for impairment whenever
events or changes in circumstances indicate that the carrying amount of
any such assets may not be recoverable. If the carrying amount is not
recoverable, an impairment is recorded to the extent that the fair value
of the asset is less then its book value.

Pension Benefits
----------------

AEP sponsors pension and other retirement plans in various forms
covering all employees who meet eligibility requirements. AEP uses
several statistical and other factors which attempt to anticipate future
events in calculating the expense and liability related to its plans.
These factors include assumptions about the discount rate, expected
return on plan assets and rate of future compensation increases as
estimated by management, within certain guidelines. In addition, AEP's
actuarial consultants use subjective factors such as withdrawal and
mortality rates to estimate these factors. The actuarial assumptions
used may differ materially from actual results due to changing market
and economic conditions, higher or lower withdrawal rates or longer or
shorter life spans of participants. These differences may result in a
significant impact to the amount of pension expense recorded. See
"Pension Plans" in the Significant Factors section of Registrants'
Combined Management's Discussion and Analysis for additional discussion.

New Accounting Pronouncements
-----------------------------

Effective July 1, 2003, we implemented FIN 46, "Consolidation of
Variable Interest Entities." As a result of the implementation, we
consolidated two entities, Sabine Mining Company ($77.8 million) and JMG
Funding, LP ($469.6 million), which were previously off-balance sheet.
These entities were consolidated with SWEPCo and OPCo, respectively.
There is no change in net income due to the consolidations. In addition,
we deconsolidated the trusts which hold mandatorily redeemable trust
preferred securities which were previously reported as Certain
Subsidiary Obligated, Mandatorily Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries ($321 million). As a result of the deconsolidation these
amounts are now included in Long-term Debt. In December 2003, the FASB
issued FIN 46R which replaces FIN 46. The FASB and other accounting
constituencies continue to interpret the application of FIN 46R. As a
result, we are continuing to review the application of this new
interpretation and expect to adopt FIN 46R by March 31, 2004.

See Notes 1 and 2 of the Notes to Respective Financial Statements for a
discussion of significant accounting policies and additional impacts of
new accounting pronouncements.

Other Matters
-------------

FERC Proposed Standard Market Design
------------------------------------

In July 2002, the FERC issued its Standard Market Design (SMD) notice of
proposed rulemaking, which sought to standardize the structure and
operation of wholesale electricity markets across the country. Key
elements of FERC's proposal included standard rules and processes for
all users of the electricity transmission grid, new transmission rules
and policies, and the creation of certain markets to be operated by
independent administrators of the grid in all regions. The FERC issued a
"white paper" on the proposal in April 2003, in response to the numerous
comments that the FERC received on its proposal. Management does not
know if or when the FERC will finalize a rule for SMD. Until any
potential rule is finalized, management cannot predict its effect on
cash flows and results of operations.

FERC Market Power Mitigation
----------------------------

A FERC order issued in November 2001 on AEP's triennial market based
wholesale power rate authorization update required certain mitigation
actions that AEP would need to take for sales/purchases within its
control area and required AEP to post information on its website
regarding its power system's status. As a result of a request for
rehearing filed by AEP and other market participants, FERC issued an
order delaying the effective date of the mitigation plan until after a
planned technical conference on market power determination. In December
2003, the FERC issued a staff paper discussing alternatives and held a
technical conference in January 2004. Management is unable to predict
the timing of any further action by the FERC or its affect of future
results of operations and cash flows.

Seasonality
-----------

The sale of electric power in AEP subsidiaries' service territories is
generally a seasonal business. In many parts of the country, demand for
power peaks during the hot summer months, with market prices also
peaking at that time. In other areas, power demand peaks during the
winter. The pattern of this fluctuation may change due to the nature and
location of the AEP System's facilities and the terms of power contracts
into which AEP enters. In addition, AEP subsidiaries have historically
sold less power, and consequently earned less income, when weather
conditions are milder. Unusually mild weather in the future could
diminish results of operations and may impact cash flows and financial
condition.