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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-Q
              [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                  For The Quarterly Period Ended MARCH 31, 2003
                                       OR
              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                        For The Transition Period from to


Commission                  Registrant, State of Incorporation                                                I.R. S. Employer
File Number                 Address, and Telephone Number                                                     Identification No.
<S>                         <C>                                                                               <C>

1-3525                      AMERICAN ELECTRIC POWER COMPANY, INC.                                             13-4922640
                            (A New York Corporation)
0-18135                     AEP GENERATING COMPANY (An Ohio Corporation)                                      31-1033833
0-346                       AEP TEXAS CENTRAL COMPANY (A Texas Corporation)                                   74-0550600
0-340                       AEP TEXAS NORTH COMPANY (A Texas Corporation)                                     75-0646790
1-3457                      APPALACHIAN POWER COMPANY (A Virginia Corporation)                                54-0124790
1-2680                      COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)                             31-4154203
1-3570                      INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)                           35-0410455
1-6858                      KENTUCKY POWER COMPANY (A Kentucky Corporation)                                   61-0247775
1-6543                      OHIO POWER COMPANY (An Ohio Corporation)                                          31-4271000
0-343                       PUBLIC SERVICE COMPANY OF OKLAHOMA                                                73-0410895
                            (An Oklahoma Corporation)
1-3146                      SOUTHWESTERN ELECTRIC POWER COMPANY                                               72-0323455
                            (A Delaware Corporation)

All Registrants             1 Riverside Plaza, Columbus, Ohio  43215-2373
                            Telephone (614) 223-1000

Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.

                                                                                                            Yes       X
No

Indicate by check mark whether  American  Electric  Power Company,  Inc. is an accelerated  filer (as defined in Rule 12b-2 of
the Exchange Act).

                                                                                                            Yes       X
No

Indicate by check mark whether AEP Generating Company, AEP Texas Central
Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern
Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio
Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company, are accelerated filers (as defined in Rule 12b-2 of the Exchange
Act).


                                                                                                            Yes
No   X

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

The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at April 30, 2003 was 394,993,420.
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                               AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                                          FORM 10-Q

                                            For The Quarter Ended March 31, 2003
                                                          CONTENTS

                                                                                                                    Page
   Glossary of Terms                                                                                                i - iii
   Forward-Looking Information                                                                                      iv

   Part I.  FINANCIAL INFORMATION
     Items 1 and 2 Financial Statements and Management's Discussion
                    and Analysis of Results of Operations:

<S>                                                                                                                <C>
                         American Electric Power Company, Inc. and Subsidiary Companies:
                              Management's Discussion and Analysis of Results of Operations                         A-1 - A-3
                              Consolidated Financial Statements                                                     A-4 - A-8

                         AEP Generating Company:
                              Management's Narrative Analysis of Results of Operations                              B-1 - B-2
                              Financial Statements                                                                  B-3 - B-6

                         AEP Texas Central Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         C-1 - C-4
                              Consolidated Financial Statements                                                     C-5 - C-9

                         AEP Texas North Company:
                              Management's Narrative Analysis of Results of Operations                              D-1 - D-3
                              Financial Statements                                                                  D-4 - D-8

                         Appalachian Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         E-1 - E-3
                              Consolidated Financial Statements                                                     E-4 - E-8

                         Columbus Southern Power Company and Subsidiaries:
                              Management's Narrative Analysis of Results of Operations                              F-1 - F-2
                              Consolidated Financial Statements                                                     F-3 - F-7

                         Indiana Michigan Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         G-1 - G-3
                              Consolidated Financial Statements                                                     G-4 - G-8

                         Kentucky Power Company:
                              Management's Narrative Analysis of Results of Operations                              H-1 - H-2
                              Financial Statements                                                                  H-3 - H-7

                         Ohio Power Company:
                              Management's Discussion and Analysis of Results of Operations                         I-1 - I-3
                              Financial Statements                                                                  I-4 - I-8

                         Public Service Company of Oklahoma and Subsidiary:
                              Management's Narrative Analysis of Results of Operations                              J-1 - J-2
                              Consolidated Financial Statements                                                     J-3 - J-7

                         Southwestern Electric Power Company and Subsidiaries:
                              Management's Discussion and Analysis of Results of Operations                         K-1 - K-2
                              Consolidated Financial Statements                                                     K-3 - K-7



<PAGE>




                         Combined Notes to Financial Statements                                                     L-1 - L-33



<PAGE>


           Item 2.        Registrants' Combined Management's Discussion and Analysis of
                                 Financial Condition, Accounting Policies and Other Matters                         M-1 - M-14
           Item 3.        Quantitative and Qualitative Disclosures About Risk Management Activities                 N-1 - N-13
           Item 4.        Controls and Procedures                                                                   O-1

       Part II.           OTHER INFORMATION
           Item 5.            Other Information                                                                     P-1
           Item 6.            Exhibits and Reports on Form 8-K                                                      P-1
                                     (a)  Exhibits
                                           Exhibit 12
                                           Exhibit 99.1
                                           Exhibit 99.2
                                     (b)   Reports on Form 8-K

SIGNATURES                                                                                                          Q-1

CERTIFICATIONS                                                                                                      R-1 - R-4

This combined Form 10-Q is separately filed by 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 and Southwestern Electric Power Company. Information
contained herein relating to any individual registrant is filed by such
registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.

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

               Term                                Meaning
<S>                                <C>
2004 True-up Proceeding............A filing to be made after January 10, 2004 under the Texas  Legislation to finalize the amount
                                            of stranded costs and the recovery of such costs.
AEGCo..............................AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................American Electric Power Company, Inc.
AEP Consolidated...................AEP and its majority owned consolidated subsidiaries.
AEP Credit.........................AEP Credit,  Inc., a subsidiary of AEP which factors  accounts  receivable and accrued utility
                                            revenues for affiliated and non-affiliated domestic electric utility companies.
AEP East companies.................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR...............................AEP Resources, Inc.
AEP System or the System...........The American Electric Power System, an integrated electric utility system,  owned and operated
                                            by AEP's electric utility subsidiaries.
AEPSC..............................American Electric Power Service  Corporation,  a service subsidiary  providing  management and
                                            professional services to AEP and its subsidiaries.
AEP Power Pool.....................AEP System  Power  Pool.  Members are APCo,  CSPCo,  I&M,  KPCo and OPCo.  The Pool shares the
                                            generation,  cost of generation  and resultant  wholesale  system sales of the member
                                            companies.
AEP West companies.................PSO, SWEPCo, TCC and TNC.
Amos Plant.........................John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and OPCo.
APCo...............................Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................Arkansas Public Service Commission.
Buckeye............................Buckeye Power, Inc., an unaffiliated corporation.
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.
CSW............................... Central and South West  Corporation,  a subsidiary  of AEP  (Effective  January 21, 2003,  the
                                            legal name of Central and South West
Corporation was changed to AEP Utilities, Inc.).
CSW Energy.........................CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International..................CSW  International,  Inc., an AEP  subsidiary  which  invests in energy  projects and entities
                                            outside the United States.
D.C. Circuit Court.................The United States Court of Appeals for the District of Columbia Circuit.
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..........................Recognition  and Reporting of Gains and Losses on Energy  Contracts under Issues No. 98-10 and
                                            00-17.
ERCOT..............................The Electric Reliability Council of Texas.
FASB...............................Financial Accounting Standards Board.
Federal EPA........................United States Environmental Protection Agency.
FERC...............................Federal Energy Regulatory Commission.
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.
KPCo...............................Kentucky Power Company, an AEP electric utility subsidiary.
KPSC...............................Kentucky Public Service Commission.
KWH................................Kilowatthour.
LIG................................Louisiana Intrastate Gas.
Michigan Legislation...............The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
MISO...............................Midwest Independent System Operator (an independent operator of transmission assets in the
                                            Midwest).
MLR................................Member Load Ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool.........................AEP System's Money Pool.
MPSC...............................Michigan Public Service Commission.
MTM................................Mark-to-Market.
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.
PJM................................Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO................................Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO...............................The Public Utilities Commission of Ohio.
PUCT...............................The Public Utility Commission of Texas.
PUHCA..............................Public Utility Holding Company Act of 1935, as amended.
PURPA..............................The Public Utility Regulatory Policies Act of 1978.
RCRA...............................Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............AEP subsidiaries who are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
                                            TCC and TNC.
REP................................Retail Electric Provider.
Rockport Plant.....................A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO................................Regional Transmission Organization.
SEC................................Securities and Exchange Commission.
SFAS...............................Statement of Financial Accounting Standards issued by the Financial Accounting Standards
                                            Board.
SFAS 71............................Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
                                            Types of Regulation.
SFAS 101...........................Statement of Financial Accounting Standards No. 101, Accounting for the
                                                Discontinuance of Application of Statement 71.
SFAS 133...........................Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
                                            and Hedging Activities.
SFAS 143...........................Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement
                                            Obligations.
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.
SWEPCo.............................Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC................................AEP Texas Central Company, an AEP electric utility subsidiary [formerly known as Central
                                            Power and Light Company (CPL)].
Texas Legislation..................Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC................................AEP Texas North Company, an AEP electric utility subsidiary [formerly known as West Texas
                                            Utilities Company (WTU)].
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>



                                       iv
     FORWARD LOOKING INFORMATION

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

o        Electric load and customer growth.
o        Abnormal weather conditions.
o        Available sources and costs of fuels.
o        Availability of generating capacity.
o        The speed and degree to which competition is introduced to our service
         territories.
o        The ability to recover stranded costs in connection with
         possible/proposed deregulation.
o        New legislation and government regulation.
o        Oversight and/or investigation of the energy sector or
          its participants.
o        Our ability to successfully control costs.
o        The success of acquiring new business ventures and disposing of
         existing investments that no longer match our corporate profile.
o        International and country-specific developments affecting foreign
         investments including the disposition of any current foreign
         investments and potential additional foreign investments.
o        The economic climate and growth in our service territory and
          changes in market demand and demographic patterns.
o        Inflationary trends.
o        Electricity and gas market prices.
o        Interest rates.
o        Liquidity in the banking, capital and wholesale power markets.
o        Actions of rating agencies.
o        Changes in technology, including the increased use of distributed
         generation within our transmission and distribution service territory.
o Other risks and unforeseen events, including wars, the effects of terrorism,
embargoes and other catastrophic events.

<PAGE>




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

                   FIRST QUARTER 2003 vs. FIRST QUARTER 2002

American Electric Power Company, Inc.'s principal operating business segments
and their major activities are:

        Utility Operations
        oDomestic generation of electricity for sale to retail
           and wholesale customers
        oDomestic electricity transmission and distribution

        Investments - Gas Operations
        oGas pipeline and storage services

        Investments - UK Operations
        oInternational generation of electricity for sale to wholesale customers

        Investments - Other
        oCoal mining, bulk commodity barging operations and other
          energy supply businesses


        o
Results of Operations

Net Income of $440 million or $1.24 per share in the first quarter of 2003
included $193 million of Income from Cumulative Effect of Accounting Changes
(see Note 3). Income Before Discontinued Operations and Cumulative Effect
increased $97 million or 61% due to improved earnings from system sales
resulting from the interactions of plant availability, the colder winter weather
and higher margins.

Changes in Revenues

AEP's total revenue increased 36% in the first quarter of 2003. The following
table shows the components of revenue.
                                                       Increase (Decrease)
                                                   (in millions)       %
REVENUES:
    Electric Generation                             $ 441               31
    Electric Transmission and
     Distribution                                      74                9
    Gas Pipeline and Storage                          669              155
    Investments                                      ( 96)             (32)
             TOTAL REVENUES                       $ 1,088               36


The increase in revenues was primarily due to higher levels of Electric
Generation and Electric Transmission and Distribution resulting from plant
availability and the colder winter weather as well as the higher revenue from
Gas Pipeline and Storage sales resulting primarily from higher prices. Heating
degree days were up 20% which resulted in higher residential KWH sales of 4%.
System sales volume increased 10% to 7,681 gigawatt hours. Higher gas prices
were caused by the decreasing availability of gas. Fuel inventories at gas
storage facilities were reduced to low levels reflecting the colder winter
weather compared to 2002. Investment revenues decreased 32% due to the completed
construction of a gas-fired plant for a third party in the summer of 2002 and a
reduction in U.K. operating margins due to market conditions.

Changes in Expenses

                                                Increase (Decrease)
                                            (in millions)           %
EXPENSES:
  Fuel for Electric Generation                     $ 39                6
  Purchased Electricity for Resale                  176              N.M.
  Purchased Gas for Resale                          795              225
  Maintenance and Other Operation                   (43)              (4)
  Depreciation and Amortization                     (17)              (5)
  Taxes Other Than Income Taxes                      (3)              (2)

      TOTAL OPERATING EXPENSES                     $947               37

N.M. = Not Meaningful

The increase in Fuel for Electric Generation includes the effect of an increase
in AEP's domestic net generation of 6% and higher generation output of 31% in
the U.K. operation. The increase in Purchased Electricity for Resale expense was
primarily attributable to an increase in MWH purchased to meet the demand.
Purchased Gas for Resale increased due primarily to higher market prices.

Maintenance and Other Operation expense decreased primarily due to the effect of
material and labor costs related to the construction of a gas-fired plant for a
third party that was completed in 2002. Project fees for the construction of the
gas-fired plant for a third party were recognized in revenues on a percentage of
completion method, consequently, the decrease in expense for material and labor
cost does not affect net income. In addition, payroll expense decreased due in
part to personnel reductions in late 2002. These decreases were partially offset
by increases in U.K. operational expenses, pension and postretirement benefits
expense, accretion expense related to asset retirement obligations (ARO) SFAS
143 (see Note 2 and explanation of decrease in Depreciation and Amortization
expense below) and nuclear refueling outage amortization expenses.

The decrease in Depreciation and Amortization expense is primarily due to the
adoption of SFAS 143 for certain subsidiary utility companies effective January
1, 2003. Effective January 1, 2003 the generation depreciation rate for certain
non-regulated jurisdictions was reduced to exclude the non-ARO removal cost
portion that was included in the depreciation rate. In addition, certain
amortization related to nuclear decommissioning costs was reclassified as ARO
accretion expense which is included in Maintenance and Other Operations expense.
Additionally, APCo reduced its Depreciation and Amortization expense related to
the amortization of generation related regulatory assets due to the return to
SFAS 71 regulatory accounting for the West Virginia jurisdiction (see Note 6 for
further discussion of the return to SFAS 71 regulatory accounting).


Other Income and Other Expenses

Other Income includes non-operating revenue including non-utility revenue
associated with energy related projects for customers, equity earnings of
non-consolidated subsidiaries, a gain on the sale of our customer care
operations in Texas, and interest and miscellaneous income.

Other Expenses includes non-utility expenses associated with energy related
projects for customers, losses on dispositions of property, donations and
various other non-operating and miscellaneous expenses.

Other Income increased mainly due to a gain of $39 million on the sale of our
customer care operations in Texas and an increase in miscellaneous income. In
the first quarter of 2003, AEP sold Mutual Energy Service Company, a customer
care operation which was created to serve retail customers in the deregulated
Texas market, to Alliance Data Systems. This sale continues our exit of the
retail electric supply business in Texas and refocuses our resources on
wholesale generation and power supply markets. Miscellaneous income increased
due to additional contracts for the staffing of nonassociated companies'
outages. Other Expenses increased due to increased non-utility expenses
associated with energy related construction projects for third parties.

Other Changes

The increase in Income Taxes is due to an increase in pre-tax income and the tax
effects of foreign operations.

The increase in Interest was primarily due to an increase in outstanding
balances of long-term debt in the first quarter of 2003. The increase was
partially offset by a decrease in short-term debt interest expense due to a
decrease in outstanding balances of short-term debt in the first quarter of
2003.

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
Notes 2 and 3).



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         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                     (in millions, except per-share amounts)
                                   (UNAUDITED)
                                                                         Three Months Ended March 31,
                                                                           2003             2002

REVENUES:
<S>                                                                      <C>                <C>
  Electric Generation                                                    $1,863             $ 1,422
  Electric Transmission and Distribution                                    910                 836
  Gas Pipeline and Storage                                                1,102                 433
  Investments                                                               205                 301
               TOTAL REVENUES                                             4,080               2,992
EXPENSES:
  Fuel for Electric Generation                                              660                 621
  Purchased Electricity for Resale                                          205                  29
  Purchased Gas for Resale                                                1,149                 354
  Maintenance and Other Operation                                           963               1,006
  Depreciation and Amortization                                             315                 332
  Taxes Other Than Income Taxes                                             188                 191
               TOTAL EXPENSES                                             3,480               2,533

OPERATING INCOME                                                            600                 459

OTHER INCOME                                                                118                  12

OTHER EXPENSES                                                               45                  20

LESS: INTEREST                                                              205                 195

      PREFERRED STOCK DIVIDEND REQUIREMENTS OF
        SUBSIDIARIES
                                                                              3                   2

      MINORITY INTEREST IN FINANCE SUBSIDIARY                                 9                   9

INCOME BEFORE INCOME TAXES                                                  456                 245
INCOME TAXES                                                                200                  86
INCOME BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE
 EFFECT                                                                     256                 159
DISCONTINUED OPERATIONS (LOSS) INCOME (NET OF TAX)                           (9)                 22
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX):
  Goodwill and Other Intangible Assets                                     -                   (350)
  Accounting for Risk Management Contracts                                  (49)               -
  Asset Retirement Obligation                                               242                -

NET INCOME (LOSS)                                                        $  440             $  (169)

AVERAGE NUMBER OF SHARES OUTSTANDING                                        356                 322

EARNINGS (LOSS) PER SHARE:
  Income Before Discontinued Operations and
   Cumulative Effect of Accounting Changes
                                                                         $ 0.72              $ 0.49
  Discontinued Operations                                                 (0.02)               0.07
  Cumulative Effect of Accounting Changes                                  0.54               (1.08)

  Earnings (Loss) Per Share (Basic and Diluted)                          $ 1.24              $(0.52)

CASH DIVIDENDS PAID PER SHARE                                            $ 0.60              $ 0.60


See Notes to Consolidated Financial Statements beginning on page L-1.

</TABLE>
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<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                                   March 31, 2003           December 31, 2002
                                                                                                (in millions)
ASSETS

CURRENT ASSETS:
<S>                                                                                  <C>                      <C>
    Cash and Cash Equivalents                                                        $ 1,764                  $ 1,213
    Accounts Receivable (net)                                                          2,572                    1,740
    Fuel, Materials and Supplies                                                         966                    1,166
    Risk Management Assets                                                             1,105                    1,012
    Other                                                                              1,037                      935

       TOTAL CURRENT ASSETS                                                            7,444                    6,066

PROPERTY, PLANT AND EQUIPMENT:
   Electric:
     Production                                                                       17,239                   17,031
     Transmission                                                                      5,909                    5,882
     Distribution                                                                      9,585                    9,573
   Other (including gas, coal mining and
     nuclear fuel)                                                                     3,911                    3,965
   Construction Work in Progress                                                       1,510                    1,406
       Total Property, Plant and Equipment                                            38,154                   37,857
   Accumulated Depreciation and Amortization                                          15,826                   16,173

       NET PROPERTY, PLANT AND EQUIPMENT                                              22,328                   21,684

REGULATORY ASSETS                                                                      2,669                    2,688

SECURITIZED TRANSITION ASSETS                                                            726                      735

INVESTMENTS IN POWER AND DISTRIBUTION PROJECTS                                           291                      283

GOODWILL                                                                                 396                      396

ASSETS HELD FOR SALE                                                                     280                      292

LONG-TERM RISK MANAGEMENT ASSETS                                                         812                      819

OTHER ASSETS                                                                           1,955                    1,783

          TOTAL ASSETS                                                               $36,901                  $34,746

See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
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<CAPTION>
         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                            March 31, 2003           December 31, 2002
                                                                                           (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
<S>                                                                              <C>                        <C>
  Accounts Payable                                                               $ 2,930                    $ 2,030
  Short-term Debt                                                                    239                      3,164
  Long-term Debt Due Within One Year                                               1,696                      1,633
  Risk Management Liabilities                                                      1,268                      1,113
  Other                                                                            2,020                      1,802

       TOTAL CURRENT LIABILITIES                                                   8,153                      9,742

LONG-TERM DEBT                                                                    10,436                      8,487

EQUITY UNIT SENIOR NOTES                                                             376                        376

LONG-TERM RISK MANAGEMENT LIABILITIES                                                543                        481

DEFERRED INCOME TAXES                                                              4,037                      3,916

DEFERRED INVESTMENT TAX CREDITS                                                      448                        455

DEFERRED CREDITS AND REGULATORY LIABILITIES                                          830                        770

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                                              183                        185

LIABILITIES HELD FOR SALE                                                            161                        142

OTHER NONCURRENT LIABILITIES                                                       2,073                      1,903

COMMITMENTS AND CONTINGENCIES (Note 7)

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
  PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
  SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
  SUBSIDIARIES                                                                       321                        321

MINORITY INTEREST IN FINANCE SUBSIDIARY                                              759                        759

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES                                          144                        145

COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
                                2003           2002
      Shares Authorized.. . 600,000,000     600,000,000
      Shares Issued. . . . .403,993,412     347,835,212
      (8,999,992 shares were held in treasury at
       March 31, 2003 and December 31, 2002)                                       2,626                      2,261
  Paid-in Capital                                                                  4,175                      3,413
  Accumulated Other Comprehensive Income (Loss)                                     (602)                      (609)
  Retained Earnings                                                                2,238                      1,999
          TOTAL COMMON SHAREHOLDERS' EQUITY                                        8,437                      7,064

              TOTAL LIABILITIES AND SHAREHOLDERS'EQUITY
                                                                                 $36,901                    $34,746

See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                                                    Three Months Ended March 31,
                                                                                                      2003                2002
                                                                                                           (in millions)
OPERATING ACTIVITIES:

<S>                                                                                                     <C>             <C>
   Net Income (Loss)                                                                                    $  440          $(169)
   Plus:  Discontinued Operations                                                                            9            (22)
   Net Income from Continuing Operations                                                                   449           (191)
   Adjustments for Noncash Items:
      Depreciation and Amortization                                                                        315            336
      Deferred Income Taxes                                                                                 27            (59)
      Deferred Investment Tax Credits                                                                       (7)            (9)
      Cumulative Effect of Accounting Changes                                                             (193)           350
      (Gain)/Loss on Sale of Assets                                                                        (36)            -
      Mark to Market of Risk Management Contracts                                                           69            158
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                                           (834)          (796)
      Fuel, Materials and Supplies                                                                         165            101
      Accrued Utility Revenues                                                                             (48)           (51)
      Prepayments and Other                                                                                (74)           (49)
      Accounts Payable                                                                                     905             43
      Taxes Accrued                                                                                        196             12
      Interest Accrued                                                                                      29             94
      Rent Accrued - Rockport Plant Unit 2                                                                  37             37
   Over/Under Fuel Recovery                                                                                 74            (31)
   Change in Other Assets                                                                                 (209)          (341)
   Change in Other Liabilities                                                                             (90)           376
          Net Cash Flows From (Used For) Operating Activities                                              775            (20)

INVESTING ACTIVITIES:
  Construction Expenditures                                                                               (324)          (300)
  Proceeds from Sale of Assets                                                                              35             -
  Other                                                                                                   -               (32)
          Net Cash Flows Used For Investing Activities                                                    (289)          (332)

FINANCING ACTIVITIES:
  Issuance of Common Stock                                                                               1,177             14
  Issuance of Long-term Debt                                                                             2,525            872
  Change in Short-term Debt (net)                                                                       (2,925)           (49)
  Retirement of Long-term Debt                                                                            (509)          (295)
  Dividends Paid on Common Stock                                                                          (203)          (193)
          Net Cash Flows From Financing Activities                                                          65            349

Effect of Exchange Rate Change on Cash                                                                    -               (14)

Net Increase (Decrease) in Cash and Cash Equivalents                                                       551            (17)
Cash and Cash Equivalents at Beginning of Period                                                         1,213            224
Cash and Cash Equivalents at End of Period                                                              $1,764          $ 207
Net Decrease in Cash and Cash Equivalents from  Discontinued  Operations
                                                                                                        $   (3)         $  (9)
Cash and Cash Equivalents from Discontinued Operations -  Beginning of Period
                                                                                                             8            108
Cash and Cash Equivalents from Discontinued Operations - End  of Period
                                                                                                        $    5          $  99

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $177 million and $126
million in 2003 and 2002, respectively. There was no cash paid for income taxes
in 2003. Cash paid for income taxes in 2002 was $94 million.

See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                    AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                   (UNAUDITED)
                                  (in millions)


                                                                                                       Accumulated Other
                                                         Common      Paid-in         Retained          Comprehensive
                                                         Stock       Capital         Earnings          Income (Loss)        Total


<S>                                                         <C>          <C>               <C>               <C>            <C>
JANUARY 1, 2002                                             $2,153       $2,906            $3,296            $(126)         $8,229

Issuance of Common Stock                                         3                                                               3
Common Stock Dividends                                                                       (193)                            (193)
Other                                                                         6                 4                               10
                                                                                                                             8,049
Comprehensive Income (Loss):
  Other Comprehensive Income (Loss),
   Net of Taxes
    Foreign Currency Translation      Adjustments
                                                                                                                (6)             (6)
    Unrealized Losses on Cash Flow
      Hedges                                                                                                   (38)            (38)
  Net Loss                                                                                   (169)                            (169)
     Total Comprehensive Income (Loss)                                                                                        (213)

MARCH 31, 2002                                              $2,156       $2,912            $2,938            $(170)         $7,836



JANUARY 1, 2003                                             $2,261       $3,413            $1,999           $(609)          $7,064

Issuance of Common Stock                                       365          812                                              1,177
Common Stock Dividends                                                                       (203)                            (203)
Common Stock Expense                                                        (35)                                               (35)
Other                                                                       (15)                2                              (13)
                                                                                                                             7,990
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes
     Foreign Currency Translation           Adjustments
                                                                                                               13               13
     Unrealized Gains on Securities                                                                             1                1
     Unrealized Losses on Cash Flow       Hedges
                                                                                                              (22)             (22)
     Minimum Pension Liability                                                                                 15               15
  Net Income                                                                                  440                              440
     Total Comprehensive Income                                                                                                447

MARCH 31, 2003                                              $2,626       $4,175            $2,238           $(602)          $8,437
See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                             AEP GENERATING COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

AEGCo is engaged in the generation and wholesale sale of electric power to two
affiliates under long-term agreements. Operating revenues are derived from the
sale of Rockport Plant energy and capacity to two affiliated companies pursuant
to FERC approved long-term unit power agreements. The unit power agreements
provide for recovery of costs including a FERC approved rate of return on common
equity and a return on other capital net of temporary cash investments.

Results of Operations
Net Income declined $97 thousand or 5% for the first quarter of 2003 as a result
of terms in the unit power agreements which limits recovery of return on capital
related to operating and in-service ratios of the Rockport Plant calculated and
adjusted monthly.

Changes in Operating Revenues
An increase in Operating Revenues of $10.6 million resulted from an increase in
recoverable expenses, primarily fuel, as generation increased 50% due to an
increase in the Rockport Plant's availability during 2003. Outages for planned
maintenance at both units decreased the Rockport Plant's generation in 2002.

Changes in Operating Expenses Operating expenses increased 22% as follows:

                                                       Increase (Decrease)
                                                   (in thousands)        %

Fuel for Electric Generation                           $12,897          74
Rent - Rockport Plant
  Unit 2                                                  -              -
Other Operation                                           (673)        (21)
Maintenance                                             (1,325)        (45)
Depreciation                                               (12)          -
Taxes Other Than Income
  Taxes                                                   (262)        (25)
Income Taxes                                              (156)        (24)
    Total Operating Expenses                           $10,469          22

Fuel for Electric Generation expense increased due to a 50% increase in
generation in 2003. Planned maintenance outages during the first quarter of 2002
reduced the Rockport Plant's availability and generation in 2002.

The decreases in Other Operation and Maintenance expenses are primarily due to
higher costs incurred during the 2002 plant outages.

The decrease in Taxes Other Than Income Taxes reflects a decline in the accrual
of real and personal property tax for Indiana for the Rockport Plant, reflecting
a favorable change in the law effective March 2002.

Income Taxes attributable to operations decreased primarily due to a decrease in
pre-tax operating income and a decrease in accrued state income.

Other Changes

The increase in Nonoperating Expense reflects additional expenses related to a
construction project.


<PAGE>
<TABLE>
<CAPTION>
                             AEP GENERATING COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                                      Three Months Ended March 31,
                                                                       2003                  2002
                                                                           (in thousands)

<S>                                                                <C>                   <C>
OPERATING REVENUES                                                 $60,428               $49,875

OPERATING EXPENSES:
   Fuel for Electric Generation                                     30,397                17,500
   Rent - Rockport Plant Unit 2                                     17,071                17,071
   Other Operation                                                   2,549                 3,222
   Maintenance                                                       1,651                 2,976
   Depreciation                                                      5,621                 5,633
   Taxes Other Than Income Taxes                                       791                 1,053
   Income Taxes                                                        497                   653

           TOTAL OPERATING EXPENSES                                 58,577                48,108

OPERATING INCOME                                                     1,851                 1,767

NONOPERATING INCOME                                                      2                     2

NONOPERATING EXPENSES                                                  217                    12

NONOPERATING INCOME TAX CREDITS                                        894                   832

INTEREST CHARGES                                                       734                   696

NET INCOME                                                         $ 1,796               $ 1,893

                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                                                     Three Months Ended March 31,
                                                                       2003                   2002
                                                                            (in thousands)

BALANCE AT BEGINNING OF PERIOD                                      $18,163               $13,761

NET INCOME                                                            1,796                 1,893

CASH DIVIDENDS DECLARED                                               1,171                 1,050

BALANCE AT END OF PERIOD                                            $18,788               $14,604

The common stock of AEGCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

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


                                                            AEP GENERATING COMPANY
                                                                BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                        March 31, 2003            December 31, 2002
                                                                                                       (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                         <C>                         <C>
   Production                                                                               $638,481                    $637,095
   General                                                                                     4,643                       4,728
   Construction Work in Progress                                                              10,707                      10,390
        Total Electric Utility Plant                                                         653,831                     652,213
   Accumulated Depreciation                                                                  364,316                     358,174
           NET ELECTRIC UTILITY PLANT                                                        289,515                     294,039

OTHER PROPERTY AND INVESTMENTS                                                                   119                         119

CURRENT ASSETS:
  Accounts Receivable - Affiliated Companies                                                  21,583                      18,454
  Fuel                                                                                        18,005                      20,260
  Materials and Supplies                                                                       4,859                       4,913
  Prepayments                                                                                     73                        -
           TOTAL CURRENT ASSETS                                                               44,520                      43,627

REGULATORY ASSETS                                                                              5,701                       4,970

DEFERRED CHARGES                                                                               9,297                       6,974

           TOTAL ASSETS                                                                     $349,152                    $349,729

See Notes to Financial Statements beginning on page L-1.

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


                                                            AEP GENERATING COMPANY
                                                                BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                          March 31, 2003          December 31, 2002
                                                                                                       (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 <S>                                                                                             <C>                       <C>
  Common Stock - Par Value $1,000:
      Authorized and Outstanding - 1,000 Shares                                               $  1,000                  $  1,000
   Paid-in Capital                                                                              23,434                    23,434
   Retained Earnings                                                                            18,788                    18,163
      Total Common Shareholder's Equity                                                         43,222                    42,597
   Long-term Debt                                                                               44,804                    44,802

        TOTAL CAPITALIZATION                                                                    88,026                    87,399

OTHER NONCURRENT LIABILITIES                                                                     1,333                       301

CURRENT LIABILITIES:
   Advances from Affiliates                                                                      9,650                    28,034
   Accounts Payable:
      General                                                                                     -                           26
      Affiliated Companies                                                                      12,585                    15,907
   Taxes Accrued                                                                                 7,294                     2,327
   Rent Accrued - Rockport Plant Unit 2                                                         23,427                     4,963
   Other                                                                                           633                     1,111
        TOTAL CURRENT LIABILITIES                                                               53,589                    52,368

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT
 PLANT UNIT 2                                                                                  109,654                   111,046

REGULATORY LIABILITIES:
   Deferred Investment Tax Credit                                                               52,108                    52,943
   Amounts Due to Customers for Income Taxes                                                    16,143                    16,670
        TOTAL REGULATORY LIABILITIES                                                            68,251                    69,613

DEFERRED INCOME TAXES                                                                           28,299                    29,002

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                                  $349,152                  $349,729

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                            AEP GENERATING COMPANY
                                                           STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                           Three Months Ended March 31,
                                                                                          2003                   2002
                                                                                                 (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                    <C>                       <C>
   Net Income                                                                          $  1,796                  $  1,893
   Adjustment for Noncash Items:
     Depreciation                                                                         5,621                     5,633
     Deferred Income Taxes                                                               (1,230)                   (1,470)
     Deferred Investment Tax Credits                                                       (835)                     (835)
     Amortization of Deferred Gain on Sale and Leaseback -
       Rockport Plant Unit 2                                                             (1,392)                   (1,392)
     Deferred Property Taxes                                                             (2,329)                   (2,693)
   Changes in Certain Current Assets and Liabilities:
     Accounts Receivable                                                                 (3,129)                    1,337
     Fuel, Materials and Supplies                                                         2,309                    (1,214)
     Accounts Payable                                                                    (3,348)                   (1,221)
     Taxes Accrued                                                                        4,967                     5,529
     Rent Accrued - Rockport Plant Unit 2                                                18,464                    18,464
   Change in Other Assets                                                                (1,021)                      586
   Change in Other Liabilities                                                               554                     (545)

           Net Cash Flow From Operating Activities                                       20,427                    24,072

INVESTING ACTIVITIES - Construction Expenditures                                           (872)                   (4,282)

FINANCING ACTIVITIES:
     Change in Advances from Affiliates (net)                                           (18,384)                  (15,511)
     Dividends Paid                                                                      (1,171)                   (1,050)
           Net Cash Flows Used For Financing Activities                                 (19,555)                  (16,561)

Net Increase in Cash and Cash Equivalents                                                  -                        3,229
Cash and Cash Equivalents at Beginning of Period                                           -                          983
Cash and Cash Equivalents at End of Period                                             $   -                     $  4,212

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $1,123,000 and
$1,108,000 and for income taxes was $(384,000) and $176,000 in 2003 and 2002,
respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

AEP Texas Central Company (TCC), formerly known as Central Power and Light
Company (CPL), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in southern Texas. TCC sells
electric power to utilities, municipalities, rural electric cooperatives and
beginning in 2002 to retail electric providers (REPs) in Texas.

Wholesale risk management activities are conducted on TCC's behalf by AEPSC.
TCC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas where TCC operates.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TCC submitted a plan for separation that was subsequently approved by the
PUCT. TCC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
CPL and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy CPL provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat rates.
Mutual Energy CPL, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TCC), was sold in December 2002.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TCC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TCC service territory. As a result of the provision of retail electric service
by REPs, effective January 1, 2002, TCC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TCC's sales as further described below under
"Results of Operations."

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 with Mutual Energy CPL
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.

Results of Operations
In 2003 Net Income increased $40 million or 164% driven by a $56 million ($36
million, net of tax) increase in revenues associated with recognition of
stranded costs in Texas, and a $5.0 million ($3.2 million, net of tax) increase
in profits on derivative contracts.

Changes in Operating Revenues

                                                        Increase (Decrease)
                                                      (in millions)     %

         Electric Generation                            $166.4        198
         Electric Transmission and  Distribution
                                                         124.9        346
         Sales to AEP Affiliates                        (141.9)       (89)
              Total Operating Revenues                  $149.4         54


In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above, and increased MWH sales at higher prices, and increased
revenues from ERCOT of $77 million. These revenues were offset in part by a
decrease in average electric rates, as 2002 included a transition period which
included fuel revenue collections from retail customers; and a reduction of $27
million resulting from a provision for rate refund (see Note 5).

Additionally, delivery charges provided to Mutual Energy CPL are classified as
Sales to AEP Affiliates in 2002, whereas in 2003 they are classified as
Electricity Transmission and Distribution revenue. Actual delivered MWHs
increased in 2003. Revenues for 2003 include $56 million of revenue associated
with recognition of stranded costs in Texas (see Note 6). Electric Transmission
and Distribution revenue also included revenues received for securitized assets
beginning in February 2002 and revenues from ERCOT for system management
services.

In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of revenues as a result of the sale of Mutual Energy CPL in December 2002,
discussed above.

Changes in Operating Expenses

                                                          Increase (Decrease)
                                                         (in millions)   %

         Fuel for Electric Generation                        $  0.3         1
         Fuel from Affiliates for Electric  Generation
                                                               11.0        40
         Purchased Electricity for Resale                      68.1       N.M.
         Purchased Electricity from AEP  Affiliates
                                                                3.6        46
         Other Operation                                        3.4         5
         Maintenance                                            5.2        47
         Depreciation and Amortization                          2.2         5
         Taxes Other Than Income Taxes                         (4.9)      (18)
         Income Taxes                                          24.0       229
              Total Operating Expenses                       $112.9        51

         N.M. = Not meaningful

The increase in total fuel expense was due to an increase in the average unit
cost of fuel offset in part by decreased MWH generation. The increase in the
average unit cost was due to gas generation as the per unit cost of gas more
than doubled from 2002 to 2003, while the actual gas MWH generation decreased
due to the mothballing of several gas plants in late 2002. Nuclear generation
decreased due to outages at the STP nuclear plant during the first quarter of
2003. See Note 7 for further information regarding the outage at the STP nuclear
plant.

The increase in total purchased electricity expense in 2003 was mainly due to
increased MWHs purchased as a result of the mothballed plants, the STP outage
and higher open market purchase prices.

Other Operation expense increased due primarily to the accretion expense for
nuclear decommissioning associated with the adoption of SFAS 143 (see Note 2). A
corresponding offsetting decrease in Depreciation and Amortization is also a
result of the adoption of SFAS 143. See Depreciation and Amortization
explanation below.

Maintenance expense increased due to an unscheduled outage at one of the nuclear
units and a refueling outage at the other nuclear unit (see Note 7).

The increase in Depreciation and Amortization is attributable to the absence in
2003 of an excess earnings favorable true-up adjustment offset in part by
reduced expense attributable to the adoption of SFAS 143, the amortization of
regulatory assets associated with the securitization during the first quarter of
2002 and decreased depreciation due to several plants mothballed during late
2002.

The decrease in Taxes Other Than Income Taxes resulted primarily from decreased
gross receipts tax, due to deregulation.

The increase in Income Taxes is due to an increase in pre-tax income.

Other Changes

Nonoperating Income increased as a result of premium payments on derivative
contracts, offset in part by decreased non-utility revenue associated with
energy related construction projects for third parties. Nonoperating Expenses
also decreased due to lower expenses associated with energy related construction
projects for third parties.

Cumulative Effect of Accounting Change

This amount represents the one-time after-tax effect of the application of EITF
02-3 (see Notes 2 and 3).


<PAGE>
<TABLE>
<CAPTION>




                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)
                                                                                                      Three Months Ended March 31,
                                                                                                         2003                 2002
                                                                                                            (in thousands)
OPERATING REVENUES:
<S>                                                                                                  <C>                  <C>
   Electric Generation                                                                               $250,377             $ 83,988
   Electric Transmission and Distribution                                                             161,006               36,060
   Sales to AEP Affiliates                                                                             16,975              158,862
           TOTAL OPERATING REVENUES                                                                   428,358              278,910

OPERATING EXPENSES:
     Fuel for Electric Generation                                                                      27,339               26,989
     Fuel from Affiliates for Electric Generation                                                      38,289               27,339
     Purchased Electricity for Resale                                                                  72,122                4,012
     Purchased Electricity from AEP Affiliates                                                         11,562                7,927
     Other Operation                                                                                   69,402               65,986
     Maintenance                                                                                       16,099               10,959
     Depreciation and Amortization                                                                     44,073               41,847
     Taxes Other Than Income Taxes                                                                     22,979               27,922
     Income Taxes                                                                                      34,483               10,484
           TOTAL OPERATING EXPENSES                                                                   336,348              223,465

OPERATING INCOME                                                                                       92,010               55,445

NONOPERATING INCOME                                                                                    10,162                9,531

NONOPERATING EXPENSES                                                                                   5,195                9,387

NONOPERATING INCOME TAX EXPENSE                                                                           558                  133

INTEREST CHARGES                                                                                         31,982             31,011

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE                                                   64,437               24,445

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX)
                                                                                                          122                 -

NET INCOME                                                                                             64,559               24,445

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                                      60                   60

EARNINGS APPLICABLE TO COMMON STOCK                                                                  $ 64,499             $ 24,385

The common stock of TCC is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)


                                                                                          Accumulated Other
                                          Common          Paid-in        Retained         Comprehensive
                                           Stock          Capital        Earnings         Income (Loss)          Total
                                                                    (in thousands)
<S>                                         <C>            <C>                 <C>             <C>            <C>
JANUARY 1, 2002                             $168,888       $405,015            $826,197        $  -           $1,400,100
Redemption of Common Stock                  (113,596)      (272,409)                                            (386,005)
Common Stock Dividends                                                          (38,502)                         (38,502)
Preferred Stock Dividends                                                           (60)                             (60)
                                                                                                                 975,533
Comprehensive Income:
  Other Comprehensive Income                                                                      -                 -
  Net Income                                                                     24,445                           24,445
     Total Comprehensive Income                                                                                   24,445

MARCH 31, 2002                              $ 55,292       $132,606            $812,080        $  -           $  999,978



JANUARY 1, 2003                             $ 55,292       $132,606            $986,396        $(73,160)      $1,101,134
Common Stock Dividends                                                          (30,201)                         (30,201)
Preferred Stock Dividends                                                           (60)                             (60)
                                                                                                               1,070,873
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                               (1,018)          (1,018)
  Net Income                                                                     64,559                           64,559
     Total Comprehensive Income                                                                                   63,541

MARCH 31, 2003                              $ 55,292       $132,606          $1,020,694        $(74,178)      $1,134,414

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                   AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)


                                                                                                       March 31,       December 31,
                                                                                                        2003               2002
                                                                                                              (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                                  <C>                <C>
  Production                                                                                         $2,977,890         $2,903,942
  Transmission                                                                                          715,195            698,964
  Distribution                                                                                        1,305,884          1,296,731
  General                                                                                               260,834            258,386
  Construction Work in Progress                                                                         180,178            200,947
  Nuclear Fuel                                                                                          270,521            266,766
          Total Electric Utility Plant                                                                5,710,502          5,625,736
  Accumulated Depreciation and Amortization                                                           2,356,530          2,405,492
          NET ELECTRIC UTILITY PLANT                                                                  3,353,972          3,220,244

OTHER PROPERTY AND INVESTMENTS                                                                            4,219              3,977

SECURITIZED TRANSITION ASSETS                                                                           725,597            734,591

LONG-TERM RISK MANAGEMENT ASSETS                                                                         11,547              4,392

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                              32,796             85,420
  Advances to Affiliates                                                                                 18,346                -
  Accounts Receivable:
    General                                                                                             190,905            113,543
    Affiliated Companies                                                                                110,291            121,324
    Allowance for Uncollectible Accounts                                                                   (230)              (346)
  Fuel Inventory                                                                                         22,103             32,563
  Materials and Supplies                                                                                 47,220             51,593
  Accrued Utility Revenues                                                                               27,540             27,150
  Risk Management Assets                                                                                 21,395             22,493
  Prepayments and Other Current Assets                                                                    4,769              2,133
          TOTAL CURRENT ASSETS                                                                          475,135            455,873

REGULATORY ASSETS                                                                                       570,058            458,552

REGULATORY ASSETS DESIGNATED FOR OR SUBJECT TO SECURITIZATION
                                                                                                        321,156            336,444

NUCLEAR DECOMMISSIONING TRUST FUND                                                                       97,128             98,474

DEFERRED CHARGES                                                                                         88,896             43,891

                    TOTAL ASSETS                                                                     $5,647,708         $5,356,438

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)


                                                                                                       March 31,    December 31,
                                                                                                           2003          2002
                                                                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                                     <C>                <C>
CAPITALIZATION:
  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
  Accumulated Other Comprehensive Income (Loss)                                                         (74,178)           (73,160)
  Retained Earnings                                                                                   1,020,694            986,396
    Total Common Shareholder's Equity                                                                 1,134,414          1,101,134
  Preferred Stock                                                                                         5,942              5,942
  CPL - Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely
   Junior Subordinated Debentures of TCC                                                                136,250            136,250

Long-term Debt                                                                                        1,980,640          1,209,434
          TOTAL CAPITALIZATION                                                                        3,257,246          2,452,760

OTHER NONCURRENT LIABILITIES                                                                            309,028             74,572

CURRENT LIABILITIES:
  Short-term Debt - Affiliates                                                                             -               650,000
  Long-term Debt Due Within One Year                                                                    209,705            229,131
  Advances from Affiliates (net)                                                                           -               126,711
  Accounts Payable - General                                                                             81,997             72,199
  Accounts Payable - Affiliated Companies                                                                65,725             36,242
  Customer Deposits                                                                                       1,803                666
  Taxes Accrued                                                                                          94,315             24,791
  Interest Accrued                                                                                       24,920             51,205
  Risk Management Liabilities                                                                            28,334             19,811
  Other                                                                                                  18,142             36,698

          TOTAL CURRENT LIABILITIES                                                                     524,941          1,247,454

DEFERRED INCOME TAXES                                                                                 1,239,961          1,261,252

DEFERRED INVESTMENT TAX CREDITS                                                                         116,384            117,686

LONG-TERM RISK MANAGEMENT LIABILITIES                                                                     5,824              1,713

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                             194,324            201,001

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                             $5,647,708         $5,356,438

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                  AEP TEXAS CENTRAL COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                              Three Months Ended March 31,
                                                                                               2003                  2002
                                                                                                   (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                        <C>                  <C>
   Net Income                                                                              $ 64,559             $  24,445
   Adjustments to Reconcile Net Income to Net Cash Flows
    From (Used For) Operating Activities:
      Depreciation and Amortization                                                          44,073                41,847
      Deferred Income Taxes                                                                  (2,260)               (8,083)
      Deferred Investment Tax Credits                                                        (1,302)               (1,302)
      Cumulative Effect of Accounting Change                                                   (122)                 -
      Mark-to-Market of Risk Management Contracts                                             5,197                 6,466
   Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                                             (66,445)              (69,400)
      Fuel, Materials and Supplies                                                           14,833                (1,359)
      Interest Accrued                                                                      (26,285)                8,942
      Accrued Utility Revenue                                                                  (390)               (4,458)
      Accounts Payable                                                                       39,281               (28,577)
     Taxes Accrued                                                                           69,524                17,767
     Deferred Property Tax                                                                  (31,590)              (32,899)
   Change in Other Assets                                                                   (51,108)              (20,966)
   Change in Other Liabilities                                                              (15,185)              (19,726)
           Net Cash Flows From (Used For) Operating Activities                               42,780               (87,303)

INVESTING ACTIVITIES:
      Construction Expenditures                                                             (21,851)              (21,002)
      Other                                                                                    -                     -
           Net Cash Flows Used For Investing Activities                                     (21,851)              (21,002)

FINANCING ACTIVITIES:
      Change in Short-term Debt Affiliated (Net)                                           (650,000)                 -
      Issuance of Long-term Debt                                                            800,000               796,613
      Retirement of Long-term Debt                                                          (48,235)             (149,998)
      Change in Advances to/from Affiliates (Net)                                          (145,057)             (115,447)
      Retirement of Common Stock                                                               -                 (386,004)
      Dividends Paid on Common Stock                                                        (30,201)              (38,502)
      Dividends Paid on Cumulative Preferred Stock                                              (60)                  (60)
           Net Cash Flows From (Used For) Financing Activities                              (73,553)              106,602

Net Decrease in Cash and Cash Equivalents                                                   (52,624)               (1,703)
Cash and Cash Equivalents at Beginning of Period                                             85,420                10,909
Cash and Cash Equivalents at End of Period                                                 $ 32,796             $   9,206

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $55,483,000 and
$18,505,000 and for income taxes was $(22,959,000) and $18,482,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                            AEP TEXAS NORTH COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002


AEP Texas North Company (TNC), formerly known as West Texas Utilities Company
(WTU), is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power in west and central Texas. TNC
sells electric power to utilities, municipalities, rural electric cooperatives
and beginning in 2002 to retail electric providers (REPs) in Texas.

Wholesale risk management activities are conducted on TNC's behalf by AEPSC.
TNC, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

On January 1, 2002, customer choice of electricity supplier began in the
Electric Reliability Council of Texas (ERCOT) area of Texas. TNC operates in
both the ERCOT and Southwest Power Pool (SPP) regions of Texas, with the
majority of its operations being in the ERCOT territory.

Under the Texas Restructuring Legislation, each electric utility was required to
submit a plan to structurally unbundle its business into an affiliated REP, a
power generator, and a transmission and distribution utility. During the year
2000, TNC submitted a plan for separation that was subsequently approved by the
PUCT. TNC functionally separated its generation from its transmission and
distribution operations and AEP formed separate affiliated REPs, Mutual Energy
WTU and AEP Texas Commercial & Industrial Retail Limited Partnership. Mutual
Energy WTU provides default electric service to residential and small commercial
customers (customers eligible for price-to-beat rates). AEP Texas Commercial &
Industrial Retail Limited Partnership provides default electric service to large
commercial and industrial customers not eligible for price- to-beat-rates.
Mutual Energy WTU, a separate legal entity that was an AEP subsidiary (not owned
by or consolidated with TNC), was sold in December 2002.

Since REPs are the electricity suppliers to retail customers in the ERCOT area,
TNC sells its generation to the REPs and other market participants and provides
transmission and distribution services to retail customers of the REPs in the
TNC service territory. As a result of the provision of retail electric service
by REPs effective January 1, 2002, TNC no longer supplies electricity directly
to retail customers. The implementation of REPs as suppliers to retail customers
has caused a significant shift in TNC's sales as further described below under
"Results of Operations."

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 with Mutual Energy WTU
are classified as Electric Generation and delivery charges as Electric
Transmission and Distribution.

Results of Operations
In 2003, Net Income increased $5.8 million or 146% primarily due to the
cumulative effect of accounting changes and increased nonoperating results,
offset by lower Operating Income.

Changes in Operating Revenues
                                             Increase (Decrease)

                                             (in millions)            %

         Electric Generation                           $ 41.9         109
         Electric Transmission and
          Distribution                                   18.5         126
         Sales to AEP Affiliates                        (47.8)        (95)
              Total Operating Revenues                 $ 12.6          12


In 2003, Electric Generation revenues increased due to the reclassification of
energy revenues as a result of the sale of Mutual Energy WTU in December 2002,
discussed above, decreased MWH sales at higher prices and increased revenues
from ERCOT of $17 million. These revenues were offset in part by a decrease in
average electric rates, as 2002 included a transition period which included fuel
revenue collections from retail customers; and a reduction of $13 million
resulting from a provision for rate refund (see Note 5).

The increase in Electric Transmission and Distribution is primarily due to
delivery charges classified as Electric Transmission and Distribution in 2003,
whereas in 2002 they were classified as Sales to AEP Affiliates. In addition,
TNC had increased MWHs delivered in 2003 and increased revenues from ERCOT for
system management services.

In 2003, Sales to AEP Affiliates decreased primarily due to the reclassification
of energy revenues as a result of the sale of Mutual Energy WTU in December
2002, discussed above.

Changes in Operating Expenses
                                                           Increase (Decrease)

                                                          (in millions)    %

         Fuel for Electric Generation                           $  2.7      32
         Fuel from Affiliates for Electric  Generation
                                                                 (10.1)    (63)
         Purchased Electricity for Resale                         18.3     280
         Purchased Electricity from AEP  Affiliates
                                                                   7.7      66
         Other Operation                                          (3.6)    (15)
         Maintenance                                              (0.2)     (5)
         Depreciation and Amortization                            (2.1)    (18)
         Taxes Other Than Income Taxes                            (0.3)     (4)
         Income Taxes                                              1.5      50
               Total Operating Expenses                         $ 13.9      15


Net fuel for electric generation decreased due to lower MWHs generated, offset
in part by an increase in the average per unit fuel cost. TNC used coal for 91%
of its generation in 2003 since many of its gas plants were mothballed in late
2002. This higher use of coal helped lower the fuel costs in 2003.

The increase in total Purchased Electricity expense in 2003 was mainly due to
both increased MWHs purchased as a result of the mothballed plants and higher
open market purchase prices.

Other Operation expense decreased in 2003 due to lower uncollectible account
expenses and lower administrative and general expenses.

Depreciation and Amortization expense decreased due to the absence in 2003 of
excess earnings expense adjustments under Texas Restructuring Legislation and
the decrease in depreciation due to the mothballing of several power plants in
late 2002.

The increase in Income Tax Expense is primarily a result of an increase in
pre-tax income.

Other Changes

Nonoperating Income and Nonoperating Expenses increased significantly as a
result of increased non-utility revenue and expenses associated with energy
related construction projects for third parties. Additionally, Nonoperating
Income increased due to increased earnings on derivative contracts.

Interest Charges declined primarily due to lower average borrowings in 2003
versus 2002.

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 Notes 2 and 3).


<PAGE>
<TABLE>
<CAPTION>


                                                           AEP TEXAS NORTH COMPANY
                                                             STATEMENTS OF INCOME
                                                                  (UNAUDITED)

                                                                              Three Months Ended March 31,
                                                                                2003                   2002
                                                                                          (in thousands)
OPERATING REVENUES:
<S>                                                                         <C>                      <C>
   Electric Generation                                                      $ 80,369                 $ 38,437
   Electric Transmission and Distribution                                     33,124                   14,672
   Sales to AEP Affiliates                                                     2,769                   50,517
        TOTAL OPERATING REVENUES                                             116,262                  103,626

OPERATING EXPENSES:
   Fuel for Electric Generation                                               11,461                    8,714
   Fuel from Affiliates for Electric Generation                                6,085                   16,266
   Purchased Electricity for Resale                                           24,778                    6,513
   Purchased Electricity from AEP Affiliates                                  19,345                   11,650
   Other Operation                                                            20,619                   24,170
   Maintenance                                                                 4,141                    4,356
   Depreciation and Amortization                                               9,532                   11,569
   Taxes Other Than Income Taxes                                               6,033                    6,300
   Income Tax Expense                                                          4,403                    2,943
           TOTAL OPERATING EXPENSES                                          106,397                   92,481

OPERATING INCOME                                                               9,865                   11,145

NONOPERATING INCOME (LOSS)                                                    13,463                   (1,488)

NONOPERATING EXPENSES                                                         11,559                    1,372

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                         339                     (989)

INTEREST CHARGES                                                               4,665                    5,282

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES                      6,765                    3,992

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)                           3,071                     -

NET INCOME                                                                     9,836                    3,992

PREFERRED STOCK DIVIDEND REQUIREMENTS                                             26                       26

EARNINGS APPLICABLE TO COMMON STOCK                                         $  9,810                 $  3,966

The common stock of TNC is wholly owned by AEP.

See Note to Financial Statements beginning on Page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                             AEP TEXAS NORTH COMPANY
    STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                          Common          Paid-in        Retained        Income (Loss)
                                           Stock          Capital        Earnings                              Total
                                                                    (in thousands)
<S>                                         <C>              <C>               <C>             <C>              <C>
JANUARY 1, 2002                             $137,214         $2,351            $105,970        $  -             $245,535
Common Stock Dividends                                                           (6,749)                          (6,749)
Preferred Stock Dividends                                                           (26)                             (26)
                                                                                                                 238,760
Comprehensive Income:
  Other Comprehensive Income                                                                      -                 -
  Net Income                                                                      3,992                            3,992
     Total Comprehensive Income                                                                                    3,992

MARCH 31, 2002                              $137,214         $2,351            $103,187        $  -             $242,752



JANUARY 1, 2003                             $137,214         $2,351             $71,942        $(30,763)        $180,744
Common Stock Dividends                                                           (4,970)                          (4,970)
Preferred Stock Dividends                                                           (26)                             (26)
                                                                                                                 175,748
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                 (421)            (421)
    Unrealized Loss on Minimum
      Pension Liability                                                                              (7)              (7)
  Net Income                                                                      9,836                            9,836
     Total Comprehensive Income                                                                                    9,408

MARCH 31, 2003                              $137,214         $2,351            $ 76,782        $(31,191)        $185,156

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                             AEP TEXAS NORTH COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                                                    March 31, 2003          December 31, 2002
                                                                                                 (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                           <C>                      <C>
   Production                                                                                 $  354,117               $  353,087
   Transmission                                                                                  255,343                  254,483
   Distribution                                                                                  446,150                  445,486
   General                                                                                       109,200                  111,679
   Construction Work in Progress                                                                  39,991                   37,012
        Total Electric Utility Plant                                                           1,204,801                1,201,747
   Accumulated Depreciation and Amortization                                                     518,631                  521,792
       NET ELECTRIC UTILITY PLANT                                                                686,170                  679,955

OTHER PROPERTY AND INVESTMENTS                                                                     1,065                    1,213

LONG-TERM RISK MANAGEMENT ASSETS                                                                   4,433                    2,248

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                       4,681                    1,219
   Advances to Affiliates                                                                          8,460                     -
   Accounts Receivable:
      Customers                                                                                   32,776                   62,660
      Affiliated Companies                                                                        37,796                   43,632
      Allowance for Uncollectible Accounts                                                        (4,728)                  (5,041)
   Fuel Inventory                                                                                  8,916                   12,677
   Materials and Supplies                                                                         10,029                    9,574
   Accrued Utility Revenues                                                                        5,591                    6,829
   Risk Management Assets                                                                          3,411                    4,130
   Prepayments and Other                                                                           1,198                    1,070
          TOTAL CURRENT ASSETS                                                                   108,130                  136,750

REGULATORY ASSETS                                                                                 44,165                   45,097

DEFERRED CHARGES                                                                                  27,481                   11,912

          TOTAL ASSETS                                                                        $  871,444               $  877,175

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                            AEP TEXAS NORTH COMPANY
                                                                BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                 March 31, 2003            December 31, 2002
                                                                                                (in thousands)

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                                                    <C>                         <C>
   Common Stock - $25 Par Value:
      Authorized - 7,800,000 Shares
      Outstanding - 5,488,560 Shares                                                      $137,214                    $137,214
   Paid-in Capital                                                                           2,351                       2,351
   Accumulated Other Comprehensive Income (Loss)                                           (31,191)                    (30,763)
   Retained Earnings                                                                        76,782                      71,942
        Total Common Shareholder's Equity                                                  185,156                     180,744
Cumulative Preferred Stock Not Subject to
  Mandatory Redemption                                                                       2,367                       2,367
Long-term Debt                                                                             333,473                     132,500

        TOTAL CAPITZALIZATION                                                              520,996                     315,611

OTHER NONCURRENT LIABILITIES                                                                41,859                      28,861

CURRENT LIABILITIES:
   Short-term Debt - Affiliates                                                               -                        125,000
   Long-term Debt Due Within One Year                                                       24,036                        -
   Advances from Affiliates                                                                   -                         80,407
   Accounts Payable - General                                                               17,297                      32,714
   Accounts Payable - Affiliated Companies                                                  37,152                      76,217
   Customer Deposits                                                                           320                         117
   Taxes Accrued                                                                            25,425                       3,697
   Interest Accrued                                                                          4,847                       2,776
   Risk Management Liabilities                                                               4,761                       3,801
   Other                                                                                     8,237                      17,414

        TOTAL CURRENT LIABILITIES                                                          122,075                     342,143

DEFERRED INCOME TAXES                                                                      113,465                     117,521

DEFERRED INVESTMENT TAX CREDITS                                                             21,130                      21,510

LONG-TERM RISK MANAGEMENT LIABILITIES                                                        2,300                         557

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                 49,619                      50,972

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                              $871,444                    $877,175

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                            AEP TEXAS NORTH COMPANY
                                                           STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                                Three Months Ended March 31,
                                                                                               2003                    2002
                                                                                                        (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                           <C>                    <C>
 Net Income                                                                                   $  9,836               $  3,992
 Adjustments to Reconcile Net Income to Net Cash Flows
    From (Used For) Operating Activities:
    Depreciation and Amortization                                                                9,532                 11,569
    Deferred Income Taxes                                                                       (5,666)                  (226)
    Deferred Investment Tax Credits                                                               (380)                  (318)
    Cumulative Effect of Accounting Changes                                                     (3,071)                  -
    Mark-to-Market of Risk Management Contracts                                                    608                   (213)
 Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                                                 35,407                (28,456)
      Fuel, Materials and Supplies                                                               3,306                   (906)
      Accrued Utility Revenues                                                                   1,238                    474
      Accounts Payable                                                                         (54,482)                (1,423)
      Taxes Accrued                                                                             21,728                  4,205
    Fuel Recovery                                                                                 -                    (1,384)
    Deferred Property Taxes                                                                    (10,868)                (9,525)
 Change in Other Assets                                                                         (4,593)                (3,068)
 Change in Other Liabilities                                                                     4,927                 (1,033)
           Net Cash Flows From (Used For) Operating Activities                                   7,522                (26,312)

INVESTING ACTIVITIES:
      Construction Expenditures                                                                (10,197)                (7,531)
      Other                                                                                       -                      -
           Net Cash Flows Used For Investing Activities                                        (10,197)                (7,531)

FINANCING ACTIVITIES:
      Change in Short-term Debt (net)                                                         (125,000)                  -
      Issuance of Long-term Debt                                                               225,000                   -
      Change in Advances to/from Affiliates (net)                                              (88,867)                38,720
      Dividends Paid on Common Stock                                                            (4,970)                (6,749)
      Dividends Paid on Cumulative Preferred Stock                                                 (26)                   (26)
           Net Cash Flows From Financing Activities                                              6,137                 31,945

Net Increase (Decrease) in Cash and Cash Equivalents                                             3,462                 (1,898)
Cash and Cash Equivalents at Beginning of Period                                                 1,219                  2,454
Cash and Cash Equivalents at End of Period                                                   $   4,681              $     556

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,021,000 and
$2,097,000 and for income taxes was $(8,873,000) and $(1,575,000) in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

APCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 925,000 retail customers in southwestern
Virginia and southern West Virginia. APCo, as a member of the AEP Power Pool,
shares in the revenues and cost of the AEP Power Pool's wholesale sales to
neighboring utility systems and power marketing transactions. APCo also sells
wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of revenues and costs.

Results of Operations
Net Income of $156.4 million in the first quarter of 2003 included income from
the Cumulative Effect of Accounting Changes of $77.3 million (see Note 3).
Income Before Cumulative Effect of Accounting Changes increased $23.8 million or
43% primarily due to an improvement in earnings from retail and AEP Power Pool
sales resulting from the interaction of plant availability, the colder winter
weather and higher margins. APCo, as a member of the AEP Power Pool, shares in
the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool. This increase was partially offset by a decline in
Nonoperating Income.

Changes in Operating Revenues

The following analyzes the changes in operating revenues:

                                                      (in millions)           %

         Electric Generation                              $56.0              21
         Electric Transmission and
          Distribution                                      3.5               2
         Sales to AEP Affiliates                           14.1              33
              Total Operating Revenues                    $73.6              16




The increase in Operating Revenues was due primarily to higher Electric
Generation sales and Sales to AEP Affiliates reflecting the more severe winter
weather of 2003 and an increase in the volume of AEP Power Pool transactions.
Heating degree days were up 18% over the prior year which resulted in an
increase in Residential KWH sales of 16% as well as a 10% increase in total
Retail sales. Additionally, APCo's relative share of the AEP Power Pool revenues
(as well as expenses) for February and March, 2003 increased over the prior
period as a result of APCo reaching a new peak demand in January 2003.

Changes in Operating Expenses

Operating expenses increased 11% in the first quarter of 2003 over the prior
year. The changes in the components of operating expenses were:
                                                         Increase (Decrease)
                                                       (in millions)  %

         Fuel for Electric Generation                      $12.4        12
         Purchased Electricity for Resale                    3.6        27
         Purchased Electricity from AEP
          Affiliates                                        19.9        33
         Other Operation                                    (4.8)       (7)
         Maintenance                                         6.9        27
         Depreciation and Amortization                     (10.8)      (23)
         Taxes Other Than Income Taxes                       0.1         -
         Income Taxes                                       15.2        44
              Total Operating Expenses                     $42.5        11


Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as KWH generated increased 7%.
Purchased Electricity for Resale increased in the first quarter of 2003 as
Retail KWH sales outpaced net generation. Purchased Electricity from AEP
Affiliates increased due to higher charges resulting from the increased of all
volume and the increase in APCo's share of the AEP Power Pool.

The decline in Other Operation expense was primarily due to decreased
employee-related expenses in the first quarter of 2003 reflecting the
cost-saving effects of the Sustained Earnings Improvement Initiative (see Note
9).

The increase in Maintenance expense is due to increased distribution line
maintenance caused by severe winter storm damage in 2003 and increased plant
maintenance primarily at the Sporn plant.

Depreciation and Amortization expense decreased primarily due to reduced expense
attributable to the adoption of SFAS 143. Effective January 1, 2003 the
generation depreciation rate for APCo's non-regulated operations was reduced to
exclude the non-ARO removal cost portion that was included in the depreciation
rate. Additionally, APCo had reduced Depreciation and Amortization expense
related to the amortization of generation related regulatory assets over the
transition period due to the return to SFAS 71 accounting for the West Virginia
jurisdiction (see Note 6 for further discussion of the return to SFAS 71
accounting). Amortization costs of transition regulatory assets had been
accelerated since July 2000 in connection with the discontinuance of SFAS 71 in
APCo's West Virginia jurisdiction. At that time net generation-related
regulatory assets were transferred to the distribution portion of the business
commensurate with their recovery through regulated rates.

The increase in operating Income Taxes is due to an increase in pre-tax
operating book income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

The Nonoperating Income Tax Credit in 2003 reflects the tax benefits associated
with the reduction in Nonoperating Income.

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 of 02-3
(see Notes 2 and 3).


<PAGE>
<TABLE>
<CAPTION>


                                                  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                       CONSOLIDATED STATEMENTS OF INCOME
                                                                  (UNAUDITED)

                                                                    Three Months Ended March 31,
                                                                  2003                  2002
                                                                           (in thousands)
OPERATING REVENUES:
<S>                                                            <C>                      <C>
    Electric Generation                                        $323,484                 $267,475
    Electric Transmission and Distribution                      155,849                  152,324
    Sales to AEP Affiliates                                      56,895                   42,806
           TOTAL OPERATING REVENUES                             536,228                  462,605

OPERATING EXPENSES:
  Fuel for Electric Generation                                  119,865                  107,490
  Purchased Electricity for Resale                               17,118                   13,516
  Purchased Electricity from AEP Affiliates                      80,720                   60,780
  Other Operation                                                62,115                   66,959
  Maintenance                                                    32,738                   25,851
  Depreciation and Amortization                                  36,008                   46,772
  Taxes Other Than Income Taxes                                  25,079                   24,995
  Income Taxes                                                   49,901                   34,688
           TOTAL OPERATING EXPENSES                             423,544                  381,051

OPERATING INCOME                                                112,684                   81,554

NONOPERATING INCOME (LOSS)                                       (4,484)                   5,084

NONOPERATING EXPENSES                                             3,674                    3,645

NONOPERATING INCOME TAX EXPENSE (CREDIT)                         (3,733)                     264

INTEREST CHARGES                                                 29,106                   27,388

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES            79,153                   55,341

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)             77,257                     -

NET INCOME                                                      156,410                   55,341

PREFERRED STOCK DIVIDEND REQUIREMENTS                               984                      503

EARNINGS APPLICABLE TO COMMON STOCK                            $155,426                 $ 54,838


The common stock of APCo is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                                      Common       Paid-in        Retained            Income (Loss)
                                                       Stock       Capital        Earnings                                 Total
                                                                             (in thousands)


<S>                                                  <C>            <C>             <C>                <C>             <C>
JANUARY 1, 2002                                      $260,458       $715,786        $150,797           $  (340)        $1,126,701
Common Stock Dividends                                                               (30,984)                             (30,984)
Preferred Stock Dividends                                                               (361)                                (361)
Capital Stock Expense                                                    142            (142)                                -
                                                                                                                        1,095,356
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
    Unrealized Gain on Cash Flow Power Hedges
                                                                                                           143                143
  Net Income                                                                          55,341                               55,341
     Total Comprehensive Income                                                                                            55,484

MARCH 31, 2002                                       $260,458       $715,928        $174,651          $   (197)        $1,150,840



JANUARY 1, 2003                                      $260,458       $717,242        $260,439          $(72,082)        $1,166,057
Common Stock Dividends                                                               (32,066)                             (32,066)
Preferred Stock Dividends                                                               (361)                                (361)
Capital Stock Expense                                                    623            (623)                                -
SFAS 71 Reapplication                                                    162                                                  162
                                                                                                                        1,133,792
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                     (12,518)           (12,518)
  Net Income                                                                         156,410                              156,410
     Total Comprehensive Income                                                                                           143,892

MARCH 31, 2003                                       $260,458       $718,027        $383,799          $(84,600)        $1,277,684

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                                       March 31, 2003          December 31, 2002
                                                                                                  (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                      <C>                         <C>
   Production                                                                            $2,256,941                  $2,245,945
   Transmission                                                                           1,218,056                   1,218,108
   Distribution                                                                           1,964,405                   1,951,804
   General                                                                                  275,416                     272,901
   Construction Work in Progress                                                            234,995                     206,545
        Total Electric Utility Plant                                                      5,949,813                   5,895,303
   Accumulated Depreciation and Amortization                                              2,317,009                   2,424,607
        NET ELECTRIC UTILITY PLANT                                                        3,632,804                   3,470,696

OTHER PROPERTY AND INVESTMENTS                                                               53,149                      54,653

LONG-TERM RISK MANAGEMENT ASSETS                                                            130,451                     115,748

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                 10,449                       4,285
   Advances to Affiliates                                                                    87,859                        -
   Accounts Receivable:
      Customers                                                                             164,050                     132,266
      Affiliated Companies                                                                   88,948                     122,665
      Miscellaneous                                                                          29,217                      28,629
      Allowance for Uncollectible Accounts                                                   (2,596)                    (13,439)
   Fuel Inventory                                                                            39,817                      53,646
   Materials and Supplies                                                                    61,697                      59,886
   Accrued Utility Revenues                                                                   7,620                      30,948
   Risk Management Assets                                                                   135,545                      94,238
   Prepayments and Other                                                                     13,716                      13,396
        TOTAL CURRENT ASSETS                                                                636,322                     526,520

REGULATORY ASSETS                                                                           407,687                     395,553

DEFERRED CHARGES                                                                             67,273                      64,677

        TOTAL ASSETS                                                                     $4,927,686                  $4,627,847

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)


                                                                                     March 31, 2003          December 31, 2002
                                                                                                  (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                               <C>                     <C>
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
      Outstanding - 13,499,500 Shares                                                          $  260,458              $  260,458
   Paid-in Capital                                                                                718,027                 717,242
   Accumulated Other Comprehensive Income (Loss)                                                  (84,600)                (72,082)
   Retained Earnings                                                                              383,799                 260,439
        Total Common Shareowner's Equity                                                        1,277,684               1,166,057
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                                                          17,790                  17,790
      Subject to Mandatory Redemption                                                              10,860                  10,860
   Long-term Debt                                                                               1,739,210               1,738,854

           TOTAL CAPITALIZATION                                                                 3,045,544               2,933,561

OTHER NONCURRENT LIABILITIES                                                                      191,764                 173,438

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                             155,007                 155,007
   Advances from Affiliates                                                                          -                     39,205
   Accounts Payable - General                                                                     153,667                 141,546
   Accounts Payable - Affiliated Companies                                                         72,179                  98,374
   Taxes Accrued                                                                                   88,442                  29,181
   Customer Deposits                                                                               35,245                  26,186
   Interest Accrued                                                                                39,222                  22,437
   Risk Management Liabilities                                                                    118,979                  69,001
   Other                                                                                           63,607                  79,832

           TOTAL CURRENT LIABILITIES                                                              726,348                 660,769

DEFERRED INCOME TAXES                                                                             749,572                 701,801

DEFERRED INVESTMENT TAX CREDITS                                                                    33,936                  33,691

LONG-TERM RISK MANAGEMENT LIABILITIES                                                              79,901                  44,517

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                       100,621                  80,070

COMMITMENTS AND CONTINGENCIES (Note 7)

        TOTAL CAPITALIZATION AND LIABILITIES                                                   $4,927,686              $4,627,847

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                  APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                      Three Months Ended March 31,
                                                                                     2003                    2002
                                                                                         (in thousands)
OPERATING ACTIVITIES:
<S>                                                                               <C>                      <C>
   Net Income                                                                     $156,410                 $  55,341
   Adjustments for Noncash Items:
      Cumulative Effect of Accounting Changes                                      (77,257)                     -
      Depreciation and Amortization                                                 36,008                    46,800
      Deferred Income Taxes                                                          1,005                    (3,644)
      Deferred Investment Tax Credits                                                  245                    (1,098)
      Deferred Power Supply Costs (net)                                             63,837                       352
      Mark to Market of Risk Management Contracts                                    5,383                    (6,653)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                     (9,498)                  (51,419)
      Fuel, Materials and Supplies                                                  12,018                    12,659
      Accrued Utility Revenues                                                      23,328                     7,013
      Accounts Payable                                                             (14,074)                   11,456
      Taxes Accrued                                                                 59,261                    29,129
      Interest Accrued                                                              16,785                    17,516
      Incentive Plan Accrued                                                        (9,595)                   (9,362)
   Change in Operating Reserves                                                     20,095                     1,541
   Rate Stabilization Deferral                                                     (75,601)                     -
   Change in Other Assets                                                          (14,446)                   (7,043)
   Change in Other Liabilities                                                      26,114                     9,187
           Net Cash Flows From Operating Activities                                220,018                   111,775

INVESTING ACTIVITIES:
      Construction Expenditures                                                    (56,627)                  (62,685)
      Proceeds from Sale of Property and Other                                       2,264                       583
           Net Cash Flows Used For Investing Activities                            (54,363)                  (62,102)

FINANCING ACTIVITIES:
      Change in Advances From Affiliates                                          (127,064)                  (31,991)
      Dividends Paid on Common Stock                                               (32,066)                  (30,984)
      Dividends Paid on Cumulative Preferred Stock                                    (361)                     (361)
           Net Cash Flows Used For Financing Activities                           (159,491)                  (63,336)

Net Increase (Decrease) in Cash and Cash Equivalents                                 6,164                   (13,663)
Cash and Cash Equivalents at Beginning of Period                                     4,285                    13,663
Cash and Cash Equivalents at End of Period                                        $ 10,449                 $    -

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $11,191,000 and
$9,222,000 and for income taxes was $(11,498,000) and $9,593,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Columbus Southern Power Company (CSPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 689,000 retail customers in central and southern Ohio. CSPCo, as a
member of the AEP Power Pool, shares in the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utilities and power marketing
transactions. CSPCo also sells wholesale power to municipalities.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivery to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing AEP
Power Pool revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

Results of Operations

Net Income increased $32 million or 94% including a $27 million Cumulative
Effect of Accounting Changes in the first quarter of 2003 (see Note 3). Net
Income Before Cumulative Effect increased $5 million or 13% due to an
improvement in earnings from retail and AEP Power Pool sales resulting from the
interactions of plant availability, colder winter weather and higher margins.
CSPCo, as a member of the AEP Power Pool, shares in the revenues and costs of
marketing and activities conducted on its behalf by the AEP Power Pool.

Changes in Operating Revenues

The following analyzes the increase in operating revenue components:

                                                  (in millions)          %

         Electric Generation                               $20.0         10
         Electric Transmission and
          Distribution                                      11.3         10
         Sales to AEP Affiliates                            13.1        170
              Total Operating Revenues                     $44.4         14


The increase in Electric Generation was driven largely by a rise in demand due
to more severe winter weather in 2003 versus 2002. Heating degree days for the
first quarter of 2003 were up 24% from the same quarter last year which resulted
in 14% higher Residential KWH sales as well as a 5% increase in Commercial KWH
Sales.

CSPCo's share of AEP Power Pool revenues and expenses for 2003 increased over
the prior year as a result of an increase in the volume of the AEP Power Pool
sales. CSPCo's share of AEP Power Pool sales increased 5%.

Changes in Operating Expenses

Operating Expenses increased 13% in 2003. The increases in the components of
Operating Expenses were:

                                                   (in millions)          %

 Fuel for Electric Generation                       $ 6.4                 14
 Purchased Electricity for Resale                     0.5                 13
 Purchased Electricity from AEP  Affiliates
                                                     10.6                 15
 Other Operation                                      2.5                  5
 Maintenance                                          0.4                  3
 Depreciation and Amortization                        1.0                  3
 Taxes Other Than Income Taxes                        5.3                 18
 Income Taxes                                         8.1                 47
      Total Operating Expenses                      $34.8                 13


Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
13%.

Purchased Electricity from AEP Affiliates was higher due to increases in energy
purchased from the AEP Power Pool resulting from a high volume of AEP Power Pool
sales and greater capacity charges.

The increase in Taxes Other Than Income Taxes was a result of increases in
property taxes and state excise taxes.

An increase in operating Income Taxes is due to an increase in pre-tax operating
book income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

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
Notes 2 and 3).
<PAGE>
<TABLE>
<CAPTION>

                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                              Three Months Ended March 31,
                                                                         2003                    2002
                                                                            (in thousands)
OPERATING REVENUES:
<S>                                                                      <C>                   <C>
  Electric Generation                                                    $214,821              $194,824
  Electric Transmission and Distribution                                  123,616               112,324
  Sales to AEP Affiliates                                                  20,768                 7,678
           TOTAL OPERATING REVENUES                                       359,205               314,826

OPERATING EXPENSES:
  Fuel for Electric Generation                                             52,043                45,650
  Purchased Electricity for Resale                                          4,198                 3,729
  Purchased Electricity from AEP Affiliates                                82,149                71,582
  Other Operation                                                          56,385                53,861
  Maintenance                                                              14,559                14,140
  Depreciation and Amortization                                            33,737                32,736
  Taxes Other Than Income Taxes                                            35,608                30,276
  Income Taxes                                                             25,375                17,304
           TOTAL OPERATING EXPENSES                                       304,054               269,278

OPERATING INCOME                                                           55,151                45,548

NONOPERATING INCOME (LOSS)                                                 (7,015)                5,074
NONOPERATING EXPENSES                                                       1,862                 1,624
NONOPERATING INCOME TAX EXPENSE (CREDIT)                                   (5,547)                1,347
INTEREST CHARGES                                                           13,462                13,793
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES                      38,359                33,858
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)                       27,283                  -
NET INCOME                                                                 65,642                33,858

PREFERRED STOCK DIVIDEND REQUIREMENTS                                         254                   181

EARNINGS APPLICABLE TO COMMON STOCK                                      $ 65,388              $ 33,677

The common stock of CSPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on Page L-1
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                              Comprehensive
                                                  Common       Paid-in        Retained        Income (Loss)
                                                   Stock       Capital        Earnings                                 Total
                                                                         (in thousands)


<S>                                               <C>           <C>             <C>                <C>               <C>
JANUARY 1, 2002                                   $41,026       $574,369        $176,103           $  -              $791,498
Common Stock Dividends Declared                                                  (21,766)                             (21,766)
Preferred Stock Dividends Declared                                                  (175)                                (175)
Capital Stock Expense                                                253            (254)                                  (1)
                                                                                                                      769,556
Comprehensive Income:
  Other Comprehensive Income                                                                          -                  -
  Net Income                                                                      33,858                               33,858
     Total Comprehensive Income                                                                                        33,858

MARCH 31, 2002                                    $41,026       $574,622        $187,766          $   -              $803,414



JANUARY 1, 2003                                   $41,026       $575,384        $290,611          $(59,357)          $847,664
Common Stock Dividends Declared                                                  (38,311)                             (38,311)
Capital Stock Expense                                                254            (254)                                -
                                                                                                                      809,353
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                  (7,343)            (7,343)
  Net Income                                                                      65,642                               65,642
     Total Comprehensive Income                                                                                        58,299

MARCH 31, 2003                                    $41,026       $575,638        $317,688          $(66,700)          $867,652

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                                    March 31, 2003          December 31, 2002
                                                                                                      (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                            <C>                     <C>
   Production                                                                                  $1,591,772              $1,582,627
   Transmission                                                                                   413,327                 413,286
   Distribution                                                                                 1,214,588               1,208,255
   General                                                                                        155,854                 165,025
   Construction Work in Progress                                                                  106,447                  98,433
       Total Electric Utility Plant                                                             3,481,988               3,467,626
   Accumulated Depreciation and Amortization                                                    1,428,761               1,465,174
        NET ELECTRIC UTILITY PLANT                                                              2,053,227               2,002,452

OTHER PROPERTY AND INVESTMENTS                                                                     34,589                  35,759

LONG-TERM RISK MANAGEMENT ASSETS                                                                   76,680                  77,810

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                        7,968                   1,479
   Advances to Affiliates                                                                          87,460                  31,257
   Accounts Receivable:
      Customers                                                                                    55,642                  49,566
      Affiliated Companies                                                                         39,880                  54,518
      Miscellaneous                                                                                19,546                  22,005
      Allowance for Uncollectible Accounts                                                           (579)                   (634)
   Fuel                                                                                            15,757                  24,844
   Materials and Supplies                                                                          40,928                  40,339
   Accrued Utility Revenues                                                                         6,964                  12,671
   Risk Management Assets                                                                          79,692                  63,348
   Prepayments and Other                                                                            9,221                   7,308
        TOTAL CURRENT ASSETS                                                                      362,479                 306,701

REGULATORY ASSETS                                                                                 252,940                 257,682

DEFERRED CHARGES                                                                                   77,510                  72,836

        TOTAL ASSETS                                                                           $2,857,425              $2,753,240

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                               COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                   March 31, 2003          December 31, 2002
                                                                                                      (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                                                            <C>                      <C>
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 24,000,000 Shares

      Outstanding - 16,410,426 Shares                                                         $   41,026               $   41,026
   Paid-in Capital                                                                               575,638                  575,384
   Accumulated Other Comprehensive Loss                                                          (66,700)                 (59,357)
   Retained Earnings                                                                             317,688                  290,611
        Total Common Shareholder's Equity                                                        867,652                  847,664
   Long-term Debt - General                                                                      747,264                  418,626
   Long-term Debt - Affiliated Companies                                                            -                     160,000

           TOTAL CAPITALIZATION                                                                1,614,916                1,426,290

OTHER NONCURRENT LIABILITIES                                                                      92,207                   95,460

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                            168,500                   43,000
   Short-term Debt - Affiliated Companies                                                         40,000                  290,000
   Accounts Payable - General                                                                     86,989                   89,736
   Accounts Payable - Affiliated Companies                                                        45,099                   81,599
   Taxes Accrued                                                                                 123,989                  112,172
   Interest Accrued                                                                               13,692                    9,798
   Risk Management Liabilities                                                                    69,939                   46,375
   Other                                                                                          51,934                   36,790

           TOTAL CURRENT LIABILITIES                                                             600,142                  709,470

DEFERRED INCOME TAXES                                                                            448,836                  437,771

DEFERRED INVESTMENT TAX CREDITS                                                                   33,144                   33,907

LONG-TERM RISK MANAGEMENT LIABILITIES                                                             46,967                   29,926

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                       21,213                   20,416

COMMITMENTS AND CONTINGENCIES (Note 7)

           TOTAL CAPITALIZATION AND LIABILITIES                                               $2,857,425               $2,753,240

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                               COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                                  Three Months Ended March 31,
                                                                                                         (in thousands)
                                                                                                       2003          2002
OPERATING ACTIVITIES:
<S>                                                                                              <C>              <C>
   Net Income                                                                                    $  65,642        $  33,858
   Adjustments for Noncash Items:
      Cumulative Effect of Accounting Changes                                                      (27,283)            -
      Depreciation and Amortization                                                                 33,737           32,786
      Deferred Income Taxes                                                                         (3,095)            (313)
      Deferred Investment Tax Credits                                                                 (763)            (778)
      Mark to Market of Risk Management Contracts                                                   10,958           (5,849)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                                     10,966          (42,207)
      Fuel, Materials and Supplies                                                                   8,498            3,636
      Accrued Utility Revenues                                                                       5,707           (5,247)
      Accounts Payable                                                                             (39,247)           7,349
      Taxes Accrued                                                                                 11,817          (19,947)
      Interest Accrued                                                                               3,894            3,607
  Change in Other Assets                                                                            (5,740)             992
  Change in Other Liabilities                                                                        6,991            3,505
           Net Cash Flows From Operating Activities                                                 82,082           11,392

INVESTING ACTIVITIES:
      Construction Expenditures                                                                    (27,269)         (24,807)
      Proceeds from Sale of Property                                                                   190              389
           Net Cash Flows Used For Investing Activities                                            (27,079)         (24,418)

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                                                   500,000             -
      Advances from (to) Affiliates                                                                (56,203)          29,106
      Retirement of Long-term Debt                                                                (204,000)            -
      Change in Short-term Debt                                                                   (250,000)            -
      Dividends Paid on Common Stock                                                               (38,311)         (21,766)
      Dividends Paid on Cumulative Preferred Stock                                                                     (175)
           Net Cash Flows From (Used For) Financing Activities
                                                                                                   (48,514)           7,165

Net Increase (Decrease) in Cash and Cash Equivalents                                                 6,489           (5,861)
Cash and Cash Equivalents at Beginning of Period                                                     1,479           12,358
Cash and Cash Equivalents at End of Period                                                        $  7,968         $  6,497

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,219,000 and
$9,725,000 and for income taxes was ($16,019,000) and $11,198,000 in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

I&M is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 571,000 retail customers in its service
territory in northern and eastern Indiana and a portion of southwestern
Michigan. As a member of the AEP Power Pool, I&M shares the revenues and the
costs of the AEP Power Pool's wholesale sales to neighboring utilities and power
marketers. I&M also sells wholesale power to municipalities and electric
cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among the AEP
Power Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for the out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is each company's
member load ratio (MLR) which determines each company's percentage share of
revenues and costs.

Under the terms of unit power agreements, I&M purchases AEGCo's 50% share of the
2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is
an affiliate that is not a member of the AEP Power Pool. An agreement between
AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, I&M purchases 910 MW of AEGCo's 50%
share of Rockport Plant capacity. If AEP's restructuring settlement agreement
filed with the FERC becomes operative, the KPCo agreement extends until December
31, 2009 for Rockport Plant Unit 1 and until December 7, 2022 for Rockport Plant
Unit 2.

Results of Operations
Net Income Before Cumulative Effect of Accounting Change increased $20 million
or 178% due primarily to increased sales as a result of higher availability of
I&M's Cook Plant and Rockport Plant in 2003 as compared to 2002. In addition, an
improvement in earnings from retail and AEP Power Pool sales resulted from the
interaction of plant availability, the more severe winter conditions and higher
margins. I&M, as a member of the AEP Power Pool, shares in the revenues and
costs of the marketing activities conducted on its behalf by the AEP Power Pool.


<PAGE>


Changes in Operating Revenues
Operating Revenues increased 19% due primarily to higher Electric Generation
sales and Sales to AEP Affiliates reflecting the colder winter weather of 2003,
an increase in AEP Power Pool transactions shared with I&M and an increase in
sales to the AEP Power Pool. The following analyzes the increases in Operating
Revenues:
                                                (in millions)              %

         Electric Generation                                 $38.6        16
         Electric Transmission and
          Distribution                                         6.2         9
         Sales to AEP Affiliates                              21.6        46
              Total Operating Revenues                       $66.4        19


The increase in Electric Generation revenues was due to an increase in sales
reflecting a colder winter. Heating degree days were up 28% over the prior year
which resulted in an increase in Residential KWH sales of 13% as well as a 5%
increase in total retail sales. I&M's share of the AEP Power Pool revenues (as
well as expenses) during 2003 increased over the prior year as a result of an
increase in the volume of the AEP Power Pool.

Revenues from Sales to AEP Affiliates increased significantly reflecting more
power being available for sale in 2003 as one unit of the Cook Nuclear Plant was
shutdown for refueling and both units of Rockport Plant were scheduled for
planned boiler maintenance in 2002. AEP Power Pool members are 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. With the outages in 2002, I&M's
available generation increased in 2003 resulting in more power being delivered
to the AEP Power Pool.

Changes in Operating Expenses
Operating Expenses increased 12% in 2003. The changes in the components of
Operating Expenses were:

                                                         Increase (Decrease)
                                                      (in millions)       %

         Fuel for Electric Generation                     $18.9          35
         Purchased Electricity for Resale                   1.0          19
         Purchased Electricity from AEP  Affiliates
                                                           12.4          23
         Other Operation                                  (10.4)         (9)
         Maintenance                                        0.3           1
         Depreciation and Amortization                      1.9           4
         Taxes Other Than Income Taxes                     (1.4)         (8)
         Income Taxes                                      15.0         250
              Total Operating Expenses                    $37.7          12

Fuel for Electric Generation increased primarily due to an increase in
generation reflecting the plant outages in 2002.

Purchased Electricity from AEP Affiliates increased due to higher availability
of the Rockport Plant in 2002, as I&M is required to purchase a portion of
AEGCo's Rockport Plant generation under their unit power agreement. AEGCo's
share of generation at the Rockport Plant increased 50% in 2003.

Other Operation expense decreased due to cost reduction efforts instituted in
the fourth quarter of 2002 and costs incurred during the outages occurring
during the first quarter of 2002.

The decrease in Taxes Other Than Income Taxes reflects a favorable tax law
change in Indiana effective March 2002 and a lower estimate for Cook Plant's
assessed value which reduced real and personal property tax estimates on which
2003 accruals are based.

Income Taxes attributable to operations increased significantly due to an
increase in pre-tax operating income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to exit those risk management activities in areas outside of its
traditional market area.

The decrease in Nonoperating Income Tax Expense is a result of the decline in
pre-tax nonoperating income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).



<PAGE>
<TABLE>
<CAPTION>


                                                    INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                       CONSOLIDATED STATEMENTS OF INCOME
                                                                  (UNAUDITED)

                                                                  Three Months Ended March 31,
                                                                          2003                  2002
                                                                                (in thousands)
OPERATING REVENUES:
<S>                                                                           <C>                 <C>
  Electric Generation                                                         $273,008            $234,446
  Electric Transmission and Distribution                                        76,779              70,580
  Sales to AEP Affiliates                                                       68,811              47,209

           TOTAL OPERATING REVENUES                                            418,598             352,235

OPERATING EXPENSES:
  Fuel for Electric Generation                                                  73,094              54,156
  Purchased Electricity for Resale                                               6,282               5,282
  Purchased Electricity from AEP Affiliates                                     65,898              53,507
  Other Operation                                                              101,381             111,766
  Maintenance                                                                   31,367              31,043
  Depreciation and Amortization                                                 43,726              41,866
  Taxes Other Than Income Taxes                                                 16,821              18,241
  Income Taxes                                                                  21,039               6,011

           TOTAL OPERATING EXPENSES                                            359,608             321,872

OPERATING INCOME                                                                58,990              30,363

NONOPERATING INCOME                                                              3,619              17,004

NONOPERATING EXPENSES                                                           12,935              13,310

NONOPERATING INCOME TAX EXPENSE (CREDIT)                                        (4,451)               (425)

INTEREST CHARGES                                                                23,438              23,424

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE                        30,687              11,058

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF TAX)                             (3,160)               -

NET INCOME                                                                      27,527              11,058

PREFERRED STOCK DIVIDEND REQUIREMENTS                                            1,149               1,155

EARNINGS APPLICABLE TO COMMON STOCK                                           $ 26,378            $  9,903


The common stock of I&M is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                                   Common       Paid-in        Retained        Income (Loss)
                                                    Stock       Capital        Earnings                                 Total
                                                                          (in thousands)


<S>                                                <C>           <C>             <C>               <C>              <C>
JANUARY 1, 2002                                    $56,584       $733,216        $ 74,605          $(3,835)         $  860,570
Preferred Stock Dividends                                                          (1,122)                              (1,122)
Capital Stock Expense                                                  33             (33)                                -
                                                                                                                       859,448
Comprehensive Income:
  Other Comprehensive Income, Net of Taxes:
    Cash Flow Interest Rate Hedge                                                                    1,259               1,259
  Net Income                                                                       11,058                               11,058
     Total Comprehensive Income                                                                                         12,317

MARCH 31, 2002                                     $56,584       $733,249        $ 84,508          $(2,576)         $  871,765



JANUARY 1, 2003                                    $56,584       $858,560        $143,996          $(40,487)        $1,018,653
Common Stock Dividends                                                            (10,000)                             (10,000)
Preferred Stock Dividends                                                          (1,115)                              (1,115)
Capital Stock Expense                                                  34             (34)                                -
                                                                                                                     1,007,538
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                   (7,857)            (7,857)
  Net Income                                                                       27,527                               27,527
     Total Comprehensive Income                                                                                         19,670

MARCH 31, 2003                                     $56,584       $858,594        $160,374          $(48,344)        $1,027,208

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                                  March 31, 2003           December 31, 2002
                                                                                                     (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                          <C>                       <C>
   Production                                                                                $2,858,230                $2,768,463
   Transmission                                                                                 979,559                   971,599
   Distribution                                                                                 928,699                   921,835
   General (including nuclear fuel)                                                             208,856                   220,137
   Construction Work in Progress                                                                148,218                   147,924
        Total Electric Utility Plant                                                          5,123,562                 5,029,958
   Accumulated Depreciation and Amortization                                                  2,645,331                 2,568,604
             NET ELECTRIC UTILITY PLANT                                                       2,478,231                 2,461,354

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
  DISPOSAL TRUST FUNDS                                                                          870,689                   870,754

LONG-TERM RISK MANAGEMENT ASSETS                                                                 80,073                    83,265

OTHER PROPERTY AND INVESTMENTS                                                                  115,837                   120,941

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                      6,520                     3,237
   Advances to Affiliates                                                                       228,775                   191,226
   Accounts Receivable:
      Customers                                                                                  77,278                    67,333
      Affiliated Companies                                                                      131,332                   122,489
      Miscellaneous                                                                              18,401                    30,468
      Allowance for Uncollectible Accounts                                                         (574)                     (578)
   Fuel                                                                                          30,586                    32,731
   Materials and Supplies                                                                        96,875                    95,552
   Risk Management Assets                                                                        85,221                    68,148
   Prepayments and Other                                                                         16,213                    18,410
          TOTAL CURRENT ASSETS                                                                  690,627                   629,016

REGULATORY ASSETS                                                                               304,988                   348,212

DEFERRED CHARGES                                                                                 85,494                    73,649

          TOTAL ASSETS                                                                       $4,625,939                $4,587,191

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                   March 31, 2003          December 31, 2002
                                                                                                      (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                           <C>                         <C>
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 2,500,000 Shares
      Outstanding - 1,400,000 Shares                                                       $   56,584                  $   56,584
   Paid-in Capital                                                                            858,594                     858,560
   Accumulated Other Comprehensive Income (Loss)                                              (48,344)                    (40,487)
   Retained Earnings                                                                          160,374                     143,996
        Total Common Shareowner's Equity                                                    1,027,208                   1,018,653
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                                                       8,101                       8,101
      Subject to Mandatory Redemption                                                          64,945                      64,945
   Long-term Debt                                                                           1,333,013                   1,587,062

           TOTAL CAPITALIZATION                                                             2,433,267                   2,678,761

OTHER NONCURRENT LIABILITIES:
   Asset Retirement Obligations                                                               525,116                        -
   Nuclear Decommissioning                                                                       -                        620,672
   Other                                                                                      131,140                     138,965

           TOTAL OTHER NONCURRENT LIABILITIES                                                 656,256                     759,637

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                                                         285,000                      30,000
   Accounts Payable:
      General                                                                                 108,331                     125,048
      Affiliated Companies                                                                     60,845                      93,608
   Taxes Accrued                                                                               90,725                      71,559
   Interest Accrued                                                                            25,786                      21,481
   Obligations Under Capital Leases                                                             6,258                       8,229
   Risk Management Liabilities                                                                 73,799                      48,568
   Other                                                                                       95,692                      92,822

           TOTAL CURRENT LIABILITIES                                                          746,436                     491,315

DEFERRED INCOME TAXES                                                                         326,438                     356,197

DEFERRED INVESTMENT TAX CREDITS                                                                95,874                      97,709

DEFERRED GAIN ON SALE AND LEASEBACK -
 ROCKPORT PLANT UNIT 2                                                                         72,958                      73,885

LONG-TERM RISK MANAGEMENT LIABILITIES                                                          48,402                      32,261

DEFERRED CREDITS AND REGULATORY LIABILITIES                                                   246,308                      97,426

CONTINGENCIES (Note 7)

                TOTAL CAPITALIZATION AND LIABILITIES                                       $4,625,939                  $4,587,191

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                                                INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                                 Three Months Ended March 31,
                                                                                                   2003                  2002
                                                                                                         (in thousands)
OPERATING ACTIVITIES:
<S>                                                                                            <C>                     <C>
   Net Income                                                                                  $ 27,527                $  11,058
   Adjustments for Noncash Items:
      Cumulative Effect of Accounting Change                                                      3,160                     -
      Depreciation and Amortization                                                              43,726                   42,184
      Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)
                                                                                                  9,410                  (24,130)
      Unrecovered Fuel and Purchased Power Costs                                                  9,375                    9,375
      Amortization of Nuclear Outage Costs                                                       10,000                   10,000
      Deferred Income Taxes                                                                     (12,367)                  (7,132)
      Deferred Investment Tax Credits                                                            (1,835)                  (1,845)
      Mark-to-Market of Risk Management Contracts                                                10,543                   (3,708)
      Deferred Property Taxes                                                                    (9,116)                  (8,409)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                                  (6,725)                 (58,316)
      Fuel, Materials and Supplies                                                                  822                    5,522
      Accounts Payable                                                                          (49,480)                 (10,779)
      Taxes Accrued                                                                              19,166                   21,391
      Rent Accrued - Rockport Plant Unit 2                                                       18,464                   18,464
   Change in Other Assets                                                                        21,178                    8,328
   Change in Other Liabilities                                                                  (13,679)                     675
           Net Cash Flows From Operating Activities                                              80,169                   12,678

INVESTING ACTIVITIES:
      Construction Expenditures                                                                 (28,234)                 (26,398)
      Other                                                                                          12                     -
           Net Cash Flows Used For Investing Activities                                         (28,222)                 (26,398)

FINANCING ACTIVITIES:
      Change in Advances from (to) Affiliates (net)                                             (37,549)                   8,887
      Dividends Paid on Common Stock                                                            (10,000)                    -
      Dividends Paid on Cumulative Preferred Stock                                               (1,115)                  (1,122)
           Net Cash Flows From (Used For) Financing Activities                                  (48,664)                   7,765

Net Increase (Decrease) in Cash and Cash Equivalents                                              3,283                   (5,955)
Cash and Cash Equivalents at Beginning of Period                                                  3,237                   16,804
Cash and Cash Equivalents at End of Period                                                     $  6,520                $  10,849

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $18,211,000 and
$15,090,000 and for income taxes was $20,011,000 and $(470,000) in 2003 and
2002, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

KPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power serving 174,000 retail customers in eastern
Kentucky. KPCo as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to neighboring utility systems and
power marketing transactions. KPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for their out-of-pocket costs of energy delivered
to the AEP Power Pool and charged for energy received from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve-month peak demand
relative to the total peak demand of all member companies as a basis for sharing
revenues and costs. The result of this calculation is the member load ratio
(MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

KPCo has a unit power agreement with AEGCo, an affiliated company, which expires
in 2004. The agreement provides for KPCo to purchase 15% of the total output of
the two unit 2,600-mw capacity Rockport Plant. Under the unit power agreement,
there is a demand charge for the right to receive the power, which is payable
even if the power is not taken. The amount of the demand charge is such that
when added to other amounts received by AEGCo, it will enable AEGCo to recover
all its fixed expenses including a FERC-approved rate of return on common
equity.

Results of Operations
Net Income of $9.9 million in the first quarter of 2003 included a loss from the
Cumulative Effect of Accounting Change of $1.1 million due to the adoption of
EITF 02-3. Income Before Cumulative Effect of Accounting Change increased $0.8
million or 8% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interaction of plant availability, the more
severe winter weather and higher margins in 2003 versus 2002. KPCo, a member of
the Power Pool, shares in the revenues and costs of marketing and activities
conducted on its behalf by the AEP Power Pool.
Changes in Operating Revenues

The following analyzes the increase in operating revenues:

                                                   (in millions)          %

  Electric Generation                                  $10.3                17
  Electric Transmission and  Distribution                0.5                 2
  Sales to AEP Affiliates                                2.1                35
       Total Operating Revenues                        $12.9                13
The increase in Operating Revenues is due to an increase in residential sales
reflecting increased demand due to the more severe weather in 2003 versus 2002
and higher volume in the AEP Power Pool of transactions. Heating degree days
were up approximately 18% resulting in a 12% increase in Residential KWH sold.
This increase was partially offset by reduced industrial sales reflecting the
slowdown in the economy. Overall retail sales were up 3% over 2002.

Changes in Operating Expenses

Changes in the components of Operating Expenses were:

                                                          Increase (Decrease)
                                                         (in millions)   %

         Fuel for Electric Generation                      $(3.8)       (18)
         Purchased Electricity from AEP  Affiliates          8.5         29
         Other Operation                                    (0.2)        (2)
         Maintenance                                         2.2         49
         Depreciation and Amortization                       0.5          6
         Taxes Other Than Income Taxes                       0.2         11
         Income Taxes                                        1.2         22
              Total Operating Expenses                     $ 8.6         10

Fuel for Electric Generation decreased due to unplanned outages in 2003 at
KPCo's Big Sandy Plant resulting in a 26% decline in net generation. Purchased
Electricity from AEP Affiliates increased primarily to support Electric
Generation sales. Increased purchases of electricity from the Rockport Plant,
which had been in an outage during the first quarter of 2002, also contributed
to the increased expense.

Maintenance expense increased primarily due to distribution line maintenance
resulting from a major ice storm in February 2003. A three week outage at the
Big Sandy plant also contributed to increased Maintenance expenses.

The increase in operating Income Taxes is due to an increase in pre-tax
Operating Income.

Other Changes

The decrease in Nonoperating Income is due to lower margins for power sold
outside of AEP's traditional marketing area reflecting reduced demand and AEP's
plan to reduce those types of transactions.

The increase in Nonoperating Income Tax Credits reflects the tax benefits
associated with the reduction in Nonoperating Income.

Cumulative Effect of Accounting Change

The Cumulative Effect of Accounting Change is due to the implementation of the
requirements of EITF 02-3 (see Notes 2 and 3).



<PAGE>
<TABLE>
<CAPTION>


                             KENTUCKY POWER COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                             Three Months Ended March 31,
                                                                    2003          2002
                                                                                 (in thousands)

OPERATING REVENUES:
<S>                                                                    <C>                <C>
  Electric Generation                                                  $ 69,165           $ 58,887
  Electric Transmission and Distribution                                 34,794             34,276
  Sales to AEP Affiliates                                                 8,135              6,022

           TOTAL OPERATING REVENUES                                     112,094             99,185

OPERATING EXPENSES:
  Fuel for Electric Generation                                           17,947             21,767
  Purchased Electricity from AEP Affiliates                              37,395             28,941
  Other Operation                                                        12,137             12,351
  Maintenance                                                             6,765              4,549
  Depreciation and Amortization                                           8,712              8,257
  Taxes Other Than Income Taxes                                           2,365              2,135
  Income Taxes                                                            6,939              5,701

           TOTAL OPERATING EXPENSES                                      92,260             83,701

OPERATING INCOME                                                         19,834             15,484

NONOPERATING INCOME (LOSS)                                               (2,415)             1,642

NONOPERATING EXPENSES                                                       232                570

NONOPERATING INCOME TAX CREDIT                                              558                190

INTEREST CHARGES                                                          6,724              6,500

INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE                     11,021             10,246

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF  TAX)                     (1,134)              -

NET INCOME                                                             $  9,887           $ 10,246

The common stock of KPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                             KENTUCKY POWER COMPANY
  STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (UNAUDITED)

                                                                                               Accumulated Other
                                                                                                Comprehensive
                                                    Common       Paid-in        Retained        Income (Loss)
                                                     Stock       Capital        Earnings                                 Total
                                                                           (in thousands)


<S>                                                 <C>           <C>              <C>               <C>               <C>
JANUARY 1, 2002                                     $50,450       $158,750         $48,833           $(1,903)          $256,130
Common Stock Dividends                                                              (7,044)                              (7,044)
                                                                                                                        249,086
Comprehensive Income:
  Other Comprehensive Income, Net of    Taxes:
    Unrealized Gain on Cash Flow Power
     Hedges                                                                                              516                516
  Net Income                                                                        10,246                               10,246
     Total Comprehensive Income                                                                                          10,762

MARCH 31, 2002                                      $50,450       $158,750         $52,035           $(1,387)          $259,848



JANUARY 1, 2003                                     $50,450       $208,750         $48,269           $(9,451)          $298,018
Common Stock Dividends                                                              (5,482)                              (5,482)
                                                                                                                        292,536
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                    (2,865)            (2,865)
  Net Income                                                                         9,887                                9,887
     Total Comprehensive Income                                                                                           7,022

MARCH 31, 2003                                      $50,450       $208,750         $52,674          $(12,316)          $299,558

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                  KENTUCKY POWER COMPANY
                                      BALANCE SHEETS
                                           (UNAUDITED)


                                                                                   March 31, 2003          December 31, 2002
                                                                                                      (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                           <C>                      <C>
   Production                                                                                 $  284,401               $  275,121
   Transmission                                                                                  374,120                  373,639
   Distribution                                                                                  415,725                  414,281
   General                                                                                        67,296                   67,449
   Construction Work in Progress                                                                 179,635                  165,129
        Total Electric Utility Plant                                                           1,321,177                1,295,619
   Accumulated Depreciation and Amortization                                                     396,014                  397,304
          NET ELECTRIC UTILITY PLANT                                                             925,163                  898,315

OTHER PROPERTY AND INVESTMENTS                                                                     6,585                    6,904

LONG-TERM RISK MANAGEMENT ASSETS                                                                  29,686                   29,871

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                       1,465                    2,304
   Accounts Receivable:
      Customers                                                                                   25,156                   22,044
      Affiliated Companies                                                                        13,692                   23,802
      Miscellaneous                                                                                3,254                    2,889
      Allowance for Uncollectible Accounts                                                          (563)                    (192)
   Fuel                                                                                           12,158                   10,817
   Materials and Supplies                                                                         16,125                   16,127
   Accrued Utility Revenues                                                                        6,529                    5,301
   Accrued Tax Benefit                                                                              -                       1,253
   Risk Management Assets                                                                         30,853                   24,320
   Prepayments and Other                                                                           2,110                    2,127
          TOTAL CURRENT ASSETS                                                                   110,779                  110,792

REGULATORY ASSETS                                                                                102,689                  101,976

DEFERRED CHARGES                                                                                  16,084                   16,818

          TOTAL ASSETS                                                                        $1,190,986               $1,164,676

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                            KENTUCKY POWER COMPANY
                                                                BALANCE SHEETS
                                                                  (UNAUDITED)


                                                                                March 31, 2003          December 31, 2002
                                                                                                  (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                                                        <C>                    <C>
CAPITALIZATION:
 Common Stock - $50 Par Value:
      Authorized - 2,000,000 Shares
      Outstanding - 1,009,000 Shares                                                       $   50,450             $   50,450
 Paid-in Capital                                                                              208,750                208,750
 Accumulated Other Comprehensive Income (Loss)                                                (12,316)                (9,451)
 Retained Earnings                                                                             52,674                 48,269
        Total Common Shareowner's Equity                                                      299,558                298,018
 Long-term Debt                                                                               391,665                391,632
 Long-term Debt - Affiliated Companies                                                         60,000                 60,000

           TOTAL CAPITALIZATION                                                               751,223                749,650

OTHER NONCURRENT LIABILITIES                                                                   27,220                 27,319

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year
    - Affiliated Companies                                                                     15,000                 15,000
   Advances from Affiliates                                                                    46,071                 23,386
   Accounts Payable:
      General                                                                                  40,294                 46,515
      Affiliated Companies                                                                     25,052                 44,035
   Customer Deposits                                                                           10,345                  8,048
   Interest Accrued                                                                             7,987                  6,471
   Accrued Taxes                                                                                8,679                   -
   Risk Management Liabilities                                                                 27,076                 17,803
   Other                                                                                       10,351                 14,322

           TOTAL CURRENT LIABILITIES                                                          190,855                175,580

DEFERRED INCOME TAXES                                                                         179,059                178,313

DEFERRED INVESTMENT TAX CREDITS                                                                 8,871                  9,165

LONG-TERM RISK MANAGEMENT LIABILITIES                                                          18,183                 11,488

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                    15,575                 13,161

COMMITMENTS AND CONTINGENCIES (Note 7)

           TOTAL CAPITALIZATION AND LIABILITIES                                            $1,190,986             $1,164,676

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                            KENTUCKY POWER COMPANY
                                                           STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)


                                                                                            Three Months Ended March 31,
                                                                                                  2003             2002
                                                                                                     (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                                  <C>                   <C>
   Net Income                                                                                        $  9,887              $ 10,246
   Adjustments for Noncash Items:
      Cumulative Effect of Accounting Change                                                            1,134                  -
      Depreciation and Amortization                                                                     8,712                 8,257
      Deferred Income Taxes                                                                             2,766                  (556)
      Deferred Investment Tax Credits                                                                    (294)                 (295)
      Deferred Fuel Costs (net)                                                                          (388)                1,542
      Mark-to-Market of Risk Management Contracts                                                       3,500                (1,858)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                                         7,004               (14,598)
      Fuel, Materials and Supplies                                                                     (1,339)               (1,759)
      Accrued Utility Revenues                                                                         (1,228)               (2,921)
      Accounts Payable                                                                                (25,204)                5,618
      Taxes Accrued                                                                                     9,932                 1,710
   Change in Other Assets                                                                                (474)                4,997
   Change in Other Liabilities                                                                          2,765                   435
           Net Cash Flows From Operating Activities                                                    16,773                10,818

INVESTING ACTIVITIES:
  Construction Expenditures                                                                           (35,025)              (15,898)
  Proceeds from Sales of Property and Other                                                               210                  -
           Net Cash Flow Used for Investing Activities                                                (34,815)              (15,898)

FINANCING ACTIVITIES:
  Change in Advances from Affiliates (net)                                                             22,685                10,594
  Dividends Paid                                                                                       (5,482)               (7,044)
           Net Cash Flows From Financing Activities                                                    17,203                 3,550

Net Decrease in Cash and Cash Equivalents                                                                (839)               (1,530)
Cash and Cash Equivalents at Beginning of Period                                                        2,304                 1,947
Cash and Cash Equivalents at End of Period                                                           $  1,465              $    417

Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $7,975,000 and $6,328,000
in 2003 and 2002, respectively. Cash paid (received) for income taxes was
$(6,435,000) and $3,053,000 in 2003 and 2002, respectively. Noncash acquisitions
under capital leases were $22,000 in 2002.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




                               OHIO POWER COMPANY
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Ohio Power Company (OPCo) is a public utility engaged in the generation, sale,
purchase, transmission and distribution of electric power to approximately
702,000 customers in the northwestern, east central, eastern and southern
sections of Ohio. As a member of the AEP Power Pool, OPCo shares in the revenues
and the costs of the AEP Power Pool's wholesale sales to neighboring utilities
and power marketing transactions. OPCo also sells wholesale power to Wheeling
Power Company, municipalities and electric cooperatives.

The cost of the AEP Power Pool's generating capacity is allocated among the Pool
members based on their relative peak demands and generating reserves through the
payment of capacity charges and the receipt of capacity credits. AEP Power Pool
members are also compensated for the out-of-pocket costs of energy delivered to
the AEP Power Pool and charged for energy received from the AEP Power Pool. The
AEP Power Pool calculates each company's prior twelve month peak demand relative
to the total peak demand of all member companies as a basis for sharing revenues
and costs. The result of this calculation is the member load ratio (MLR) which
determines each company's percentage share of AEP Power Pool revenues and costs.

Results of Operations
Net Income for the first quarter of 2003 increased $129 million or 201% compared
to the same quarter last year. This increase was due primarily to a $125 million
Cumulative Effect of Accounting Changes in the first quarter of 2003 (see Note
3). Net Income Before Cumulative Effect of Accounting Changes increased $4
million or 7% primarily due to an improvement in earnings from retail and AEP
Power Pool sales resulting from the interactions of plant availability, the
colder weather and higher margins. OPCo, as a member of the Power Pool, shares
in the revenues and costs of marketing and activities conducted on its behalf by
the AEP Power Pool.

Changes in Operating Revenues

The following analyzes the increases in operating revenue components:
                                                         (in millions)     %

         Electric Generation                                 $35.1          13
         Electric Transmission and  Distribution
                                                               4.8           3
         Sales to AEP Affiliates                              30.1          27
                 Total Operating Revenues                    $70.0          13


The increase in Operating Revenues is due to a rise in revenue from Electric
Generation and Sales to AEP Affiliates. The increase was driven largely by an
increased demand due to more severe winter conditions in 2003 as compared to
2002, and an increase in the volume of AEP Power Pool transactions. Heating
degree days were up 25% over the prior year which resulted in 13% higher
residential KWH sales. OPCo's share of the AEP Power Pool revenues and expenses
for first quarter 2003 increased over the prior year as a result of an increase
in the overall volume of the AEP Power Pool. OPCo's share of AEP Power Pool
sales increased 19%.

Changes in Operating Expenses

Operating Expenses increased 13% in 2003. The changes in the components of
Operating Expenses were:

                                                            Increase (Decrease)
                                                       (in millions)        %

         Fuel for Electric Generation                           $11.3       8
         Purchased Electricity for Resale                         1.8      10
         Purchased Electricity from AEP  Affiliates
                                                                  8.5      60
         Other Operation                                          2.9       3
         Maintenance                                              6.5      22
         Depreciation and Amortization                           (1.1)     (2)
         Taxes Other Than Income Taxes                            1.3       3
         Income Taxes                                            23.6      67
              Total Operating Expenses                          $54.8      13


Fuel for Electric Generation increased in the first quarter of 2003 to meet the
demand of the higher Electric Generation sales as net KWH generation increased
30%. Purchased Electricity for Resale increased due to the 4% increase in KWH
purchased to meet demand. Purchased Electricity from AEP Affiliates increased as
a result of additional MWH purchases and increased prices.

Maintenance expense increased primarily due to an increase in boiler plant
maintenance and distribution line maintenance caused by severe storm damage in
2003.

The increase in operating Income Taxes is due to an increase in pre-tax
operating book income and federal income tax adjustments.

Other Changes

The decrease in Nonoperating Income (Loss) is due to lower margins for power
sold outside of AEP's traditional marketing area reflecting reduced demand and
AEP's plan to reduce those types of transactions.

Nonoperating Expenses increased predominately as a result of costs incurred
related to the sale of our Switch Water Heater program. The decrease in
Nonoperating Income Tax Expense (Credit) is due to a decrease in pre-tax
nonoperating book income.

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
Notes 2 and 3).



<PAGE>
<TABLE>
<CAPTION>


                               OHIO POWER COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                                              Three Months Ended March 31,
                                                                         2003                    2002
                                                                              (in thousands)
OPERATING REVENUES:
<S>                                                                           <C>                   <C>
  Electric Generation                                                         $305,035              $269,978
  Electric Transmission and Distribution                                       145,852               141,040
  Sales to AEP Affiliates                                                      139,744               109,634
           TOTAL OPERATING REVENUES                                            590,631               520,652

OPERATING EXPENSES:
  Fuel for Electric Generation                                                 153,648               142,336
  Purchased Electricity for Resale                                              19,392                17,629
  Purchased Electricity from AEP Affiliates                                     22,783                14,227
  Other Operation                                                               92,981                90,114
  Maintenance                                                                   35,457                28,988
  Depreciation and Amortization                                                 61,551                62,621
  Taxes Other Than Income Taxes                                                 47,155                45,839
  Income Taxes                                                                  58,794                35,182
           TOTAL OPERATING EXPENSES                                            491,761               436,936

OPERATING INCOME                                                                98,870                83,716

NONOPERATING INCOME (LOSS)                                                      (3,811)               12,925
NONOPERATING EXPENSES                                                           10,623                 7,407
NONOPERATING INCOME TAX EXPENSE (CREDIT)                                        (4,656)                3,722
INTEREST CHARGES                                                                20,742                21,461
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES                           68,350                64,051
CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)                           124,632                  -
NET INCOME                                                                     192,982                64,051

PREFERRED STOCK DIVIDEND REQUIREMENTS                                              314                   314

EARNINGS APPLICABLE TO COMMON STOCK                                           $192,668              $ 63,737

The common stock of OPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

                               OHIO POWER COMPANY
       STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                               Common       Paid-in        Retained        Income (Loss)
                                                Stock       Capital        Earnings                                 Total
                                                                      (in thousands)


<S>                                           <C>            <C>             <C>               <C>              <C>
JANUARY 1, 2002                               $321,201       $462,483        $401,297          $   (196)        $1,184,785
Common Stock Dividends                                                        (32,582)                             (32,582)
Preferred Stock Dividends                                                        (314)                                (314)
                                                                                                                 1,151,889
Comprehensive Income:
  Other Comprehensive Income (Loss)                                                                (201)              (201)
  Net Income                                                                   64,051                               64,051
     Total Comprehensive Income                                                                                     63,850

MARCH 31, 2002                                $321,201       $462,483        $432,452          $   (397)        $1,215,739



JANUARY 1, 2003                               $321,201       $462,483        $522,316          $(72,886)        $1,233,114
Common Stock Dividends                                                        (41,934)                             (41,934)
Preferred Stock Dividends                                                        (314)                                (314)
                                                                                                                 1,190,866
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                               (4,115)            (4,115)
  Net Income                                                                  192,982                              192,982
     Total Comprehensive Income                                                                                    188,867

MARCH 31, 2003                                $321,201       $462,483        $673,050          $(77,001)        $1,379,733

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                               OHIO POWER COMPANY
                                 BALANCE SHEETS
                                           (UNAUDITED)

                                                                                     March 31, 2003          December 31, 2002
                                                                                                       (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                             <C>                    <C>
   Production                                                                                   $3,135,098             $3,116,825
   Transmission                                                                                    907,021                905,829
   Distribution                                                                                  1,122,732              1,114,600
   General                                                                                         227,014                260,153
   Construction Work in Progress                                                                   307,842                288,419
        Total Electric Utility Plant                                                             5,699,707              5,685,826
   Accumulated Depreciation and Amortization                                                     2,331,793              2,566,828
          NET ELECTRIC UTILITY PLANT                                                             3,367,914              3,118,998

OTHER PROPERTY AND INVESTMENTS                                                                      58,084                 61,686

LONG-TERM RISK MANAGEMENT ASSETS                                                                   101,736                103,230

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                        32,412                  5,285
   Accounts Receivable:
      Customers                                                                                    112,495                 95,100
      Affiliated Companies                                                                          98,926                124,244
      Miscellaneous                                                                                 25,567                 19,281
      Allowance for Uncollectible Accounts                                                            (898)                  (909)
   Fuel                                                                                             75,920                 87,409
   Materials and Supplies                                                                           83,327                 85,379
   Risk Management Assets                                                                          114,581                 92,108
   Prepayments and Other                                                                            36,370                 12,083
          TOTAL CURRENT ASSETS                                                                     578,700                519,980

REGULATORY ASSETS                                                                                  549,421                568,641

DEFERRED CHARGES AND OTHER ASSETS                                                                  126,564                 84,497

          TOTAL ASSETS                                                                          $4,782,419             $4,457,032

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                                              OHIO POWER COMPANY
                                                                BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                    March 31, 2003          December 31, 2002
                                                                                                (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                                                            <C>                     <C>
CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 40,000,000 Shares
      Outstanding - 27,952,473 Shares                                                          $  321,201              $  321,201
   Paid-in Capital                                                                                462,483                 462,483
   Accumulated Other Comprehensive Income (Loss)                                                  (77,001)                (72,886)
   Retained Earnings                                                                              673,050                 522,316
        Total Common Shareholder's Equity                                                       1,379,733               1,233,114
   Cumulative Preferred Stock:
      Not Subject to Mandatory Redemption                                                          16,648                  16,648
      Subject to Mandatory Redemption                                                               8,850                   8,850
   Long-term Debt                                                                               1,175,676                 917,649

           TOTAL CAPITALIZATION                                                                 2,580,907               2,176,261

OTHER NONCURRENT LIABILITIES                                                                      237,011                 227,689

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year - General                                                    89,665                  89,665
   Long-term Debt Due Within One Year - Affiliated         Companies
                                                                                                   60,000                  60,000
   Short-term Debt - Affiliated Companies                                                            -                    275,000
   Advances from Affiliates                                                                       239,328                 129,979
   Accounts Payable - General                                                                     139,007                 170,563
   Accounts Payable - Affiliated Companies                                                         68,551                 145,718
   Customer Deposits                                                                               19,994                  12,969
   Taxes Accrued                                                                                  165,222                 111,778
   Interest Accrued                                                                                24,644                  18,809
   Obligations Under Capital Leases                                                                10,348                  14,360
   Risk Management Liabilities                                                                     93,511                  61,839
   Other                                                                                           54,233                  80,608

           TOTAL CURRENT LIABILITIES                                                              964,503               1,171,288

DEFERRED INCOME TAXES                                                                             875,344                 794,387

DEFERRED INVESTMENT TAX CREDITS                                                                    17,986                  18,748

LONG-TERM RISK MANAGEMENT LIABILITIES                                                              62,313                  39,702

DEFERRED CREDITS                                                                                   44,355                  28,957

COMMITMENTS AND CONTINGENCIES (Note 7)

       TOTAL CAPITALIZATION AND LIABILITIES                                                    $4,782,419              $4,457,032

See Notes to Financial Statements beginning on page L-1.

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


                                                              OHIO POWER COMPANY
                                                           STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                             Three Months Ended March 31,
                                                                                      2003                  2002
                                                                                           (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                     <C>                  <C>
   Net Income                                                                           $192,982             $  64,051
   Adjustments for Noncash Items:
      Cumulative Effect of Accounting Changes                                           (124,632)                 -
      Depreciation and Amortization                                                       61,551                62,621
      Deferred Income Taxes                                                               (1,563)               (4,649)
      Deferred Property Taxes                                                             14,878                14,717
      Mark to Market of Risk Management Contracts                                         14,156               (16,055)
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                                                            1,626                (2,618)
      Fuel, Materials and Supplies                                                        13,541                (6,416)
      Accrued Utility Revenues                                                             4,429                (5,368)
      Prepayments and Other                                                              (24,288)              (11,822)
      Accounts Payable                                                                  (108,723)              (75,824)
      Customer Deposits                                                                    7,025                   509
      Taxes Accrued                                                                       53,444                21,498
      Interest Accrued                                                                     5,835                 7,171
   Other Operating Assets                                                                (54,220)                1,388
   Other Operating Liabilities                                                           (26,276)               (8,819)
           Net Cash Flows From Operating Activities                                       29,765                40,384

INVESTING ACTIVITIES:
      Construction Expenditures                                                          (56,372)              (66,312)
      Proceeds from Sale of Property and Other                                             1,633                   154
           Net Cash Flows Used For Investing Activities                                  (54,739)              (66,158)

FINANCING ACTIVITIES:
      Issuance of Long-term Debt                                                         500,000                  -
      Change in Advances to Affiliates (net)                                             109,349                89,173
      Retirement of Long-term Debt                                                      (240,000)                 -
      Changes in Short-term Debt (net)                                                  (275,000)                 -
      Dividends Paid on Common Stock                                                     (41,934)              (32,582)
      Dividends Paid on Cumulative Preferred Stock                                          (314)                 (314)
           Net Cash Flows From Financing Activities                                       52,101                56,277

Net Increase in Cash and Cash Equivalents                                                 27,127                30,503
Cash and Cash Equivalents at Beginning of Period                                           5,285                 8,848
Cash and Cash Equivalents at End of Period                                             $  32,412             $  39,351

Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $14,551,000 and
$13,900,000 and for income taxes was $(22,475,000) and $(5,574,000) in 2003 and
2002, respectively. Noncash acquisitions under capital leases were $98,000 in
2002.

See Notes to Financial Statements beginning on page L-1.
</TABLE>


                PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Public Service Company of Oklahoma (PSO) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electricity to
approximately 505,000 retail customers in eastern and southwestern Oklahoma. PSO
sells electric power to other utilities, municipalities and rural electric
cooperatives.

Wholesale power marketing activities are conducted on PSO's behalf by AEPSC.
PSO, along with the other AEP electric operating subsidiaries, shares in AEP's
electric power transactions with other utility systems and power marketers.

Results of Operations

In 2003, Net Income increased by $2.3 million primarily resulting from increased
wholesale margins and increased transmission revenues, partially offset by
higher Interest Charges.

Changes in Operating Revenues

                                                       Increase (Decrease)
                                                     (in millions)         %

Electric Generation                                           85.8           92
Electric Transmission and  Distribution
                                                               5.6           10
Sales to AEP Affiliates                                        2.3          110
    Total Operating Revenues                                 $93.7           63


Electric Generation revenues increased in 2003 as a result of increased fuel
related revenues and retained wholesale margins.

The increase in Electric Transmission & Distribution revenues is due to
increased transmission revenues, as distribution revenues were virtually flat.

Sales to AEP Affiliates increased primarily due to higher prices.

Changes in Operating Expenses

                                                       Increase (Decrease)
                                                     (in millions)         %

Fuel for Electric Generation                                 $45.1           78
Purchased Electricity for  Resale
                                                              14.8          N.M.
Purchased Electricity from AEP  Affiliates
                                                              25.2          150
Other Operation                                                5.0           19
Maintenance                                                   (4.8)         (34)
Depreciation and Amortization                                  0.6            3
Taxes Other Than Income Taxes                                  1.8           23
Income Taxes (Credits)                                         1.2           74
    Total Operating Expenses                                 $88.9           63

N.M. = Not Meaningful

The increase in Fuel for Electric Generation in 2003 was primarily due to higher
market prices for natural gas and increased MWH generation.

The increase in purchased electricity expenses was due to higher prices offset
in part by reduced MWH purchases.

Other Operation expense increased in 2003 primarily due to increased customer
related expenses and a credit posted in 2002 related to a true-up of rents
received from affiliates.

Maintenance expense decreased in 2003 largely as a result of the absence of
expenses to repair damage to overhead lines caused by a winter storm in 2002.

Taxes Other Than Income Taxes increased in 2003 primarily due to an increase in
ad valorem taxes.

Income Taxes increased in 2003 primarily due to an increase in pre-tax income.

Other Changes

Interest Charges increased due to increases in average long-term debt balances
and higher average interest rates.



<PAGE>
<TABLE>
<CAPTION>


                PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF OPERATIONS
                                   (UNAUDITED)

                                                                                            Three Months Ended March 31,
                                                                                                 2003                    2002
                                                                                                         (in thousands)
OPERATING REVENUES:
<S>                                                                                                  <C>                  <C>
  Electric Generation                                                                                $179,149             $ 93,337
  Electric Transmission and Distribution                                                               59,118               53,555
  Sales to AEP Affiliates                                                                               4,395                2,094
           TOTAL OPERATING REVENUES                                                                   242,662              148,986

OPERATING EXPENSES:
  Fuel for Electric Generation                                                                        103,174               58,097
  Purchased Electricity for Resale                                                                     12,491               (2,344)
  Purchased Electricity from AEP Affiliates                                                            42,107               16,845
  Other Operation                                                                                      31,618               26,639
  Maintenance                                                                                           9,394               14,169
  Depreciation and Amortization                                                                        21,494               20,916
  Taxes Other Than Income Taxes                                                                         9,646                7,848
  Income Taxes (Credits)                                                                                 (408)              (1,594)
           TOTAL OPERATING EXPENSES                                                                   229,516              140,576

OPERATING INCOME                                                                                       13,146                8,410

NONOPERATING INCOME                                                                                       650                  106

NONOPERATING EXPENSES                                                                                     439                  595

NONOPERATING INCOME TAX CREDIT                                                                            200                  141

INTEREST CHARGES                                                                                       12,866                9,710

NET INCOME (LOSS)                                                                                         691               (1,648)

LESS: PREFERRED STOCK DIVIDEND REQUIREMENTS                                                                53                   53

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK                                                           $    638             $ (1,701)


The common stock of PSO is owned by a wholly owned subsidiary of AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                               Common          Paid-in        Retained        Income (Loss)
                                                Stock          Capital        Earnings                              Total
                                                                         (in thousands)

<S>                                              <C>            <C>                 <C>             <C>              <C>
JANUARY 1, 2002                                  $157,230       $180,016            $142,994        $  -             $480,240
Common Stock Dividends                                                               (22,455)                         (22,455)
Preferred Stock Dividends                                                                (53)                             (53)
                                                                                                                      457,732
Comprehensive Income (Loss):
  Other Comprehensive Income                                                                           -                 -
  Net Income (Loss)                                                                   (1,648)                          (1,648)
     Total Comprehensive Income (Loss)                                                                                 (1,648)

MARCH 31, 2002                                   $157,230       $180,016            $118,838        $  -             $456,084



JANUARY 1, 2003                                  $157,230       $180,016            $116,474        $(54,473)        $399,247
Common Stock Dividends                                                                (7,500)                          (7,500)
Preferred Stock Dividends                                                                (53)                             (53)
Distribution of Investment in AEMT,  Inc.
Preferred Shares to Parent                                                              (548)                            (548)
                                                                                                                      391,146


Comprehensive Income (Loss):
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Minimum Pension Liability                                                                            (58)             (58)
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                    (1,197)          (1,197)
  Net Income                                                                             691                              691
     Total Comprehensive Income (Loss)                                                                                   (564)

MARCH 31, 2003                                   $157,230       $180,016            $109,064        $(55,728)        $390,582

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)



                                                                                     March 31, 2003          December 31, 2002
                                                                                                       (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                             <C>                      <C>
  Production                                                                                    $1,040,642               $1,040,520
  Transmission                                                                                     431,553                  432,846
  Distribution                                                                                     991,688                  990,947
  General                                                                                          200,630                  206,747
  Construction Work in Progress                                                                     95,186                   88,444
      Total Electric Utility Plant                                                               2,759,699                2,759,504
  Accumulated Depreciation and Amortization                                                      1,241,480                1,239,855
          NET ELECTRIC UTILITY PLANT                                                             1,518,219                1,519,649

OTHER PROPERTY AND INVESTMENTS                                                                       4,931                    5,383

LONG-TERM RISK MANAGEMENT ASSETS                                                                     7,484                    4,481

CURRENT ASSETS:
  Cash and Cash Equivalents                                                                         15,975                   16,774
  Accounts Receivable:
   Customers                                                                                        30,626                   31,687
   Affiliated Companies                                                                             15,939                   14,139
   Allowance for Uncollectible Accounts                                                                (54)                     (84)
  Fuel Inventory                                                                                    18,941                   19,973
  Materials and Supplies                                                                            38,178                   37,375
  Under-recovered Fuel Costs                                                                        77,701                   76,470
  Risk Management Assets                                                                             7,100                    3,841
  Prepayments and Other                                                                              3,643                    2,735
          TOTAL CURRENT ASSETS                                                                     208,049                  202,910

REGULATORY ASSETS                                                                                   25,417                   26,150

DEFERRED CHARGES                                                                                    45,755                   18,117

                    TOTAL ASSETS                                                                $1,809,855               $1,776,690


See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)


                                                                                            March 31, 2003  December 31, 2002
                                                                                                      (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                                                             <C>                      <C>
CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                                                               $  157,230               $  157,230
  Paid-in Capital                                                                                  180,016                  180,016
  Accumulated Other Comprehensive Income (Loss)                                                    (55,728)                 (54,473)
  Retained Earnings                                                                                109,064                  116,474
    Total Common Shareholder's Equity                                                              390,582                  399,247

Cumulative Preferred Stock Not Subject
  to Mandatory Redemption                                                                            5,267                    5,267
PSO-Obligated, Mandatorily Redeemable Preferred
  Securities of Subsidiary Trust Holding Solely Junior
  Subordinated Debentures of PSO                                                                    75,000                   75,000
Long-term Debt                                                                                     445,514                  445,437

          TOTAL CAPITALIZATION                                                                     916,363                  924,951

OTHER NONCURRENT LIABILITIES                                                                        54,853                   54,761

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                               100,000                  100,000
  Advances from Affiliates                                                                         119,820                   86,105
  Accounts Payable - General                                                                        74,807                   61,169
  Accounts Payable - Affiliated Companies                                                           59,616                   78,076
  Customer Deposits                                                                                 23,863                   21,789
  Taxes Accrued                                                                                     22,732                    6,854
  Interest Accrued                                                                                   9,384                    6,979
  Risk Management Liabilities                                                                        6,658                    3,260
  Other                                                                                             15,210                   24,957

          TOTAL CURRENT LIABILITIES                                                                432,090                  389,189

DEFERRED INCOME TAXES                                                                              342,529                  341,396

DEFERRED INVESTMENT TAX CREDITS                                                                     31,754                   32,201

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                         27,392                   32,611

LONG-TERM RISK MANAGEMENT LIABILITIES                                                                4,874                    1,581

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                        $1,809,855               $1,776,690


See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARY
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                          Three Months Ended March 31,
                                                                                   2003                  2002
                                                                                        (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                <C>                      <C>
   Net Income (Loss)                                                               $    691                 $ (1,648)
   Adjustments to Reconcile Net Income (Loss) to Net Cash
   Flows Used For Operating Activities:
      Depreciation and Amortization                                                  21,494                   20,916
      Deferred Income Taxes                                                           1,309                    1,886
      Deferred Investment Tax Credits                                                  (447)                    (448)
   Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                                        (769)                  (3,733)
      Fuel, Materials and Supplies                                                      229                   (1,346)
      Accounts Payable                                                               (4,822)                 (31,427)
      Taxes Accrued                                                                  15,878                    9,407
      Deferred Property Taxes                                                       (24,413)                 (21,210)
      Fuel Recovery                                                                  (1,231)                   2,380
   Changes in Other Assets                                                          (11,662)                  (7,606)
   Changes in Other Liabilities                                                      (5,606)                   4,032
           Net Cash Flows Used For Operating Activities                              (9,349)                 (28,797)

INVESTING ACTIVITIES:
  Construction Expenditures                                                         (17,612)                 (10,559)
           Net Cash Flows Used For Investing Activities                             (17,612)                 (10,559)

FINANCING ACTIVITIES:
  Change in Advances from Affiliates (net)                                           33,715                   63,910
  Dividends Paid on Common Stock                                                     (7,500)                 (22,455)
  Dividends Paid on Cumulative Preferred Stock                                          (53)                     (53)
           Net Cash Flows From Financing Activities                                  26,162                   41,402

Net Increase (Decrease) in Cash and Cash Equivalents                                   (799)                   2,046
Cash and Cash Equivalents at Beginning of Period                                     16,774                    5,795
Cash and Cash Equivalents at End of Period                                         $ 15,975                 $  7,841


Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $9,653,000 and
$5,157,000 and for income taxes was $(959,000) and $1,783,000 in 2003 and 2002,
respectively.

There was a non-cash distribution of $548,000 in preferred shares in AEMT, Inc. to PSO's Parent Company.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>




              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    FIRST QUARTER 2003 vs. FIRST QUARTER 2002

Southwestern Electric Power Company (SWEPCo) is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
approximately 437,000 retail customers in northeastern Texas, northwestern
Louisiana and western Arkansas. SWEPCo sells electric power to other utilities,
municipalities and rural electric cooperatives.

Wholesale power marketing activities are conducted on SWEPCo's behalf by AEPSC.
SWEPCo, along with the other AEP electric operating subsidiaries, shares in
AEP's electric power transactions with other utility systems and power
marketers.

Results of Operations
Net Income increased $10.8 million or 133% for the quarter. The increase
resulted primarily from the cumulative effect of accounting changes due to the
adoption of SFAS 143.

Changes in Operating Revenues

                                                        Increase (Decrease)
                                                     (in millions)       %

         Electric Generation                              $24.9          19
         Electric Transmission and  Distribution
                                                           (1.3)         (2)
         Sales to AEP Affiliates                          9.4            41
              Total Operating Revenues                    $33.0          15


Electric Generation revenues increased in 2003 due to higher
wholesale revenues, a slight increase in customers, coupled with a more
profitable mix of sales in higher rate categories.

Sales to AEP Affiliates increased primarily due to higher prices.

Changes in Operating Expenses


                                                            Increase
                                                            (Decrease)
                                                            (in
                                                            millions)     %

         Fuel for Electric Generation                          $14.1      16
         Purchased Electricity for Resale                        8.5     209
         Purchased Electricity from AEP  Affiliates
                                                                 5.3      97
         Other Operation                                        (1.3)     (3)
         Maintenance                                             1.0       8
         Depreciation and Amortization                          (2.1)     (7)
         Taxes Other Than Income Taxes                           1.4      10
         Income Taxes                                            2.5      91
              Total Operating Expenses                         $29.4      15

Fuel for Electric Generation increased in 2003 due to both increased generation
and higher fuel costs.

In 2003, Purchased Electricity increased overall due to higher costs for
purchased power offset in part by reduced MWHs purchased.

Maintenance expense increased in 2003 as a result of scheduled maintenance at
several power plants.

The decrease in Depreciation and Amortization expense was due primarily to the
restoration of a regulatory asset for recovery of a fuel related cost allowed in
a fuel proceeding for the Arkansas portion of SWEPCo's operations.

In 2003, Taxes Other Than Income Taxes increased due to increased payroll and
state gross receipts taxes.

Income Taxes attributable to operations increased in 2003 due to increased
pre-tax income.

Other Changes
Nonoperating Income increased in 2003 due primarily to increased interest income
and AFUDC.

In 2003, Interest Charges increased due to increased levels of debt outstanding
and higher average interest rates.

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
Notes 2 and 3).


<PAGE>
<TABLE>
<CAPTION>


                                             SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                       CONSOLIDATED STATEMENTS OF INCOME
                                                                  (UNAUDITED)

                                                                                           Three Months Ended March 31,
                                                                                                  2003                   2002
                                                                                                          (in thousands)
OPERATING REVENUES:
<S>                                                                                                <C>                   <C>
  Electric Generation                                                                              $156,681              $131,761
  Electric Transmission and Distribution                                                             66,242                67,539
  Sales to AEP Affiliates                                                                            32,355                22,959
           TOTAL OPERATING REVENUES                                                                 255,278               222,259

OPERATING EXPENSES:
  Fuel for Electric Generation                                                                      103,010                88,883
  Purchased Electricity for Resale                                                                   12,567                 4,070
  Purchased Electricity from AEP Affiliates                                                          10,810                 5,485
  Other Operation                                                                                    40,857                42,151
  Maintenance                                                                                        12,817                11,838
  Depreciation and Amortization                                                                      28,035                30,140
  Taxes Other Than Income Taxes                                                                      15,873                14,466
  Income Taxes                                                                                        5,265                 2,757
           TOTAL OPERATING EXPENSES                                                                 229,234               199,790

OPERATING INCOME                                                                                     26,044                22,469

NONOPERATING INCOME                                                                                     872                   102

NONOPERATING EXPENSES                                                                                   521                   566

NONOPERATING INCOME TAX EXPENSE                                                                          50                    28

INTEREST CHARGES                                                                                     15,854                13,818

NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGES                                            10,491                 8,159

CUMULATIVE EFFECT OF ACCOUNTING CHANGES (NET OF TAX)                                                  8,517                  -

NET INCOME                                                                                           19,008                 8,159

PREFERRED STOCK DIVIDEND REQUIREMENTS                                                                    57                    57

EARNINGS APPLICABLE TO COMMON STOCK                                                                $ 18,951              $  8,102


The common stock of SWEPCo is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>




                                         SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                            CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME
                                   (UNAUDITED)

                                                                                                     Accumulated Other
                                                                                                       Comprehensive
                                                  Common       Paid-in        Retained        Income (Loss)
                                                   Stock       Capital        Earnings                                 Total
                                                                         (in thousands)


<S>                                              <C>            <C>             <C>               <C>                <C>
JANUARY 1, 2002                                  $135,660       $245,003        $308,915          $   -              $689,578
Common Stock Dividends                                                           (18,964)                             (18,964)
Preferred Stock Dividends                                                            (57)                                 (57)
                                                                                                                      670,557
Comprehensive Income:
  Other Comprehensive Income                                                                          -                  -
  Net Income                                                                       8,159                                8,159
     Total Comprehensive Income                                                                                         8,159

MARCH 31, 2002                                   $135,660       $245,003        $298,053          $   -              $678,716



JANUARY 1, 2003                                  $135,660       $245,003        $334,789          $(53,683)          $661,769
Common Stock Dividends                                                           (18,199)                             (18,199)
Preferred Stock Dividends                                                            (57)                                 (57)
                                                                                                                      643,513
Comprehensive Income:
  Other Comprehensive Income (Loss),
   Net of Taxes:
    Unrealized Loss on Cash Flow
      Power Hedges                                                                                  (1,367)            (1,367)
  Net Income                                                                      19,008                               19,008
     Total Comprehensive Income                                                                                        17,641

MARCH 31, 2003                                   $135,660       $245,003        $335,541          $(55,050)          $661,154

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                                                     March 31, 2003          December 31, 2002
                                                                                                       (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                                                            <C>                     <C>
   Production                                                                                  $1,503,521              $1,503,722
   Transmission                                                                                   575,856                 575,003
   Distribution                                                                                 1,040,007               1,063,564
   General                                                                                        402,229                 378,130
   Construction Work in Progress                                                                   85,836                  75,755
        Total Electric Utility Plant                                                            3,607,449               3,596,174
   Accumulated Depreciation and Amortization                                                    1,702,196               1,697,338
        NET ELECTRIC UTILITY PLANT                                                              1,905,253               1,898,836

OTHER PROPERTY AND INVESTMENTS                                                                      5,793                   5,978

LONG-TERM RISK MANAGEMENT ASSETS                                                                    8,549                   5,119

CURRENT ASSETS:
   Cash and Cash Equivalents                                                                        7,163                   2,069
   Accounts Receivable:
      Customers                                                                                    62,237                  62,359
      Affiliated Companies                                                                         20,651                  19,253
      Allowance for Uncollectible Accounts                                                         (2,116)                 (2,128)
   Fuel Inventory                                                                                  58,814                  61,741
   Materials and Supplies                                                                          33,806                  33,539
   Under-recovered Fuel Costs                                                                        -                      2,865
   Risk Management Assets                                                                           8,110                   4,388
   Prepayments and Other                                                                           18,565                  17,851
          TOTAL CURRENT ASSETS                                                                    207,230                 201,937

REGULATORY ASSETS                                                                                  52,645                  49,233

DEFERRED CHARGES                                                                                   74,034                  47,572

          TOTAL ASSETS                                                                         $2,253,504              $2,208,675

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                             SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                          CONSOLIDATED BALANCE SHEETS
                                                                  (UNAUDITED)

                                                                                                March 31, 2003  December 31, 2002
                                                                                                         (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                                                              <C>                     <C>
CAPITALIZATION:
  Common Stock - $18 Par Value:
    Authorized - 7,600,000 Shares
    Outstanding - 7,536,640 Shares                                                               $  135,660              $  135,660
  Paid-in Capital                                                                                   245,003                 245,003
  Accumulated Other Comprehensive Income (Loss)                                                     (55,050)                (53,683)
  Retained Earnings                                                                                 335,541                 334,789
    Total Common Shareholder's Equity                                                               661,154                 661,769
  Preferred Stock                                                                                     4,700                   4,701
  SWEPCo-Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely Junior
   Subordinated Debentures of SWEPCo                                                                110,000                 110,000
  Long-term Debt                                                                                    637,496                 637,853
          TOTAL CAPITALIZATION                                                                    1,413,350               1,414,323

OTHER NONCURRENT LIABILITIES                                                                         80,142                  78,494

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                                                    595                  55,595
  Advances from Affiliates, net                                                                     103,123                  23,239
  Accounts Payable - General                                                                         56,856                  62,139
  Accounts Payable - Affiliated Companies                                                            46,762                  58,773
  Customer Deposits                                                                                  22,220                  20,110
  Taxes Accrued                                                                                      60,263                  19,081
  Interest Accrued                                                                                   12,367                  17,051
  Risk Management Liabilities                                                                         7,606                   3,724
  Over-recovered Fuel                                                                                17,090                  17,226
  Other                                                                                              19,781                  34,565
          TOTAL CURRENT LIABILITIES                                                                 346,663                 311,503

DEFERRED INCOME TAXES                                                                               341,398                 341,064

DEFERRED INVESTMENT TAX CREDITS                                                                      43,109                  44,190

REGULATORY LIABILITIES AND DEFERRED CREDITS                                                          23,274                  17,295

LONG-TERM RISK MANAGEMENT LIABILITIES                                                                 5,568                   1,806

COMMITMENTS AND CONTINGENCIES (Note 7)

                    TOTAL CAPITALIZATION AND LIABILITIES                                         $2,253,504              $2,208,675

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                             SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                                  (UNAUDITED)

                                                                                       Three Months Ended March 31,
                                                                                          2003                  2002
                                                                                               (in thousands)

OPERATING ACTIVITIES:
<S>                                                                                     <C>                    <C>
   Net Income                                                                           $19,008                $8,159
   Adjustments to Reconcile Net Income to
     Net Cash Flows From  Operating Activities:
      Depreciation and Amortization                                                      28,035                30,140
      Deferred Income Taxes                                                              (4,034)               (3,930)
      Deferred Investment Tax Credits                                                    (1,081)               (1,131)
      Cumulative Effect of Accounting Changes                                            (8,517)                 -
      Mark-to-Market of Risk Management Contracts                                        (1,462)                7,695
   Changes in Certain Assets and Liabilities:
      Accounts Receivable (net)                                                          (1,288)               (9,762)
      Fuel, Materials and Supplies                                                        2,660               (18,504)
      Accounts Payable                                                                  (17,294)               (2,646)
      Taxes Accrued                                                                      41,182                27,254
      Deferred Property Taxes                                                           (27,945)              (27,217)
      Fuel Recovery                                                                       2,729                10,391
   Change in Other Assets                                                                 1,461                 9,511
   Change in Other Liabilities                                                           (9,120)               (7,260)
           Net Cash Flows From Operating Activities                                      24,334                22,700

INVESTING ACTIVITIES:
      Construction Expenditures                                                         (25,702)              (11,715)
      Proceeds from Sale of Assets and Other                                                284                  -
           Net Cash Flows Used For Investing Activities                                 (25,418)              (11,715)

FINANCING ACTIVITIES:
      Retirement of Long-term Debt                                                      (55,450)             (150,450)
      Change in Advances from Affiliates (net)                                           79,884               154,959
      Dividends Paid on Common Stock                                                    (18,199)              (18,964)
      Dividends Paid on Cumulative Preferred Stock                                          (57)                  (57)
           Net Cash Flows From (Used For) Financing Activities                            6,178               (14,512)

Net Increase (Decrease) in Cash and Cash Equivalents                                      5,094                (3,527)
Cash and Cash Equivalents at Beginning of Period                                          2,069                 5,415
Cash and Cash Equivalents at End of Period                                              $ 7,163              $  1,888

Supplemental Disclosure:
Cash (received) paid for interest net of capitalized amounts was $17,963,000 and
$10,203,000 and for income taxes was ($755,000) and $8,581,000 in 2003 and 2002,
respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>




                     COMBINED NOTES TO FINANCIAL STATEMENTS
                                 MARCH 31, 2003
                                   (UNAUDITED)

The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list indicates the registrants
to which the footnotes apply:


<S>          <C>                            <C>
1.           General                        AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

2.           Significant
             Accounting
              Policies and New
              Accounting
              Pronouncements               AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

3.           Extraordinary Items and
                Cumulative Effect          AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

4.           Goodwill and
                Other  Intangible Assets   AEP, SWEPCo

5.           Rate Matters                  AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

6.           Customer Choice
             and  Industry Restructuring   AEP, APCo, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC

7.           Commitments and
                 Contingencies             AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

8.              Guarantees                 AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO,


9.           Sustained Earnings
                 Improvement
                 Initiative                AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

10.          Dispositions,
                Discontinued
                Operations and
                Assets Held for Sale       AEP, APCo, CSPCo, I&M, KPCo, OPCo

11.          Business Segments             AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC, TNC

12.          Leases                       AEP, OPCo

13.          Minority Interest
               in  Finance Subsidiary     AEP

14.          Financing and Related
                Activities                AEP, CSPCo, I&M, OPCo, SWEPCo, TCC, TNC

</TABLE>






1.              GENERAL

        The accompanying unaudited interim financial statements should be read
        in conjunction with the 2002 Annual Report as incorporated in and filed
        with the Form 10-K.

        Certain prior period financial statement items have been reclassified to
        conform to current period presentation. These items include the effects
        of discontinued operations, gains and losses associated with derivative
        trading contracts presented on a net basis in accordance with EITF 02-3,
        and counterparty netting in accordance with FASB Interpretation No. 39,
        "Offsetting of Amounts Related to Certain Contracts" and EITF Topic
        D-43, "Assurance That a Right of Setoff is Enforceable in a Bankruptcy
        under FASB Interpretation No. 39". Such reclassifications had no effect
        of previously reported Net Income. In addition, management determined
        that certain amounts were misclassified in AEP's 2002 Consolidated
        Statement of Operations resulting from errors in the coding of certain
        intercompany transactions and transactions associated with our UK
        operations. As a result, in the first quarter of 2002 Gas Pipeline and
        Storage revenues decreased by $47 million, Investments revenue decreased
        by $10 million, Fuel for Electric Generation decreased by $27 million,
        and Purchased Gas for Resale decreased by $58 million. Expenses for
        Maintenance and Other Operation increased by $21 million and Taxes Other
        Than Income Taxes increased by $7 million. These revisions had no effect
        on Operating Income or Net Loss.

        In the opinion of management, the unaudited interim financial statements
        reflect all normal recurring accruals and adjustments which are
        necessary for a fair presentation of the results of operations for
        interim periods.

2. SIGNIFICANT ACCOUNTING POLICIES AND NEW ACCOUNTING PRONOUNCEMENTS

        Significant Accounting Policies

        Components of Accumulated Other Comprehensive Income (Loss) - Other
        comprehensive income (loss) is included on the balance sheet in the
        equity section. The following table provides the components that
        comprise the balance sheet amount in Accumulated Other Comprehensive
        Income (Loss) for AEP:

                                                    March 31,    December 31,
                                                      2003             2002
       Components                                           (in millions)

       Foreign Currency Translation   Adjustments   $  17                  $ 4
       Unrealized Losses on Securities                 (1)                  (2)
       Unrealized Losses on Cash Flow  Hedges         (38)                 (16)
       Minimum Pension Liability                     (580)                (595)
                                                    $(602)               $(609)

        Accumulated Other Comprehensive Income (Loss) for AEP registrant
        subsidiaries as of March 31, 2003, and December 31, 2002 is shown in the
        following table.

                                               March 31,     December 31,
                                                2003            2002
       Components                                  (in thousands)

       Unrealized Losses
        on Cash Flow  Hedges:
         APCo                              $ (14,438)            $ (1,920)
         CSPCo                                (7,610)                (267)
         I&M                                  (8,143)                (286)
         KPCo                                 (2,543)                 322
         OPCo                                (10,477)                (738)
         PSO                                  (1,239)                 (42)
         SWEPCo                               (1,415)                 (48)
         TCC                                  (1,054)                 (36)
         TNC                                    (436)                 (15)
         Non-Registrants                       9,220              (13,368)
                                           $ (38,135)            $(16,398)

       Minimum Pension Liability:
         APCo                               $(70,162)            $(70,162)
         CSPCo                               (59,090)             (59,090)
         I&M                                 (40,201)             (40,201)
         KPCo                                 (9,773)              (9,773)
         OPCo                                (66,524)             (72,148)
         PSO                                 (54,489)             (54,431)
         SWEPCo                              (53,635)             (53,635)
         TCC                                 (73,124)             (73,124)
         TNC                                 (30,755)             (30,748)
         Non-Registrants                    (121,879)            (131,898)
                                           $(579,632)           $(595,210)
<TABLE>
<CAPTION>


        The following tables represent the activity in Other Comprehensive
        Income (Loss) related to the effect of adopting SFAS 133 for derivative
        contracts that qualify as cash flow hedges at March 31, 2003:

                                                      Domestic       Domestic        Foreign                             AEP
                                                        Power          Gas          Currency        Interest Rate    Consolidated
                                                                                             (in millions)
<S>                                                     <C>             <C>             <C>               <C>              <C>
        Accumulated OCI, December 31, 2002                  $ (1)       $ -             $(3)              $(12)            $(16)
        Changes in Fair Value (a)                            (65)         8               5                  6              (46)
        Reclassifications from OCI to Net
         Income (b)                                           23          -              -                   1               24
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003 (c)                                  $(43)       $ 8             $ 2               $ (5)            $(38)
</TABLE>
<TABLE>
<CAPTION>

        APCo                                          Domestic            Foreign                                   APCo
                                                        Power             Currency          Interest Rate       Consolidated
                                                                                           (in thousands)
<S>                                                     <C>                 <C>                   <C>                  <C>
        Accumulated OCI, December 31, 2002              $   (394)           $(190)                $(1,336)             $(1,920)
        Changes in Fair Value (a)                        (19,201)             -                      (104)          (19,305)
        Reclassifications from OCI to Net
         Income (b)                                        6,649                2                     136                6,787
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003 (c)                              $(12,946)           $(188)                $(1,304)            $(14,438)
</TABLE>

        CSPCo                                         Domestic
                                                        Power
                                                       (in thousands)
        Accumulated OCI, December 31, 2002               $  (267)
        Changes in Fair Value (a)                        (11,251)
        Reclassifications from OCI to Net
         Income (b)                                        3,908
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003 (c)                               $(7,610)



        I&M                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002               $  (286)
        Changes in Fair Value (a)                        (12,039)
        Reclassifications from OCI to Net
         Income (b)                                        4,182
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003 (c)                               $(8,143)
<TABLE>
<CAPTION>

        KPCo                                          Domestic                                KPCo
                                                        Power          Interest Rate       Consolidated
                                                                            (in thousands)
<S>                                                      <C>                    <C>               <C>
        Accumulated OCI, December 31, 2002               $  (103)               $425              $   322
        Changes in Fair Value (a)                         (4,357)                (43)              (4,400)
        Reclassifications from OCI to Net
         Income (b)                                        1,513                  22                1,535
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003 (c)                               $(2,947)               $404              $(2,543)
</TABLE>
<TABLE>
<CAPTION>

        OPCo                                          Domestic          Foreign              OPCo
                                                        Power           Currency         Consolidated
                                                                        (in thousands)
<S>                                                     <C>                <C>                 <C>
        Accumulated OCI, December 31, 2002              $   (354)          $(384)              $   (738)
        Changes in Fair Value (a)                        (14,928)             -                 (14,928)
        Reclassifications from OCI to Net
         Income (b)                                        5,186               3                  5,189
        Accumulate OCI Derivative Gain  (Loss)
        March 31, 2003 (c)                              $(10,096)          $(381)              $(10,477)
</TABLE>

        PSO                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (42)
        Changes in Fair Value (a)                         (1,833)
        Reclassifications from OCI to Net
         Income (b)                                          636
        Accumulated OCI Derivative Gain (Loss) March
        31, 2003 (c)                                      $(1,239)


        SWEPCo                                        Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (48)
        Changes in Fair Value (a)                         (2,094)
        Reclassifications from OCI to Net
         Income (b)                                          727
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003 (c)                               $(1,415)

        TCC                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (36)
        Changes in Fair Value (a)                         (1,559)
        Reclassifications from OCI to Net
         Income (b)                                          541
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003 (c)                               $(1,054)

        TNC                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (15)
        Changes in Fair Value (a)                           (645)
        Reclassifications from OCI to Net
         Income (b)                                          224
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003 (c)                               $  (436)

(a)       Changes in fair value - 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 - 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.
(c)       Accumulated OCI Derivative Gain (Loss) March 31, 2003 - 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.

        Approximately $31 million of net losses from cash flow hedges in
        Accumulated Other Comprehensive Income (Loss) at March 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
        Accumulated Other Comprehensive Income to Net Income can differ as a
        result of market price changes. The maximum term for which the exposure
        to the variability of future cash flows is being hedged is five years.

        Common Stock Options and Restricted Shares - AEP has two stock-based
        employee compensation plans with outstanding stock options. AEP accounts
        for these plans under the recognition and measurement principles of APB
        Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and
        related Interpretations. No stock-based employee compensation expense is
        reflected in AEP's earnings, as all options granted under these plans
        had exercise prices equal to or above the market value of the underlying
        common stock on the date of grant.

        AEP awarded 102,513 restricted stock units to certain AEP employees in
        March 2003. The units vest in equal one-third increments in January
        2004, 2005 and 2006. At each vesting date, shares will be issued at no
        cost to the employee. In accordance with APB 25, the compensation
        expense of approximately $2.3 million will be expensed over the vesting
        period of the units. The value of the units was based on a $21.95 per
        share value at the grant date. The amount of compensation expense
        recognized during the first quarter of 2003 in AEP's Consolidated
        Statements of Operations was $463 thousand, pre-tax.

        The following table illustrates the effect on AEP's Net Income (Loss)
        and earnings (loss) per share as if AEP had applied the fair value
        recognition provisions of FASB Statement No. 123, "Accounting for
        Stock-Based Compensation", to stock-based employee compensation awards:
<TABLE>
<CAPTION>

                                                                                    Three Months Ended
                                                                                         March 31,
                                                                                2003                2002
                                                                      (in millions,  except per  share data)

<S>                                                                            <C>                 <C>
          Net Income (loss), as reported                                       $ 440               $(169)
          Add:    Stock-based    compensation   expense   included   in
            reported net income, net of related tax effects                      -   (a)          -
          Deduct:  Stock-based employee compensation       expense
        determined under fair value based method     for all awards,
        net of related tax effects                                                (1)                 (2)
          Pro Forma Net Income (Loss)                                          $ 439              $ (171)

          Earnings (Loss) per Share:
              Basic - as Reported                                              $1.24              $(0.52)
              Basic - Pro Forma                                                 1.23               (0.53)

              Diluted - as Reported                                            $1.24              $(0.52)
              Diluted - Pro Forma                                               1.23               (0.53)

        (a)   Compensation expense related to restricted units during the first
              quarter of 2003 was $301 thousand, net of tax.
</TABLE>

        New Accounting Pronouncements

        AEP 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 that had previously been recorded for
        generation that does not qualify as a legal obligation which was
        collected in depreciation rates by certain formerly regulated
        subsidiaries.

        AEP has completed a review of its asset retirement obligations and
        concluded that at present, it has related legal liabilities for nuclear
        decommissioning costs for its Cook Plant and its 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 AEP presently recovers its nuclear decommissioning
        costs in its regulated cash flow and thus had existing balances recorded
        for such nuclear retirement obligations, it recognized the cumulative
        difference in the amount already provided through rates versus the new
        methodology of 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 AEP's regulated operations.
        AEP recorded an unfavorable cumulative effect of $45.4 million after tax
        for the non-regulated operations ($38.0 million related to Ash Ponds and
        $7.4 million related to U.K. Plants, Wind Mills and Coal Operations).

        Certain of AEP's operating companies have recorded in Accumulated
        Depreciation and Amortization, removal costs collected from rate payers
        for certain assets that do not have associated legal asset retirement
        obligations. To the extent that such operating companies have now been
        deregulated, AEP reversed the balance of such removal costs, totaling
        $287.2 million after tax, from accumulated depreciation which resulted
        in a net favorable cumulative effect. However, AEP did not adjust the
        balance of such removal costs for its regulated operations, and in
        accordance with the present method of recovery, will continue to record
        such amounts through depreciation expense and accumulated depreciation.
        AEP estimates that it has approximately $1.2 billion of such regulatory
        liabilities recorded in Accumulated Depreciation and Amortization as of
        both March 31, 2003 and December 31, 2002.

        The following is a summary by registrant of the regulatory liabilities
        for removal costs included in Accumulated Depreciation and Amortization:

                               March 31, 2003        December 31,2002
                                              (in millions)
        AEGCo                          $   28.4                $   28.0
        APCo                               94.5                    94.6
        CSPCo                              96.7                    96.0
        I&M                               252.7                   250.5
        KPCo                               21.9                    23.7
        OPCo                               96.2                    97.0
        PSO                               198.9                   202.6
        SWEPCo                            220.7                   219.5
        TCC                                97.7                    97.5
        TNC                                74.7                    75.0
        Non-Registrants                     0.5                     0.5
                                       $1,182.9                $1,184.9



        The net favorable cumulative effect of the change in accounting
principle consists of the following:

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

        Ash Ponds                            $ (62.8)       $ (38.0)
        UK Plants, Wind Mills  and  Coal
        Operations                             (11.3)          (7.4)
        Reversal of Cost of  Removal
                                               472.6          287.2
            Total                            $ 398.5        $ 241.8
<TABLE>
<CAPTION>

        The following is a summary by registrant of the cumulative effect of
changes in accounting principles:

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

                                            U. K. Plants,                                           U. K. Plants,
                                            Wind Mills            Reversal of                       Wind Mills          Reversal of
                                            and Coal               Cost of                          and Coal         Cost of Removal
                          Ash Ponds         Operations             Removal          Ash Ponds       Operations
                                               (in millions)
<S>                       <C>               <C>                <C>                <C>                 <C>               <C>
        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
        SWEPCo                  -                 -                    13.0             -                 -                    8.4
        TCC                     -                 -                     -               -                 -                    -
        TNC                     -                 -                     4.7             -                 -                    3.1
        Other                    -              (11.3)                  1.2             -                (7.4)                 0.8
                             $(62.8)           $(11.3)              $ 472.6          $(38.0)            $(7.4)              $287.2
</TABLE>

        AEP has identified, but not recognized, asset retirement obligation
        liabilities related to electric transmission and distribution and gas
        distribution assets, as a result of certain easements on property on
        which AEP has assets. Generally, such easements are perpetual and
        require only the retirement and removal of AEP's assets upon the
        cessation of the property's use. The retirement obligation is not
        estimable for such easements since AEP plans to use its properties
        indefinitely. The retirement obligation would only be recognized if and
        when AEP abandons or ceases the use of specific easements.
<TABLE>
<CAPTION>

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



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

        Asset Retirement
        Obligation Liability at
<S>                                                <C>                     <C>                    <C>                  <C>
          January 1, 2003                          $718.3                  $69.8                  $37.2                $825.3


        Accretion expense                            12.7                    1.4                   0.4                   14.5

        Asset Retirement   Obligation
        Liability
          at March 31, 2003                        $731.0                  $71.2                 $37.6                 $839.8
</TABLE>
<TABLE>
<CAPTION>

        The following is a reconciliation of beginning and ending aggregate
        carrying amounts of asset retirement obligations by registrant following
        the adoption of SFAS 143:

                                                        Balance At                                              Balance at
                                                      January 1, 2003              Accretion                  March 31, 2003
                                                                                 (in millions)
<S>                                                           <C>                        <C>                       <C>
       AEGCo (a)                                              $  1.1                     $  -                      $  1.1
       APCo (a)                                                 20.1                       0.4                       20.5
       CSPCo (a)                                                 8.1                       0.2
       I&M (b)                                                 516.1                       9.0                      525.1
       OPCo (a)                                                 39.5                       0.8                       40.3
       TCC (c)                                                 203.2                       3.8                      207.0
       Other (d)                                                37.2                       0.3                       37.5
                                                              $825.3                     $14.5                     $839.8

       (a) Consists of asset retirement obligations related to ash ponds.
       (b) Consists of asset retirement obligations related to ash ponds ($1.1
       million at March 31, 2003) and nuclear decommissioning costs for the Cook
       Plant ($524 million at March 31, 2003). (c) Consists of asset retirement
       obligations related to nuclear decommissioning costs for STP. (d)
       Consists of asset retirement obligations related to wind farms, the U.K.
       plants and certain coal mining facilities.
</TABLE>



        Accretion expense is included in Maintenance and Other Operation in
        AEP's accompanying Consolidated Statements of Operations and in Other
        Operation expense in the Income Statements of the other individual
        registrants.

        As of March 31, 2003 and December 31, 2002, the fair value of assets
        that are legally restricted for purposes of settling the nuclear
        decommissioning liabilities totaled $706 million and $716 million,
        respectively, recorded in Other Assets on AEP's Consolidated Balance
        Sheets.

        Pro forma net income and earnings per share have not been presented for
        the quarter ended March 31, 2002 or the years ended December 31, 2002,
        2001 and 2000 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 for those periods.

        The following is a summary by registrant 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        December 31,2001
                                               (in millions)
        AEGCo                         $  1.0                   $  1.0
        APCo                            20.2                     18.7
        CSPCo                            8.1                      7.5
        I&M                            516.1                    481.4
        KPCo                              -                        -
        OPCo                            39.5                     36.5
        PSO                               -                        -
        SWEPCo                            -                        -
        TCC                            203.2                    188.8
        TNC                               -                        -
        Non-Registrants                 37.2                     35.3
                                      $825.3                   $769.2


        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,  "Recognition  and
        Reporting of Gains and Losses on Energy Contracts under Issue
        No. 98-10 and 00-17" (EITF 02-3).  See Note 3.

        FASB Stock-based Compensation Project

        In March 2003, the FASB added a project to address issues related to
        share-based payments. In April 2003, the FASB decided that goods and
        services, including employee stock options, received in exchange for
        stock-based compensation should be recognized in the income statement as
        an expense, with the cost measured at fair value. An exposure draft is
        expected by the end of this year and a final statement could be
        effective in 2004.

        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 for derivative instruments, including
        certain derivative instruments embedded in other contracts and for
        hedging activities. SFAS 149 also amends certain other existing
        pronouncements. SFAS 149 is effective for AEP for contracts entered into
        or modified after June 30, 2003. AEP and its subsidiaries are evaluating
        the impact of adopting the requirements of SFAS 149.


3. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT

        Cumulative Effect of Accounting Changes - SFAS 142 requires that
        goodwill and intangible assets with indefinite useful lives no longer be
        amortized and be tested annually for impairment. The implementation of
        SFAS 142 resulted in a $350 million after tax net transitional loss in
        2002 for the U.K. and Australian operations and is reported in AEP's
        Consolidated Statements of Operations as a cumulative effect of
        accounting change.

        SFAS 143, "Accounting for Asset Retirement Obligations", (see Note 2) is
        effective for AEP on January 1, 2003. SFAS 143 generally applies to
        legal obligations associated with the retirement of long-lived assets. A
        company is required to recognize an estimated liability for any legal
        obligations associated with the future retirement of its long-lived
        assets. The liability is measured at fair value and is capitalized as
        part of the related asset's capitalized cost. The increase in the
        capitalized cost is included in determining depreciation expense over
        the expected useful life of the asset. The catch-up effect of adopting
        SFAS 143 will be recorded as a cumulative effect of an accounting
        change. Additionally, because the asset retirement obligation is
        recorded initially at fair value, accretion expense (similar to
        interest) will be recognized each period as an operating expense in the
        statement of operations. AEP has recorded $242 million in after tax
        income related to the recording of Asset Retirement Obligations in AEP's
        Consolidated Statements of Operations as a cumulative effect of
        accounting change.

        EITF 02-3 rescinds EITF 98-10 and related interpretive guidance. Under
        EITF 02-3, mark-to-market accounting is precluded for energy trading
        contracts that are not derivatives pursuant to SFAS 133. The consensus
        to rescind EITF 98-10 will also eliminate any basis for recognizing
        physical inventories at fair value other than as provided by GAAP. The
        consensus to rescind EITF 98-10 is effective for all new contracts
        entered into (and physical inventory purchased) after October 25, 2002.
        The consensus is effective for fiscal periods beginning after December
        15, 2002, and applies to all energy trading contracts that existed on or
        before October 25, 2002 that remain in effect as of the date of
        implementation, January 1, 2003. Effective January 2003, nonderivative
        energy contracts entered into prior to October 25, 2002 are required to
        be accounted for on a settlement basis and inventory is required to be
        presented at the lower of cost or market. The effect of implementing
        this consensus is reported as a cumulative effect of an accounting
        change. Such contracts and inventory are accounted for at fair value
        through December 31, 2002. Energy contracts that qualify as derivatives
        were accounted for at fair value under SFAS 133. AEP has recorded a $49
        million after tax charge against net income as Accounting for Risk
        Management Contracts in AEP's Consolidated Statements of Operations in
        Cumulative Effect of Accounting Changes. This amount will be recognized
        when the positions settle.
<TABLE>
<CAPTION>

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


                                                                     Three Months Ended March 31,
       Description                                                       2003            2002
                                                                       (in millions)

<S>                                                                      <C>            <C>
       Accounting for Risk  Management  Contracts (EITF 02-3)            $(49)          $  -
       Asset Retirement Obligations (SFAS 143)                            242              -
       Goodwill and Other
        Intangible Assets                                                  -             (350)
       Total                                                            $193            $(350)



        The following is a summary by registrant of the cumulative effect of
        changes in accounting principles for the adoptions of SFAS 143 and EITF
        02-3:


                                 SFAS 143 Cumulative Effect               EITF 02-3 Cumulative Effect
                           Pre-tax After-tax After-tax
                              Income Income Income
                          (Loss) (Loss) Pre-tax (Loss)
                                     Income
                                     (Loss)
                                              (in millions)                             (in millions)

       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                  -                     -
       Other                                (10.1)               (6.6)              (49.5)                (37.3)
                                           $398.5              $241.8              $(67.7)               $(49.1)

</TABLE>
<TABLE>
<CAPTION>

4. GOODWILL AND OTHER INTANGIBLE ASSETS

        Goodwill

        The changes in the carrying amount of goodwill for the three months
ended March 31, 2003 by operating segment are:

                                                          Investments
                                         Utility            Gas             U.K.                           AEP
                                       Operations     Operations      Operations        Other           Consolidated
                                                                            (in millions)

<S>                                          <C>            <C>             <C>          <C>              <C>
       Balance January 1, 2003               $37.1          $306.3          $11.1        $41.5            $396.0
       Foreign currency
        exchange rate changes                   -               -            (0.3)          -               (0.3)
       Balance March 31, 2003                $37.1          $306.3          $10.8        $41.5            $395.7


       Acquired Intangible Assets

        The gross carrying amount, accumulated amortization and amortization
        life by major asset class are shown in the following table:


                                                                                  March 31, 2003               December 31, 2002

                                                         Gross    Carrying                                Gross
                                          Amortization            Amount           Accumulated          Carrying        Accumulated
                                              Life                                Amortization           Amount        Amortization
                                                                                              (in millions)
       Software and customer  list
                                                2                 $ 0.5              $0.3                $ 0.5               $0.2
       Software acquired                        3                   0.4                -                   0.5                 -
       Patent                                   5                   0.1                -                   0.1                 -
        administration of  contracts
                                                7                   2.4               0.6                  2.4                0.6
       Purchased technology                    10                  10.3               1.3                 10.3                1.0
       Advanced royalties                      10                  29.4               5.4                 29.4                4.7

         Total                                                    $43.1              $7.6                $43.2               $6.5


       Amortization of intangible assets was $1.2 million ($1.1 million net of
       foreign currency translation) and $1.0 million (no foreign currency
       translation) for the three months ended March 31, 2003 and March 31,
       2002.

       Estimated aggregate amortization expense is $4.4 million for each year
       2004 through 2006, $4.3 million in 2007, $4.1 million in 2008 and $4.0
       million in 2009.

       Fluctuations in the gross carrying values since December 31, 2002
        represent changes in the foreign currency exchange rate.

       Intangible assets subject to amortization are recorded in Other Assets in
the AEP Consolidated Balance Sheets.
</TABLE>

  5. RATE MATTERS

       Fuel in SPP - Affecting AEP, SWEPCo and TNC

       As discussed in Note 6 of the 2002 Annual Report, in 2001, the PUCT
       delayed the start of customer choice in the SPP area of Texas. In May
       2003, the PUCT approved a stipulation that delays competition in the SPP
       areas of Texas until no sooner than January 1, 2007. All of SWEPCo's
       Texas service territory and a small portion of TNC's service territory
       are in the SPP. SWEPCo's existing Texas fuel cost recovery procedures
       will continue until competition begins. SWEPCo will continue to set fuel
       factors and determine final fuel costs in fuel reconciliation proceedings
       during the SPP delay period. The PUCT has ruled that TNC fuel factors in
       the SPP area will be based upon the price-to-beat fuel factors offered by
       the retail electric provider (REP) in the ERCOT portion of TNC's service
       territory. 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, should be used to reconcile fuel costs in its
       SPP area. The adjustments removed $3.71 per MWH from reconcilable fuel
       expense. This adjustment will reduce revenues received from TNC's SPP
       customers by approximately $400,000 annually. These customers are now
       served by SWEPCo's REP.

       TNC Fuel Reconciliation - Affecting AEP and TNC

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

       In March 2003, the Administrative Law Judges (ALJ) in this proceeding
       filed their Proposal for Decision (PFD). The PFD recommends that TNC's
       under-recovered retail fuel balance be reduced by approximately $12.5
       million. In March 2003, TNC established a reserve of $13 million,
       including interest, based on the PFD's recommendations. On April 22,
       2003, TNC and intervenors in this proceeding filed exceptions to the PFD.
       The PUCT is scheduled to consider the PFD on May 22, 2003 and is expected
       to issue a final order by mid 2003. Any further adverse ruling from the
       PUCT could have a material impact on future results of operations, cash
       flows and financial condition.

       TCC Fuel Reconciliation  - Affecting AEP and TCC

       In December 2002, TCC filed with the PUCT to reconcile fuel costs and to
       defer its over-recovery of fuel for inclusion in the 2004 true-up
       proceeding. This reconciliation for the period of July 1998 through
       December 2001 will be the final fuel reconciliation. At December 31,
       2001, the over-recovery balance for TCC was $63.5 million including
       interest. During the reconciliation period, TCC incurred $1.6 billion of
       eligible fuel and fuel-related expenses. Recommendations from intervening
       parties were received in April 2003 with hearings scheduled in May 2003.
       Intervening parties have recommended disallowances totaling $170 million.

       In March 2003, the ALJ hearing the TNC final fuel reconciliation,
       discussed above, issued a PFD in the TNC proceeding. Various issues
       addressed in TNC's proceeding may also be applicable to TCC's proceeding.
       Consequently, TCC established a reserve for potential adverse rulings of
       $27 million during the first quarter of 2003. A final order is expected
       in late 2003. An adverse ruling from the PUCT in excess of the 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".

       FERC Wholesale Fuel Complaints - Affecting AEP and TNC

       As discussed in the 2002 Annual Report, 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 have
       resulted in new contracts. Consequently, an offer of settlement will be
       filed at FERC regarding the fuel complaint. Management is unable to
       predict whether FERC will approve this offer of settlement which is not
       expected to have a significant impact on TNC's financial condition. In
       March 2002, TNC recorded a provision for refund of $2.2 million before
       income taxes. The actual refund and final resolution of this matter could
       differ materially from this estimate and may have a negative impact on
       future results of operations, cash flow and financial condition.

       Environmental Surcharge Filing - Affecting AEP and 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 Big
       Sandy Plant. See NOx Reductions in Note 7.

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

       PSO Rate Review - Affecting AEP and PSO

       In February 2003, the Director of the OCC filed an application requiring
       PSO to file all documents necessary for a general rate review before
       August 1, 2003. Management is unable to predict the ultimate effect of
       this review on PSO's rates.

       FERC Long-term Contracts - Affecting AEP and AEP East and
         AEP West companies

       In September 2002, the FERC voted to hold hearings to consider requests
       from certain wholesale customers located in Nevada and Washington to
       break long-term contracts which they allege are "high-priced". At issue
       are long-term contracts entered during the California energy price spike
       in 2000 and 2001. The complaints allege that AEP sold power at unjust and
       unreasonable prices. The FERC delayed hearings to allow the parties to
       hold settlement discussions. In January 2003, the FERC settlement judge
       assigned to the case indicated that the parties' settlement efforts were
       not progressing and he recommended that the complaint be placed back on
       the schedule for a hearing. In February 2003, AEP and one of 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 a similar complaint, a FERC administrative law judge (ALJ) ruled in
       favor of AEP and dismissed, in December 2002, a complaint filed by two
       Nevada utilities. In 2000 and 2001, AEP agreed to sell power to the
       utilities for future delivery. In late 2001, the utilities filed
       complaints that the prices for power supplied under those contracts
       should be lowered because the market for power was allegedly
       dysfunctional at the time such contracts were consummated. The ALJ
       rejected the utilities' complaint, held that the markets for future
       delivery were not dysfunctional, and that the utilities had failed to
       demonstrate that the public interest required that changes be made to the
       contracts. The ALJ's order is preliminary and is subject to review by the
       FERC. At a hearing held in April 2003, the utilities asked FERC to void
       the long-term contracts. The FERC will likely rule on the ALJ's order in
       2003. Management is unable to predict the outcome of these proceedings or
       their impact on future results of operations.

       6. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

       As discussed in the 2002 Annual Report, 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 in 2003
       related to customer choice and industry restructuring.

       Ohio Restructuring - Affecting AEP, 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 other
       applicable law by failing to participate in an RTO.

        The complaintants 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         pricing 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 the FERC's reversal of its previous approval of our RTO filings
        and 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 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 unable to predict the timing of the AEP's
        East companies' participation in PJM, or the outcome of these
        proceedings before the PUCO.

        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. Management is unable to
        predict the timing or the outcome of this proceeding.

        Texas Restructuring - Affecting AEP,  SWEPCo, TCC and TNC

        As discussed in the 2002 Annual Report, on January 1, 2002, customer
        choice of electricity supplier began in the ERCOT area of Texas.
        Customer choice has been delayed in other areas of Texas including the
        SPP area in which SWEPCo operates. In May 2003, the PUCT approved a
        stipulation that delays competition in the SPP area until at least
        January 1, 2007.

        A 2004 true-up proceeding will determine the amount of stranded costs,
        final fuel balance, net regulatory assets, certain environmental costs,
        accumulated excess earnings, excess of price-to-beat revenues over
        market prices subject to certain conditions and limitations (Retail
        clawback), and the difference between the price of power obtained
        through the legislatively-mandated capacity auctions and the power costs
        used in the PUCT's ECOM model for 2002 and 2003 (Wholesale clawback) and
        other restructuring issues.

        The Texas Legislation allows for several alternative methods to be used
        to value stranded costs in the final 2004 true-up proceeding including
        the sale or exchange of generation assets, stock valuation or the use of
        an ECOM model. Only TCC has stranded costs under the Texas Legislation.

        In late 2002, TCC decided to obtain a market value of generating assets
        for purposes of determining stranded costs for the 2004 true-up
        proceeding and filed a plan of divestiture with the PUCT seeking
        approval of a sales process for all of its generating facilities. Such
        sales would quantify the actual stranded costs. The amount of stranded
        costs under this market valuation methodology will be the amount by
        which net book value of TCC's generating assets, including regulatory
        assets and liabilities that were not securitized, exceeds the market
        value of the generation assets as measured by the net proceeds from the
        sale of the assets. It is anticipated that any such sale will result in
        significant stranded costs for purposes of TCC's 2004 true-up
        proceeding. The filing included a request for the PUCT to issue a
        declaratory order that TCC's 25.2% ownership interest in its nuclear
        plant, STP, can be sold to value stranded costs. Intervenors to this
        proceeding, including the PUCT Staff, made filings to dismiss TCC's
        filing claiming that the PUCT does not have the authority to issue a
        declaratory order. The intervenors also argued that the proper time to
        address the sales process is after the plants are sold during the 2004
        true-up proceeding. Since the bidding process is not expected to be
        completed before mid-2004, TCC requested that the 2004 true-up
        proceeding be scheduled after completion of the divestiture of the
        generating assets.

        In March 2003, the PUCT dismissed TCC's divestiture filing, determining
        that it was more appropriate to address the nuclear asset stranded costs
        valuation in a rulemaking proceeding. The PUCT approved a rule, in May
        2003, that allows the value obtained by selling nuclear assets to be
        used in determining stranded costs. Since the PUCT also dismissed the
        request to certify the proposed divestiture plan, the divestiture plan
        utilized by TCC will still be subject to a prudency review in the 2004
        true-up proceedings. The PUCT also initiated a rulemaking regarding the
        timing of the 2004 true-up proceedings scheduling TNC's filing in May
        2004 and TCC's filing in September 2004.

        Texas Legislation also requires that electric utilities and their
        affiliated power generation companies (PGC) sell at auction in 2002 and
        2003 at least 15% of the PGC's Texas jurisdictional installed generation
        capacity in order to promote competitiveness in the wholesale market
        through increased availability of generation and liquidity. Actual
        market power prices received in the state mandated auctions will replace
        the PUCT's earlier estimates of those market prices used in the ECOM
        model to calculate the stranded cost for TCC for the 2004 true-up
        proceeding.

        The decision to determine stranded costs using market prices, instead of
        using the PUCT's ECOM model estimates, enabled TCC to record a $262
        million regulatory asset and related revenues which represents the
        quantifiable amount of stranded costs for the year 2002 related to the
        wholesale prices. In the first quarter of 2003, TCC recorded an
        additional $56 million regulatory asset and related revenues for
        stranded costs. Prior to the decision to pursue a sale of TCC's
        generating assets, the PUCT's ECOM estimate prohibited the recognition
        of the regulatory assets and revenues as there was no way to quantify
        stranded costs. As discussed above, a defined process is required in
        order to determine the amount of stranded costs related to generation
        facility for the 2004 true-up proceedings. TCC's plan of divestiture
        filed with the PUCT during 2002 provided such a process.

        When the divestiture and the 2004 true-up proceeding are completed, TCC
        can securitize stranded costs that are in excess of current securitized
        amounts. The annual costs of securitization will be recovered through a
        non-bypassable rate surcharge by the regulated transmission and
        distribution (T&D) utility over the life of the securitization bonds.
        Any stranded costs and other true-up amounts not recovered through the
        sale of securitization bonds may be recovered through a separate
        non-bypassable competitive transition charge to T&D utility customers.

        In the event TCC and TNC are unable after the 2004 true-up proceeding to
        recover all or a portion of their generation-related regulatory assets,
        unrecovered fuel balances, stranded costs and other restructuring
        related costs, it could have a material adverse effect on results of
        operations, cash flows and possibly financial condition.

        Arkansas Restructuring - Affecting AEP and 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 for the first quarter of 2003. 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 AEP and 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 deregulation 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.

475     In the 2003 legislative session, the WV Legislature failed to enact the
        required tax legislation. Also, a March 2003 WV Legislative Bill
        clarified the jurisdiction of the WVPSC over electric generation
        facilities in WV. In March 2003, APCo's outside counsel advised us that
        deregulation in West Virginia 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 apply SFAS 71.

        The result of reapplying SFAS 71 in WV had an insignificant effect on
        results of operations for the first quarter of 2003. 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
        market-to-market.

7. COMMITMENTS AND CONTINGENCIES

        Power Generation Facility - Affecting AEP

        AEP has entered into agreements with Katco Funding L.P. (Katco), an
        unrelated unconsolidated special purpose entity. Katco has an aggregate
        financing commitment of $525 million and a capital structure of which 3%
        is equity from investors with no relationship to AEP or any of its
        subsidiaries and 97% is debt from a syndicate of banks. Katco was formed
        to develop, construct, finance and lease a power generation facility to
        AEP. Katco will own the power generation facility and lease it to AEP
        after construction is completed. The lease was originally intended to be
        accounted for as an operating lease, therefore neither the facility nor
        the related obligations would be reported on AEP's balance sheet (see
        discussion of potential consolidation issues later in this note).
        Payments under the operating lease are expected to commence in the first
        quarter of 2004. AEP will in turn sublease the facility to Dow Chemical
        Company (DOW). The use of Katco allows AEP to limit its risk associated
        with the power generation facility once the construction phase has been
        completed.

        AEP is the construction agent for Katco. Construction is currently
        scheduled to be completed by the first quarter of 2004, subject to
        unforeseen events beyond AEP's control.

        In the event the project is terminated before completion of
        construction, AEP has the option to either purchase the facility for
        100% of project costs or terminate the project and make a payment to
        Katco for 89.9% of project costs.

        DOW will use a portion of the energy produced by the facility and sell
        the excess energy. AEP has agreed to purchase approximately 800 MW of
        such excess energy from DOW. AEP will resell that energy to Tractebel
        Energy Marketing, Inc. (TEM) for a period of 20 years. Beginning May 1,
        2003, AEP has certain contractual rights and obligations in connection
        with providing replacement energy and other products to TEM. If the
        project is not completed by April 30, 2004, TEM may claim that it can
        terminate the purchase agreement and is owed liquidating damages of
        approximately $17.5 million.

        The operating lease between Katco and AEP commences on the commercial
        operation date of the facility and continues until November 2006. The
        lease contains extension options subject to the approval of Katco, and
        if all extension options were exercised, the total term of the lease
        would be 30 years. AEP's lease payments to Katco are sufficient for
        Katco to make required debt payments and provide a return to the
        investors of Katco. At the end of each lease term, AEP may renew the
        lease at fair market value subject to Katco's approval, purchase the
        facility at its original construction cost, or sell the facility, on
        behalf of Katco, to an independent third party. If the facility is sold
        and the proceeds from the sale are insufficient to repay Katco, AEP may
        be required to make a payment to Katco for the difference between the
        proceeds from the sale and the obligations of Katco, up to 82% of the
        project's cost. AEP has guaranteed a portion of the obligations of its
        subsidiaries to Katco during the construction and post-construction
        periods.

        As of March 31, 2003, project costs subject to these agreements totaled
        $403 million, and total costs for the completed facility are expected to
        be approximately $510 million. For the 30-year extended lease term, the
        lease rental is a variable rate obligation indexed to three-month LIBOR.
        Consequently as market interest rates increase, the payments under this
        operating lease will also increase. Annual payments of approximately $12
        million represent future minimum payments during the initial term
        calculated using the indexed LIBOR rate (1.38% at December 31, 2002).
        The Power Generation Facility collateralizes the debt obligation of
        Katco. AEP's maximum exposure to loss as a result of its involvement
        with Katco is 100% during the construction phase and up to 82% once the
        construction is completed. Maximum loss is deemed to be remote due to
        the collateralization.

        It is reasonably possible that under this operating lease structure AEP
        will consolidate Katco in the third quarter of 2003, as a result of the
        issuance of FASB Interpretation No. 46 "Consolidation of Variable
        Interest Entities" (FIN 46). Upon consolidation, AEP would record the
        assets, liabilities, depreciation expense, minority interest and debt
        interest expense. AEP would eliminate operating lease expense. The
        sublease to DOW would not be affected by this consolidation.

        AEP is currently in the process of reviewing restructuring options for
        this operating lease, which could replace Katco with a new lease
        facility. Under these new leasing options, in accordance with FIN 46,
        AEP would not consolidate the assets or debt of the Power Generation
        Facility.

        Nuclear Plant Outages - Affecting AEP, I&M and TCC

        In April 2003, engineers at STP found a small quantity of powdery
        residue during inspections conducted regularly as part of refueling
        outages. STP officials are working closely with the NRC to safely return
        the unit to service. The NRC will review any corrective action prior to
        its implementation and restart of the unit.

        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.

        Management is unable to predict the length of time that the STP and Cook
        Plant units may be unavailable or the costs of corrective actions at
        this time. Cook Unit 2 was already planned for a refueling outage
        starting May 5. We have commitments to provide power to customers during
        the outages. Therefore, we will be subject to fluctuations in the market
        prices of electricity and purchased replacement energy could be a
        significant cost.

        Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo,
         CSPCo, I&M, and OPCo

        As discussed in Note 9 of the Combined Notes to Financial Statements in
        the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have been
        involved in litigation regarding generating plant emissions under the
        Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
        I&M, OPCo and eleven unaffiliated utilities modified certain units at
        coal-fired generating plants in violation of the Clean Air Act. Federal
        EPA filed complaints against AEP subsidiaries in U.S. District Court for
        the Southern District of Ohio. A separate lawsuit initiated by certain
        special interest groups was consolidated with the Federal EPA case. The
        alleged modification of the generating units occurred over a 20 year
        period.

        Under the Clean Air Act, if a plant undertakes a major modification that
        directly results in an emissions increase, permitting requirements might
        be triggered and the plant may be required to install additional
        pollution control technology. This requirement does not apply to
        activities such as routine maintenance, replacement of degraded
        equipment or failed components, or other repairs needed for the
        reliable, safe and efficient operation of the plant. The Clean Air Act
        authorizes civil penalties of up to $27,500 per day per violation at
        each generating unit ($25,000 per day prior to January 30, 1997). In
        2001, the District Court ruled claims for civil penalties based on
        activities that occurred more than five years before the filing date of
        the complaints cannot be imposed. There is no time limit on claims for
        injunctive relief.

        Management believes its maintenance, repair and replacement activities
        were in conformity with the Clean Air Act and intends to vigorously
        pursue its defense.

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

        In December 2000, Cinergy Corp., an unaffiliated utility, which operates
        certain plants jointly owned by CSPCo, reached a tentative agreement
        with 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.

        NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo,
         SWEPCo and TCC

        Federal EPA issued a NOx Rule requiring substantial reductions in NOx
        emissions in a number of eastern states, including certain states in
        which the AEP System's generating plants are located. The NOx Rule has
        been upheld on appeal. The compliance date for the NOx Rule is May 31,
        2004.

        In 2000, Federal EPA also adopted a revised rule (the Section 126 Rule)
        granting petitions filed by certain northeastern states under the Clean
        Air Act. The rule imposes emissions reduction requirements comparable to
        the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired
        generating units. Affected utilities, including certain AEP operating
        companies, petitioned the D.C. Circuit Court to review the Section 126
        Rule.

        After review, the D.C. Circuit Court instructed Federal EPA to justify
        the methods it used to allocate allowances and project growth for both
        the NOx Rule and the Section 126 Rule. AEP subsidiaries and other
        utilities requested that the D.C. Circuit Court vacate the Section 126
        Rule or suspend its May 2003 compliance date. In 2001, the D.C. Circuit
        Court issued an order tolling the compliance schedule until Federal EPA
        responds to the Court's remand. On April 30, 2002, Federal EPA announced
        that May 31, 2004 is the compliance date for the Section 126 Rule.
        Federal EPA published a notice in the Federal Register on May 1, 2002
        advising that no changes in the growth factors used to set the NOx
        budgets were warranted. In June 2002, AEP subsidiaries joined other
        utilities and industrial organizations in seeking a review of Federal
        EPA's actions in the D.C. Circuit Court. This action is pending.

        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 date is May 2003 for TCC and
        May 2005 for SWEPCo.

        AEP is installing a variety of emission control technologies to reduce
        NOx emissions to comply with the applicable state and Federal NOx
        requirements. This includes selective catalytic reduction (SCR)
        technology on certain units and non-SCR technologies on a larger number
        of units. During 2001 SCR technology commenced operations on OPCo's
        Gavin Plant. Installation of SCR technology on Amos and Mountaineer
        plants was completed and commenced operation in May 2002. Construction
        of SCR technology at certain other AEP generating units continues.
        Non-SCR technologies have been installed and commenced operation on a
        number of units across the AEP System and additional units will be
        equipped with these technologies.

        The AEP NOx compliance plan is a dynamic plan that is continually
        reviewed and revised as new information becomes available on the
        performance of installed technologies and the cost of planned
        technologies. Certain compliance steps may or may not be necessary as a
        result of this new information. Consequently, the plan has a range of
        possible outcomes. Our current estimates indicate that AEP's compliance
        with the NOx Rule, the Texas Commission on Environmental Quality rule
        and the Section 126 Rule could result in required capital expenditures
        in the range of $1.3 billion to $1.7 billion, of which $918 million has
        been spent through March 31, 2003. Estimated compliance cost ranges and
        amounts spent by registrant subsidiaries are as follows:

                                         Estimated              Amount
                                     Compliance Costs           Spent
                                                  (in millions)
               AEGCo                     $   24                  $  5
               APCo                         463                   250
               CSPCo                         87                    54
               I&M                           34                     8
               KPCo                         176                   164
               OPCo                       495-824                 404
               SWEPCo                        37                    23
               TCC                            5                     5

        Since compliance costs cannot be estimated with certainty, the actual
        cost to comply could be significantly different than the estimates
        depending upon the compliance alternatives selected to achieve
        reductions in NOx emissions. Unless any capital and operating costs for
        additional pollution control equipment are recovered from customers,
        they will have an adverse effect on future results of operations, cash
        flows and possibly financial condition.


        Enron Bankruptcy -  Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

        On October 15, 2002, certain subsidiaries of AEP filed claims against
        Enron and its subsidiaries in the bankruptcy proceeding filed by the
        Enron entities which are pending in the U.S. Bankruptcy Court for the
        Southern District of New York. At the date of Enron's bankruptcy,
        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 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 preliminary 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 are unable to
        predict whether these discussions will lead to an agreement on these
        subjects. If these discussions do not lead to an agreement, there may be
        a dispute with Enron concerning our ability to continue utilization of
        the Bammel storage facility and certain appurtenant pipelines under the
        existing agreements.

        We also entered into an agreement with BAM Lease Company which grants
        HPL the right to use approximately 65 billion cubic feet of cushion gas
        (or pad gas) required for the normal operation of the Bammel gas storage
        facility. The Bammel Gas Trust, which purportedly owned approximately 55
        billion cubic feet of the gas, had entered into a financing arrangement
        in 1997 with Enron and a group of banks. These banks purported to have
        certain rights to the gas in certain events of default. In connection
        with AEP's acquisition of HPL, the banks entered into an agreement
        granting HPL's exclusive use of the cushion gas and released HPL from
        liabilities and obligations under the financing arrangement. HPL was
        thereafter informed by the banks of a purported default by Enron under
        the terms of the referenced financing arrangement. In July 2002, the
        banks filed a lawsuit against HPL seeking a declaratory judgment that
        they have a valid and enforceable security interest in this cushion gas
        which would permit them to cause the withdrawal of this gas from the
        storage facility. In September 2002, HPL filed a general denial and
        certain counterclaims against the banks. HPL also filed a motion to
        dismiss. Management is unable to predict the outcome of this lawsuit or
        its impact on AEP's financial position, results of operations and cash
        flows.

        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 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.

        Enron has recently instituted proceedings against other energy trading
        counterparties challenging the practice of utilizing offsetting
        receivables and payables and related collateral across various Enron
        entities. We believe that we have the right to utilize similar
        procedures in dealing with payables, receivables and collateral with
        Enron entities by offsetting trading payables owed to various Enron
        entities against trading receivables due to several AEP subsidiaries. An
        additional expense of up to $110 million may be incurred without such
        offsets. We believe we have legal defenses to any challenge that may be
        made to the utilization of such offsets but at this time are unable to
        predict the ultimate resolution of this issue.

        Shareholder Lawsuits - Affecting AEP

        In the fourth quarter of 2002 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 AEP failed to disclose that alleged
        "round trip" trades resulted in an overstatement of revenues, that AEP
        failed to disclose that AEP traders falsely reported energy prices to
        trade publications that published gas price indices and that AEP failed
        to disclose that it did not have in place sufficient management controls
        to prevent round trip trades or false reporting of energy prices. The
        plaintiffs seek recovery of an unstated amount of compensatory damages,
        attorney fees and costs. 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 AEP executives,
        members of the AEP Board of Directors and AEP's independent auditor. AEP
        intends to vigorously defend against these actions. Also in the fourth
        quarter of 2002, two shareholder derivative actions were filed in state
        court in Columbus, Ohio against AEP and its Board of Directors alleging
        a breach of fiduciary duty for failure to establish and maintain
        adequate internal controls over AEP's gas trading operations; and, in
        the fourth quarter of 2002 and the first quarter of 2003, three lawsuits
        were filed against AEP, certain AEP 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. The
        derivative actions and the ERISA actions are in the initial pleading
        stage. AEP intends to vigorously defend against these actions.

        California Lawsuit -Affecting AEP

        In November 2002, Cruz Bustamante, Lieutenant Governor of California,
        filed a lawsuit in Los Angeles County, California Superior Court against
        forty energy companies, including AEP, and two publishing companies
        alleging violations of California law through alleged fraudulent
        reporting of false natural gas price and volume information with an
        intent to affect the market price of natural gas and electricity. This
        case is in the initial pleading stage. AEP has filed a motion to
        dismiss. AEP intends to vigorously defend against this action.

        Bank of Montreal Claim - Affecting AEP

        In March 2003, Bank of Montreal (BOM) terminated all natural gas
        trading deals and has claimed approximately $25 million is owed to BOM
        by AEP which BOM subsequently has changed to approximately $34 million.
        In April 2003, AEP filed a lawsuit against BOM claiming BOM had acted
        contrary to industry practice in calculating termination and
        liquidation amounts and that BOM had acknowledged in March 2003 that it
        owed AEP approximately $68 million. Alternatively, AEP is claiming that
        BOM owes approximately $45 million to AEP. 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 - Affecting AEP

        In October 2002, AEP filed its demand for arbitration with the American
        Arbitration Association to initiate formal arbitration proceedings in a
        dispute with the Williams Companies (Williams). The proceeding results
        from Williams' repudiation of its obligations to provide physical power
        deliveries to AEP and Williams' failure to provide the monetary security
        required for natural gas deliveries by AEP. Consequently, both parties
        claimed default and terminated all outstanding natural gas and electric
        power trading deals among the various Williams and AEP affiliates.
        Williams claimed that AEP owes approximately $130 million in connection
        with the termination and liquidation of all trading deals. AEP believes
        it has valid claims arising from Williams' actions and is seeking, in
        part, a determination that either no amount is due or that a lesser
        amount is due from AEP to Williams (which lesser amount is fully
        reserved by AEP) and the extent of any other damages and legal or
        equitable relief available. Although management is unable to predict the
        outcome of this matter, it is not expected to have a material impact on
        results of operations, cash flows or financial condition.

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

        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. 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 conditions.

        Energy Market Investigation  - Affecting AEP

        As discussed in the 2002 Annual Report, 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, the U.S. Department of Justice and the California
        attorney general during 2002. AEP's management responded to the
        inquiries and provided the requested information.

        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
        had received an informal data request from the SEC seeking that AEP
        voluntarily provide information. The subpoena seeks additional
        information and is part of the SEC's formal investigation. AEP will
        continue to cooperate with the SEC.

        Other

        AEP and its subsidiary registrants continue to be involved in certain
        other matters discussed in the 2002 Annual Report.

  8.    GUARANTEES

        In November 2002, the FASB issued FASB Interpretation No. 45,
        "Guarantor's Accounting and Disclosure Requirements for Guarantees,
        Including Indirect Guarantees of Indebtedness of Others" (FIN 45) which
        clarifies the accounting to recognize a liability related to issuing a
        guarantee, as well as additional disclosures of guarantees. This new
        guidance is an interpretation of SFAS 5, 57, and 107 and a rescission of
        FIN 34. The initial recognition and initial measurement provisions of
        FIN 45 is effective on a prospective basis to guarantees issued or
        modified after December 31, 2002. The disclosure requirements of FIN 45
        were effective for financial statements of interim or annual periods
        ending after December 15, 2002.

        There are no liabilities recorded for all of the guarantees described
        below in accordance with FIN 45 as these guarantees were entered into
        prior to December 31, 2002 or have immaterial values which were not
        recorded. There is no collateral held in relation to these guarantees
        and there is no recourse to third parties in the event these guarantees
        are drawn.

        Certain AEP subsidiaries have entered into standby letters of credit
        (LOC) with third parties. These LOCs cover gas and electricity trading
        contracts, construction contracts, insurance programs, security
        deposits, debt service reserves, drilling funds and credit enhancements
        for issued bonds. All of these LOCs were issued at a subsidiary level of
        AEP in the subsidiaries' ordinary course of business. TCC issued one of
        the LOCs for credit enhancement of issued bonds. At March 31, 2003, the
        maximum future payments of all the LOCs are approximately $158 million
        with maturities ranging from April 2003 to January 2011. TCC's LOC was
        for approximately $40.9 million with a maturity date of November 2003.
        I&M's LOC was approximately $2 million with a maturity date of March
        2003. Since AEP is the parent to all these subsidiaries, it holds all
        assets of the subsidiaries as collateral. There is no recourse to third
        parties in the event these letters of credit are drawn.

        The following AEP subsidiaries have entered into guarantees of third
        parties obligations:

        CSW Energy and CSW International have guaranteed 50% of the required
        debt service reserve of Sweeny Cogeneration (Sweeny), an IPP of which
        CSW Energy is a 50% owner. The guarantee was provided in lieu of Sweeny
        funding the debt reserve as a part of financing. In the event that
        Sweeny does not make the required debt payments, CSW Energy and CSW
        International have a maximum future payment exposure of approximately
        $3.7 million, which expires June 2020.

        Additionally, CSW guaranteed 50% of the required debt service reserve
        for Polk Power Partners, another IPP of which CSW Energy owns 50%. In
        the event that Polk Power does not make the required debt payments, CSW
        has a maximum future payment exposure of approximately $4.7 million,
        which expires July 2010.

        In connection with reducing the cost of the lignite mining contract for
        its Henry W. Pirkey Power Plant, SWEPCo has agreed under certain
        conditions, to assume the revolving credit agreement, capital lease
        obligations, and term loan payments of the mining contractor. In the
        event the mining contractor defaults under any of these agreements,
        SWEPCo's total future maximum payment exposure is approximately $73
        million with maturity dates ranging from April 2003 to February 2012.

        As part of the process to receive a renewal of a Texas Railroad
        Commission permit for lignite mining, SWEPCo has agreed to provide
        guarantees of mine reclamation in the amount of approximately $85
        million. Since SWEPCo uses self-bonding, the guarantee provides for
        SWEPCo to commit to use its resources to complete the reclamation in the
        event the work is not completed by a third party miner. At March 31,
        2003, the cost to reclaim the mine is estimated to be approximately $36
        million. This guarantee ends upon depletion of reserves estimated at
        2035 plus 6 years to complete reclamation.

        See Note 13 "Minority Interest in Finance Subsidiary" for disclosure for
        the guaranteed support of AEP for Caddis Partners, LLC.

        AEP and its subsidiaries enter into several types of contracts, which
        would require indemnifications. Typically these contracts include, but
        are not limited to, sale agreements, lease agreements, purchase
        agreements and financing agreements. Generally these agreements may
        include, but are not limited to, indemnifications around certain tax,
        contractual and environmental matters. With respect to sale agreements,
        AEP's exposure generally does not exceed the sale price. AEP cannot
        estimate the maximum potential exposure for any of these
        indemnifications entered prior to December 31, 2002 due to the
        uncertainty of future events. In the first quarter of 2003, AEP entered
        into several sale agreements as discussed in Note 10. These sale
        agreements include indemnifications with a maximum exposure of
        approximately $60 million. There are no liabilities recorded for any
        indemnifications due to the insignificant fair value of the
        indemnification or due to the fact that they were entered prior to
        December 31, 2002.

        AEP and its 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 March 31, 2003, the maximum potential loss for
        these lease agreements was approximately $25 million assuming the fair
        market value of the equipment is zero at the end of the lease term. The
        maximum potential loss by registrant is as follows:

                                             Maximum Potential Loss
        Subsidiary                              (in millions)

        APCo                                 $ 0.7
        CSPCo                        0.5
        I&M                                 3.3
        KPCo                                            0.7
        OPCo                                2.7
        PSO                                 2.9
        SWEPCo                       3.1
        TCC                                 5.8
        TNC                                              2.2
        Other AEP Subsidiaries                  3.5

        Total                               $25.4

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. Termination benefits expense relating
        to 1,120 terminated employees totaling $75.4 million pre-tax was
        recorded in the fourth quarter of 2002. Of this amount, AEP paid $9.5
        million and $51.2 million to these terminated employees in the fourth
        quarter of 2002 and the first quarter of 2003, respectively. The
        termination benefits expense was classified as Maintenance and Other
        Operation expense on AEP's Consolidated Statements of Operations and as
        Other Operation expense on the other registrants' statements of
        operations. No additional termination benefits expense related to the
        SEI initiative was recorded during the first quarter of 2003.
<TABLE>
<CAPTION>

        The following table shows the beginning and ending termination benefits
        accrual amounts and the total termination related payments made during
        the first quarter 2003.

                                                                        Total Termination              Total Termination
                                                                      Payments Made During                 Benefits
                                      Total Termination                        the                    Accrued at 3/31/03
                                           Benefits                       Three Months                   (in millions)
            Subsidiary               Accrued at 12/31/02                  Ended 3/31/03
              Company                   (in millions)                     (in millions)

<S>                                           <C>                             <C>                              <C>
            AEGCo                             $ 0.3                           $ 0.3                            $ -
            APCo                               12.2                             9.3                             2.9
            CSPCo                               4.5                             3.8                             0.7
            I&M                                13.1                             9.3                             3.8
            KPCo                                2.5                             1.8                             0.7
            OPCo                                7.1                             5.4                             1.7
            PSO                                 3.0                             2.4                             0.6
            SWEPCo                              3.1                             2.8                             0.3
            TCC                                 5.5                             5.5                              -
            TNC                                 1.6                             1.6                              -
            Other  Subsidiaries
                                               13.0                             9.0                             4.0
              Totals                          $65.9                           $51.2                           $14.7
</TABLE>
10. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

        DISPOSITIONS

        In the first quarter of 2003, AEP completed a number of asset
        dispositions determined not to be part of its core Utility Operations:

        Disposition of Assets of C3 Communications

        On February 28, 2003, C3 Communications sold the majority of its assets
        for a sales price of $7.25 million. C3 received $7 million in cash and a
        one-year non-interest bearing note receivable of $250,000 from the
        purchaser. AEP provided for an $82 million pre-tax asset impairment in
        the fourth quarter 2002, and the effect of the sale on first quarter
        2003 results of operations was not significant.

        Disposition of Mutual Energy Companies

        On December 23, 2002, AEP received PUCT regulatory approval on a sale of
        two of its Texas retail energy providers (REP's). As part of the REP
        sale, MESC received a prepayment of approximately $30 million from the
        purchaser. The prepaid service revenue was deferred on the books of MESC
        to be amortized over the two-year term of the back office service
        agreement.

        On February 28, 2003, AEP completed the sale of Mutual Energy Service
        Company, LLC (MESC) for $30.4 million dollars and realized a pre-tax
        gain of approximately $12.2 million dollars. In addition, the $27.2
        million pre-tax gain which was previously deferred and was being
        recognized over the two-year term of a back office service agreement was
        recognized as part of the gain calculation in the first quarter of 2003
        as no further service obligations existed for MESC.

<TABLE>
<CAPTION>
        Disposition of Water Heater Assets

        AEP sold its 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. AEP 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). AEP, APCo, CSPCo, I&M, KPCo, and OPCo operated a
        program to lease electric water heaters to residential and commercial
        customers until a decision was reached in the fourth quarter of 2002 to
        discontinue the program and offer the assets for sale. See table below
        for detail of charges by Company:


                                        Asset Impairment              Lease Prepayment                 Loss on Sale
                                        Charge Recorded               Penalty Recorded           Recorded in First Quarter
        Subsidiary                     in Fourth Quarter              in Fourth Quarter               2003 (Pre-tax)
        Company                          2002 (Pre-tax)                2002 (Pre-tax)
                                                                               (in millions)
<S>                                               <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
        Other Non- Registrant
         Subsidiaries
                                                   0.126                        0.156                          0.161
            Total                                 $3.202                       $3.942                         $3.920
</TABLE>


        Disposition of AEP Gas Power Systems

        In 2001, AEP 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 (Gas Power) sold
        its assets. AEP recognized a goodwill impairment loss of $12.2 million
        in the first quarter of 2002, and the effect of the asset sale on the
        first quarter 2003 results of operations was not significant.


        DISCONTINUED OPERATIONS

        The results of operations of the entities shown below, affecting AEP,
        have been classified as Discontinued Operations for all periods
        presented. The assets and liabilities of Pushan Power Plant and Eastex
        were aggregated on AEP's Consolidated Balance Sheets as Assets Held for
        Sale and Liabilities Held for Sale (see table at the end of the Assets
        Held For Sale section below for more detailed information):

<TABLE>
<CAPTION>

                                                                                  Pushan Power
                                             SEEBOARD           CitiPower            Plant               Total
                                                                                     Eastex
                                                                             (in millions)

<S>                                              <C>                <C>                 <C>                 <C>            <C>
        2003 Revenue                             $ -                $ -                 $15                 $31            $ 46
        2002 Revenue                              383                 97                 15                  12             507

        2003 Earnings
         (Loss) After Tax                        $ -                $ -                 $ -                 $(9)           $(9)
        2002 Earnings
         (Loss) After Tax                          33                (11)                 2                  (2)            22


</TABLE>


        ASSETS HELD FOR SALE

        As discussed in the 2002 Annual Report, during 2002, AEP (and its
        registrant subsidiaries, as applicable) recorded an estimated loss on
        disposal of assets held for sale.

        Eastex
        In 1998, CSW began construction of a natural gas-fired cogeneration
        facility (Eastex) located near Longview, Texas and commercial operations
        commenced in December 2001. In June 2002, AEP requested that the FERC
        allow it to modify the FERC Merger Order and substitute Eastex as a
        required divestiture under the order, due to the fact that the agreed
        upon market-power related divestiture of a plant in Oklahoma was no
        longer feasible. The FERC approved the request at the end of September
        2002. Subsequently, in the fourth quarter of 2002, AEP solicited bids
        for the sale of Eastex and several interested buyers were identified by
        December 2002. We still anticipate that the sale of assets will be
        completed by the end of 2003. The estimated pre-tax loss on sale of
        $218.7 million, which was based on the estimated fair value of the
        facility and indicative bids by interested buyers, was recorded in
        Discontinued Operations in AEP's Consolidated Statements of Operations
        during the fourth quarter 2002.

        Results of operations of Eastex have been reclassified as Discontinued
        Operations in accordance with SFAS 144. The assets and liabilities of
        Eastex have been included on AEP's Consolidated Balance Sheets as held
        for sale. See the tables at the end of this section for more detailed
        information.

        Pushan Power Plant
        In the fourth quarter of 2002, AEP began active negotiations to sell its
        interest in the Pushan Power Plant (Pushan) in Nanyang, China to one of
        the minority interest partners. We currently anticipate negotiations to
        be completed by the end of 2003 with an estimated pre-tax loss on
        disposal of $20.0 million, based on an indicative price expression. This
        estimated loss was recorded in Discontinued Operations in AEP's
        Consolidated Statements of Operations during the fourth quarter of 2002.

        Results of operations of Pushan have been reclassified as Discontinued
        Operations in accordance with SFAS 144. The assets and liabilities of
        Pushan have been classified on AEP's Consolidated Balance Sheets as held
        for sale. See the tables at the end of this section for more detailed
        information.

        Telecommunications
        AEP had developed businesses to provide telecommunication services to
        businesses and to other telecommunication companies through broadband
        fiber optic networks operated in conjunction with AEP's electric
        transmission and distribution lines. The businesses included AEP
        Communications, LLC (AEPC), C3 Communications, Inc. (C3), and a 50%
        share of AFN Networks, LLC (AFN), a joint venture. Due to the difficult
        economic conditions in these businesses and the overall
        telecommunications industry, and other operating problems, the AEP Board
        approved in December 2002 a plan to cease operations of these
        businesses. AEP initiated steps to market the assets of the businesses
        to potential interested buyers in the fourth quarter of 2002. As a
        result, the assets of C3 were sold in February 2003. See "Disposition of
        Assets of AEP Communications" earlier in this note for further
        information.

        The sale of all telecommunication assets is expected by the end of 2003
        with an estimated pre-tax impairment loss of $76 million related to AEPC
        and an estimated pre-tax loss in value of the investment in AFN of $13.8
        million. The estimated losses are based on indicative bids by potential
        buyers. The estimated losses were recorded in Investment Value and Other
        Impairment Losses in AEP's Consolidated Statements of Operations during
        the fourth quarter 2002.

        Newgulf Facility
        In 1995, CSW purchased an 85 MW gas-fired peaking electrical generation
        facility located near Newgulf, Texas (Newgulf). In October 2002, AEP
        began negotiations with a likely buyer of the facility. AEP still
        expects a sale to be completed by the end of 2003 with an estimated
        pre-tax loss on sale of $11.8 million based on an indicative bid by the
        likely buyer. This loss was recorded as Asset Impairments on AEP's
        Consolidated Statements of Operations during the fourth quarter 2002.
        Newgulf's Property, Plant and Equipment, net of accumulated
        depreciation, has been classified on AEP's Consolidated Balance Sheets
        as held for sale. See the tables at the end of this section for more
        detailed information.

        Nordic Trading
        In October 2002, AEP announced that its ongoing energy trading
        operations would be centered around its generation assets. As a result,
        AEP took steps to exit its coal, gas, and electricity trading activities
        in Europe, except for those activities necessary to support the U.K.
        Generation operations. The Nordic Trading business acquired earlier in
        2002, was made available for sale to potential buyers. The estimated
        pre-tax loss on disposal in 2002 of $5.3 million consisted of impairment
        of goodwill of $4.0 million and impairment of assets of $1.3 million,
        and was included in Asset Impairments on AEP's Consolidated Statements
        of Operations during the fourth quarter of 2002. Management's
        determination of a zero fair value at the end of 2002 was based on
        discussions with a potential buyer. The assets and liabilities of Nordic
        Trading have been classified on AEP's Consolidated Balance Sheets as
        held for sale. 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 will not be significant.

        Excess Equipment
        In November 2002, as a result of a cancelled development project, AEP
        obtained title to a surplus gas turbine generator. AEP has been
        unsuccessful in finding potential buyers of the unit, including its own
        internal generation operators, due to an over-supply of generation
        equipment available for sale. Sale of the turbine is currently still
        projected before the end of 2003 with an estimated 2002 pre-tax loss on
        disposal of $23.9 million, based on market prices of similar equipment.
        This estimated loss was recorded in Asset Impairments on AEP's
        Consolidated Statements of Operations during the fourth quarter of 2002.
        The Other Assets have been classified on AEP's Consolidated Balance
        Sheets as held for sale. See the tables at the end of this section for
        more detailed information.

        Excess Real Estate
        In the fourth quarter of 2002, AEP began to market an under-utilized
        office building in Dallas, TX obtained through the merger with CSW. Sale
        of the facility is still projected by the end of 2003 and an estimated
        pre-tax loss on disposal of $15.7 million was recorded during the fourth
        quarter of 2002 based on an estimated sales price. This estimated loss
        was included in Asset Impairments on AEP's Consolidated Statements of
        Operations. The property asset has been classified on AEP's Consolidated
        Balance Sheets as held for sale. See the tables at the end of this
        section for more detailed information.

<TABLE>
<CAPTION>

        The assets and liabilities of the entities held for sale at March 31,
2003 and December 31, 2002 are as follows:


                                               Pushan Power
                                               Plant         Newgulf        Nordic           Excess             Excess
                                    Eastex                   Facility       Trading          Real Estate      Equipment       Total
          At March 31, 2003                                                          (in millions)
          Assets:
<S>                                    <C>        <C>            <C>         <C>             <C>              <C>          <C>
           Current Assets              $20        $ 16           $ -         $50             $ -              $ -          $ 86
           Property, Plant   and
          Equipment,
            Net                          -         149             6          -               18                -           173
           Deferred Income
            Taxes                        -          -              -           6               -                -             6
           Other Assets                  -          -              -           3               -               12            15
             Total Assets
              Held for Sale            $20        $165           $ 6         $59             $18              $12          $280

          Liabilities:
           Current   Liabilities
                                       $ 6        $ 22           $ -         $56             $ -              $ -          $ 84
           Long-term Debt                -          22             -          -                -                -            22
           Other Liabilities             4          49             -           2               -                -            55
             Total
              Liabilities
              Held For Sale            $10        $ 93           $ -         $58             $ -              $ -          $161

</TABLE>
<TABLE>
<CAPTION>

                                    Pushan                             Excess                 Water       Tele-
                                    Power     Newgulf     Nordic       Real     Excess        Heater      communica-
                         Eastex     Plant     Facility    Trading      Estate   Equipment     Program     tions       Total
At December 31, 2002                                     (in millions)
Assets:
<S>                           <C>      <C>        <C>           <C>       <C>         <C>           <C>       <C>         <C>
 Current Assets               $15      $ 19       $ -           $35       $ -         $ -           $ 1       $ -         $ 70
 Property, Plant   and
  Equipment, Net
                                -       132         6            -         18           -            38        6           200
 Other Assets                   -        -          -            10         -          12             -         -           22
   Total Assets
    Held for Sale             $15      $151       $ 6           $45       $18         $12           $39       $ 6         $292

Liabilities:
 Current  Liabilities
                              $ 8      $ 28       $ -           $48       $ -         $ -           $ -       $ -         $ 84
 Long-term Debt                 -        25         -             -         -           -             -         -           25
 Other Liabilities              4        26         -             3         -           -             -         -           33
    Total
     Liabilities
     Held For Sale            $12      $ 79       $ -           $51       $ -         $ -           $ -       $ -         $142

</TABLE>



11. BUSINESS SEGMENTS

In October 2002, AEP announced that it was exiting wholesale markets where it
does not own assets and announced certain reassignment changes in members of the
Office of the Chairman group. A further decision was later made in 2003 by the
Board of Directors and management to focus on AEP's core electric utility
businesses. Assets outside of domestic generation, distribution and transmission
of electricity are considered to be non-core and are being evaluated and may be
sold when market conditions are more favorable. In the fourth quarter of 2002,
as more fully described in Note 13 of the 2002 Annual Report, management
recognized pre-tax impairments totaling $1.4 billion, principally related to
non-regulated assets and investments and characterized $247 million of assets
and investments as Held for Sale.

During 2001 and most of 2002, AEP was in the process of restructuring into two
main businesses, i.e. the regulated business and the non-regulated business. The
extent to which these were to be further divided into business segments was
dependent on how the businesses were to be managed and how the chief operating
decision maker of each business would monitor the performance of such
businesses. However, until deregulation developed further, regulatory hurdles
were cleared and corporate separation was achieved, management was unable to
determine precisely what segments would exist for the various businesses after
corporate separation.

As a result of the changes in AEP's business strategy noted above, management's
desire to concentrate on its core businesses, delays in corporate separation and
the repeal of and/or delay of competition and deregulation in AEP's
jurisdictions, a decision was made to realign the segments for financial
reporting purposes in the first quarter of 2003 to reflect the manner in which
AEP's chief operating decision makers (the Office of the Chairman group) now
manage the business. Assets have been identified as either being core or
non-core investments and are being managed as such and the results of operations
are reported to senior management in this format as well as to AEP's investors
in its earning releases and presentations to financial analysts.

Throughout 2002, AEP's segments for financial reporting purposes were Wholesale,
Energy Delivery and Other. The business activities were as follows:

Wholesale
- Generation of electricity for sale to retail and wholesale customers - Gas
pipeline and storage facilities - Marketing and trading of electricity, gas,
coal and other commodities - Coal mining, bulk commodity barging operations and
other energy supply related businesses

Energy Delivery
-        Domestic electricity transmission
-        Domestic electricity distribution

Other
-        Energy services
-        Telecommunication services (reclassified as Held for
          Sale as of December 31, 2002)

As a result of the Board of Director's and management's decision to concentrate
on its core asset base and exit wholesale operations where AEP does not own
assets, Wholesale will no longer be a reporting segment. AEP's core operations
are now managed as vertically integrated electricity generation and energy
delivery businesses. The operations are managed on an integrated basis because
of the substantial impact of bundled, primarily cost-based rates and regulatory
oversight on the business process, cost structure and operating results. Assets
not meeting the Board of Director's and management's core strategy are
classified into three Investments segments. AEP's current segments, for which
discrete financial information is available, engage in business activities for
which AEP earns revenues and incurs expenses. The operating results of these
segments are regularly reviewed by AEP's chief operating decision maker. The
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

Investments - Other
o        Coal mining, bulk commodity barging operations and other
          energy supply businesses

Management has aggregated electricity transmission, distribution and generation
within Utility Operations because their economic characteristics are similar and
their revenue is substantially determined by regulated jurisdictions. AEP's
electricity transmission and distribution operations are entirely regulated by
FERC and state regulatory jurisdictions. Electric generation sales to retail
customers are determined by the respective state jurisdictions, even for
customers in Ohio, Texas and Virginia which are in transition to deregulation,
and whose transition rates are still determined by the respective state
jurisdictions.

With respect to Investments, management has aggregated data into three separate
reporting groupings, due to the significance of each business and the manner in
which they are operated. The Investments-Gas Operations segment includes two
intra-state gas pipeline and storage operations located in Louisiana and Texas
and also includes risk management activities around these assets. The
Investments-UK Operations segment includes the generation of electricity for
sale to wholesale customers in the UK. Investments-Other includes the coal
mining operations and commodity barging operations, all of which share similar
economic characteristics.
<TABLE>
<CAPTION>

The tables below present the reformatted reportable segment information for the
three months ended March 31, 2003 and 2002 based on the changes in business
strategy in the first quarter of 2003. These amounts include certain estimates
and allocations where necessary.



                                                           Investments
                                              Utility        Gas            UK                        Reconciling
                                             Operations    Operations   Operations            Other   Adjustments      Consolidated
        March 31, 2003                                  (in millions)
        Revenues from:
<S>                                           <C>           <C>            <C>              <C>             <C>           <C>
          External Customers                  $ 2,773       $1,102         $   50           $  155          $-            $ 4,080
          Other Operating    Segments
                                                 -              44           -                  13            (57)           -
        Net Income (Loss)                         528          (37)           (55)               4           -                440
        Total Assets                           28,840        4,513          1,493            1,775            280 (a)      36,901

        March 31, 2002
        Revenues from:
          External Customers                  $ 2,258         $433         $  101          $   200          $-            $ 2,992
          Other Operating    Segments
                                                 -              44           -                  33            (77)           -
        Net Income (Loss)                         213          (48)            29             (363)          -               (169)
        Total Assets                           25,056        6,241          1,648            6,905            793 (a)      40,643

        (a) Reconciling adjustments for Total Assets include Assets Held for
Sale and/or Assets of Discontinued Operations.

        All of the 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, which remains unchanged. 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 processes, cost structures and operating results.
</TABLE>

12. LEASES

        OPCo has entered into an agreement with JMG Funding LLP (JMG), an
        unrelated unconsolidated special purpose entity. JMG has a capital
        structure of which 3% is equity from investors with no relationship to
        AEP or any of its subsidiaries and 97% is debt from pollution control
        bonds and other bonds. JMG was formed to design, construct and lease the
        Gavin Scrubber for the Gavin Plant to OPCo. JMG owns the Gavin Scrubber
        and leases it to OPCo. The lease is accounted for as an operating lease.
        Payments under the operating lease are based on JMG's cost of financing
        (both debt and equity) and include an amortization component plus the
        cost of administration. 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. The initial 15-year lease term is
        non-cancelable. At the end of the initial term, OPCo can renew the
        lease, purchase the Gavin Scrubber (terms previously mentioned), or sell
        the Gavin Scrubber. In case of a sale at less than the adjusted
        acquisition cost, OPCo must pay the difference to JMG.

        The use of JMG allows OPCo to enter into an operating lease while
        keeping the tax benefits otherwise associated with a capital lease. As
        of March 31, 2003, unless the structure of this arrangement is changed,
        it is reasonably possible that OPCo will consolidate JMG in the third
        quarter of 2003 as a result of the issuance of FIN 46. Upon
        consolidation, OPCo would record the assets, liabilities, depreciation
        expense, minority interest and debt interest expense of JMG. OPCo would
        eliminate operating lease expense. OPCo's maximum exposure to loss as a
        result of its involvement with JMG is approximately $460 million of
        outstanding debt and equity of JMG as of March 31, 2003.

        On March 31, 2003, OPCo made a prepayment of $90 million under this
        operating lease structure. AEP recognizes lease expense on a
        straight-line basis over the remaining lease term, in accordance with
        SFAS 13 "Accounting for Leases". On March 31, 2003, due to the $90
        million prepayment, the net lease liability became an asset of $67.8
        million. The asset is comprised of $16.7 million included in Other
        current assets and $51.1 million in Other Assets on AEP's Consolidated
        Balance Sheets ($16.7 million in Prepayments and Other and $51.1 million
        in Deferred Charges and Other Assets on OPCo's Balance Sheets) . The
        asset will be amortized over the remaining lease term, which ends in the
        first quarter of 2010.

13. MINORITY INTEREST IN FINANCE SUBSIDIARY

        In August 2001, AEP formed AEP Energy Services Gas Holding Co. II, LLC
        (SubOne) and Caddis Partners, LLC (Caddis). SubOne is a wholly owned
        consolidated subsidiary of AEP that was capitalized with the assets of
        Houston Pipe Line Company, Louisiana Interstate Gas Company (AEP
        subsidiaries) and $321.4 million of AEP Energy Services Gas Holding
        Company (AEP Gas Holding is an AEP subsidiary and parent of SubOne)
        preferred stock, that is convertible into AEP common stock at market
        price on a dollar-for-dollar basis. Caddis was capitalized with $2
        million cash and a subscription agreement that represents an
        unconditional obligation to fund $83 million from SubOne and $750
        million from Steelhead Investors LLC ("Steelhead" - non-controlling
        preferred member interest). As managing member, SubOne consolidates
        Caddis. Steelhead is an unconsolidated special purpose entity and has a
        capital structure of $750 million of which 3% is equity from investors
        with no relationship to AEP or any of its subsidiaries and 97% is debt
        from a syndicate of banks. The use of Steelhead allows AEP to limit its
        risk associated with Houston Pipe Line Company and Louisiana Intrastate
        Gas Company.

        Under the provisions of the Caddis formation agreements, Steelhead
        receives a quarterly preferred return equal to an adjusted floating
        reference rate (4.7426% and 4.4349% for the quarters ended March 31,
        2003 and 2002, respectively). Caddis has the right to redeem Steelhead's
        interest at any time.

        The $750 million invested in Caddis by Steelhead was loaned to SubOne.
        This intercompany loan to SubOne is due August 2006, and is supported by
        the natural gas pipeline assets of SubOne, a cash reserve fund of SubOne
        and SubOne's $321.4 million of preferred stock in AEP Gas Holding. The
        preferred stock is convertible into AEP common stock upon the occurrence
        of certain events including AEP's stock price closing below $18.75 for
        ten consecutive trading days. AEP can elect not to have the transaction
        supported by such preferred stock if SubOne were to reduce its loan with
        Caddis by $225 million (see below). 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 March 31,
        2003, AEP has complied with the covenants contained in the credit
        agreement. In addition, a default under any other agreement or
        instrument relating to AEP and certain subsidiaries' debt outstanding in
        excess of $50 million is an event of default under the credit agreement.

        The initial period of Steelhead's investment in Caddis is through August
        2006. At the end of the initial period, Caddis will either reset
        Steelhead's return rate, re-market Steelhead's interests to new
        investors, redeem Steelhead's interests, in whole or in part including
        accrued return, or liquidate Caddis in accordance with the provisions of
        applicable agreements.

        Steelhead has certain rights as a preferred member in Caddis. Upon the
        occurrence of certain events including a default in the payment of the
        preferred return, Steelhead's rights include: forcing a liquidation of
        Caddis and acting as the liquidator, and requiring the conversion of the
        AEP Gas Holding preferred stock into AEP common stock. If Steelhead
        exercised its rights to force Caddis to liquidate under these
        conditions, then AEP would evaluate whether to refinance at that time or
        relinquish the assets that support the intercompany loan to Caddis.
        Liquidation of Caddis could negatively impact AEP's liquidity.

        Caddis and SubOne are each a limited liability company, with a separate
        existence and identity from its members, and the assets of each are
        separate and legally distinct from AEP. The results of operations, cash
        flows and financial position of Caddis and SubOne are consolidated with
        AEP for financial reporting purposes. Steelhead's investment in Caddis
        and payments made to Steelhead from Caddis are currently reported on
        AEP's Consolidated Statements of Operation and Consolidated Balance
        Sheets as Minority Interest in Finance Subsidiary.

        On May 9, 2003, SubOne borrowed $225 million from AEP and reduced the
        outstanding balance of the loan from Caddis, which Caddis then used to
        reduce the preferred interest held by Steelhead. This payment will allow
        the convertible preferred stock of AEP Gas Holding and the stock price
        trigger discussed above to be eliminated.

        AEP's maximum exposure to loss as a result of its involvement with
        Steelhead is a $2 million capital investment, $83 million under the
        subscription agreement to Caddis for any losses incurred by Caddis and
        the cash reserve fund balance of approximately $42 million (as of March
        31, 2003) due Caddis for default under the intercompany loan agreement.
        Of the remaining $525 million financing, the recourse to AEP for the
        first quarter will increase in the second quarter 2003 by $165 million
        to comply with the covenants.

        As of March 31, 2003, AEP is continuing to review the application of FIN
        46 as it relates to the Steelhead transaction.

<TABLE>
<CAPTION>
14. FINANCING AND RELATED ACTIVITIES

        Long-term debt and other securities issuances and retirements
        during the first three months of 2003 were:

                                   Type                Principal   Interest  Due
         Company                of Debt               Amount      Rate    Date
        Issuances                                   (in millions)   (%)
<S>                                                <C>        <C>     <C>
          AEP                Senior Unsecured Notes  $500       5.375   2010
          CSPCo              Senior Unsecured Notes   250       5.50    2013
          CSPCo              Senior Unsecured Notes   250       6.60    2033
          OPCo               Senior Unsecured Notes   250       5.50    2013
          OPCo               Senior Unsecured Notes   250       6.60    2033
          TCC                Senior Unsecured Notes   150       3.00    2005
          TCC                Senior Unsecured Notes   100     Variable  2005
          TCC                Senior Unsecured Notes   275       5.50    2013
          TCC                Senior Unsecured Notes   275       6.65    2033
          TNC                Senior Unsecured Notes   225       5.50    2013

          Company
        Retirements
         AEP                Bank Facility          1,300     Variable  2003
         AEP                Senior Unsecured Notes    49       6.125   2006
         CSPCo              First Mortgage Bonds       2       8.70    2022
         CSPCo              First Mortgage Bonds      15       8.55    2022
         CSPCo              First Mortgage Bonds      14       8.40    2022
         CSPCo              First Mortgage Bonds      13       8.40    2022
         SWEPCo             First Mortgage Bonds      55       6.625   2003
         TCC                First Mortgage Bonds      16       6.875   2003
         TCC                Securitization Bonds      32       3.54    2005

         Non-Registrant:
         AEP Subsidiaries   Notes Payable              2     Variable  2007
         AEP Subsidiaries   Revolving Credit
                              Agreement              291     Variable  2003
         AEP Subsidiaries   Senior Unsecured Notes    17       6.50    2003



        In addition to the transactions reported in the table above, the
        following table lists intercompany retirements of debt due to AEP.

                                   Type                 Principal  Interest  Due
          Company               of Debt                Amount      Rate    Date
        Retirements                                 (in millions)   (%)

             CSPCo              Notes Payable           $160      6.501   2006
             OPCo               Notes Payable            240      6.501   2006
</TABLE>

        Other Matters

        In April 2003, AEP announced that they will have an early redemption on
May 30, 2003 of the following:

o        $125.5 million of CSPCo's First Mortgage Bonds
o        $165 million of I&M's Junior Subordinated Debentures
o        $90 million of I&M's First Mortgage Bonds

        Consequently, the debt has been classified as Long-term Debt Due Within
        One Year on their respective Balance Sheets due to the refinancing debt
        having been issued prior to March 31, 2003.

        Common Stock

        In March 2003, AEP issued 56 million shares of common stock at $20.95
        per share through an equity offering and received net proceeds of $1,141
        million (net of issuance costs of $36 million). Proceeds from the sale
        of common stock were used to pay down both short-term and long-term debt
        with the balance being held in cash.


<PAGE>



           REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
          OF FINANCIAL CONDITION, ACCOUNTING POLICIES AND OTHER MATTERS

This is our combined presentation of management's discussion and analysis of
financial condition, accounting policies and other matters for AEP and its
registrant subsidiaries. Management's discussion and analysis of results of
operations for AEP and each of its registrant subsidiaries for the quarter ended
March 31, 2003 is presented with their financial statements earlier in this
document.

FINANCIAL CONDITION

Credit Ratings
As discussed in the 2002 Annual Report, the rating agencies have been conducting
credit reviews of AEP and its registrant subsidiaries.

In February 2003, Moody's Investors Service (Moody's) completed their review of
AEP and its rated subsidiaries. The results of that review were downgrades of
the following ratings for unsecured debt: AEP to Baa3 from Baa2, APCo from Baa1
to Baa2, PSO from A2 to Baa1, SWEPCo from A2 to Baa1 and TCC from Baa1 to Baa2.
TNC, which had no senior unsecured notes outstanding at the time of the ratings
action, had its mortgage bond debt downgraded from A2 to A3. AEP's commercial
paper was also downgraded from P-2 to P-3. 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 its subsidiaries senior unsecured ratings
from BBB+ to BBB along with the first mortgage bonds of AEP subsidiaries. S&P
placed AEP on stable rating and closed their review.

In March 2003, Fitch Ratings Service downgraded the parent company (AEP) to BBB
from BBB+ with stable outlook.

Current ratings of AEP's subsidiaries' first mortgage bonds are listed in the
following table:

Company                      Moody's    S&P      Fitch

APCo                         Baa1       BBB      A-
CSPCo                        A3         BBB      A
I&M                          Baa1       BBB      BBB+
KPCo                         Baa1       BBB      BBB+
OPCo                         A3         BBB      A-
PSO                          A3         BBB      A
SWEPCO                       A3         BBB      A
TCC                          Baa1       BBB      A
TNC                          A3         BBB      A




Current short-term ratings are as follows:

Company                      Moody's    S&P      Fitch

AEP                          P-3        A-2      F-2



The current ratings for senior unsecured debt are listed in the following table:

Company                      Moody's    S&P      Fitch

AEP                          Baa3       BBB      BBB
AEP Resources*               Baa3       BBB      BBB+
APCo                         Baa2       BBB      BBB+
CSPCo                        A3         BBB      A-
I&M                          Baa2       BBB      BBB
KPCo                         Baa2       BBB      BBB
OPCo                         A3         BBB      BBB+
PSO                          Baa1       BBB      A-
SWEPCO                       Baa1       BBB      A-
TCC                          Baa2       BBB      A-
TNC                          Baa1       BBB      A-

* The rating is for a series of senior notes issued with a Support Agreement
from AEP.

Liquidity

Liquidity, or access to cash, has become a more critical factor in determining
the financial stability of a company due to volatility in wholesale power
markets and the potential limitations that credit rating downgrades place on a
company's ability to raise capital. Management is committed to preserving an
adequate liquidity position and addressing AEP and its subsidiaries' financial
needs.

At March 31, 2003, we had an available liquidity position of $5.3 billion as
illustrated in the table below:

Credit Facilities
                       (in millions) Maturity
Commercial Paper Backup
  Lines of Credit          $2,500*       5/03
Commercial Paper Backup
  Lines of Credit           1,000        5/05
Euro Revolving Credit
  Facilities                  315       10/03
         Total              3,815

Cash Liquidity Reserves       300**
Additional Unrestricted
 Cash including Cash
 on Hand for
 Operational Needs          1,464**
Total Credit Facilities
  and Cash                  5,579

Less: Commercial Paper
        Outstanding           225
      Euro Revolving
        Credit Loans           16
Total Available Liquidity  $5,338

 * Contains one year term-out provision.
 ** These components comprise the Cash and Cash Equivalents balance on AEP's
Consolidated Balance Sheet at March 31, 2003.

The Ohio and Texas subsidiaries issued $2.025 billion of senior unsecured notes
in February 2003 with maturity dates ranging from 2005 to 2033. The commercial
paper balance outstanding decreased due to its repayment with proceeds from
these issuances.

At December 31, 2002, AEP also had a $1.725 billion bank facility maturing in
April 2003 that was available for debt refinancing with $1.3 billion
outstanding. With the issuance of the permanent financing for the Ohio and Texas
subsidiaries, mentioned above, this facility was repaid and cancelled in
February 2003.

AEP also maintains a minimum $300 million cash liquidity reserve fund to support
its marketing operations in the U.S. and keeps additional cash on hand as market
conditions change. At March 31, 2002, AEP had $1.8 billion of available cash.

In total, as shown in the table above, we had approximately $5.6 billion in
liquidity sources of which $5.3 billion were unused and available at March 31,
2003.

In April 2003, AEP's Board of Directors declared a common stock dividend of
$0.35 per share for the second quarter of 2003, which is a 42% decrease from the
previous quarter's dividend of $0.60 per share. This reduction will result in
annual cash savings of approximately $395 million (based on the outstanding
common shares at April 30, 2003).

Cash from operations and short-term borrowings provide working capital and meet
other short-term cash needs. We generally use short-term borrowings to fund
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. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored receivables purchase agreement and two revolving credit
agreements.

Cash flows from operating activities during the first quarter of 2003 were $775
million, including $335 million from depreciation, amortization, deferred income
taxes and deferred investment tax credits. This represents an increase of $795
million when compared to first quarter results of 2002, largely due to the
year-over-year increase in net income of $609 million ($440 million and $(169)
million in 2003 and 2002, respectively) and an increase in cash from working
capital items of $985 million ($376 million in 2003 and $(609) million in 2002).
The aforementioned increases were partially offset by a $(193) million
cumulative effect of accounting change in 2003 (see Note 3).

Cash flows used for investing activities during the first quarter of 2003 were
$289 million compared to $332 million during the first quarter of 2002. The
major reason for the year-over-year variance was proceeds of $35 million from
the sale of assets in 2003 (see Note 10). During the first quarter of 2003,
major construction expenditures continued for emission control technology at
several coal-fired generating plants (see Note 7).

Cash flows from financing activities in the first quarter of 2003 decreased by
$284 million when compared to the first quarter of 2002 ($65 million compared to
$349 million during 2003 and 2002, respectively), primarily as the result of
AEP's retirement and restructuring of its short-term and long-term debt during
2003. During the first quarter of 2003, AEP was able to retire $3,434 million of
debt ($2,925 million short-term and $509 million of long-term) and increase
available cash primarily through the issuance of long-term financing ($2,525
million), issuance of common stock ($1,177 million) and the generation of cash
from operating activities.

Total consolidated plant and property additions for the first quarter 2003 were
$324 million. The following table shows the plant and property additions by
certain registrant subsidiaries:

        Company                     Amount
                                (in millions)
        APCo                        $ 57
        I&M                           28
        OPCo                          56
        SWEPCo                        26
        TCC                           22


Financing Activity

Common Stock Offering
On February 27, 2003, AEP priced its offering of 50 million shares of common
stock at a public offering price of $20.95 per share. AEP granted the
underwriters an option to purchase an additional 7.5 million shares of common
stock to cover over allotments. The underwriters exercised their over allotment
option to purchase an additional 6 million shares. The net proceeds of
approximately $1.1 billion from the sale of these securities were used to reduce
debt and for other corporate purposes.

Debt
During March 2003, AEP completed an offering of 5.375% Series C Senior Notes
which have a principal amount of $500 million and a maturity date of March 15,
2010. The net proceeds of $494 million from the offering were used to repay or
redeem current maturities of long-term debt and for other corporate purposes.

In February 2003, CSPCo issued $250 million of unsecured senior notes due 2013
at a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. OPCo issued $250 million of unsecured senior notes due 2013 at
a coupon of 5.50% and $250 million of unsecured senior notes due 2033 at a
coupon of 6.60%. TCC issued $100 million of unsecured senior notes due 2005 at a
variable rate, $150 million of unsecured senior notes due 2005 at a coupon of
3.0%, $275 million of unsecured senior notes due 2013 at a coupon of 5.50% and
$275 million of unsecured senior notes due 2033 at a coupon of 6.65%. TNC issued
$225 million of unsecured senior notes due 2013 at a coupon of 5.50%. The
proceeds from the bond issuances were used to repay the bank facility due to
mature in April 2003, mentioned above, short-term debt and for other corporate
purposes.

During the first quarter of 2003, CSPCo retired $44 million of first mortgage
bonds due 2022 with rates ranging from 8.4% to 8.7%. SWEPCo and TCC retired $55
million and $16 million, respectively, of first mortgage bonds at maturity. TCC
also retired $32 million of securitization bonds due 2005.

In April 2003, SWEPCo issued $100 million of senior unsecured debt due 2015 at a
coupon of 5.375%.
<TABLE>
<CAPTION>
In April 2003, certain AEP subsidiaries called the following First Mortgage
Bonds (FMB) or Junior Subordinated Debentures (JSD) for early redemption on May
30, 2003:

                                     Coupon
        Subsidiary                           Type of         Or Stated           Call                                 Principal
        Company                               Debt             Rate              Rate           Due Date               Amounts
                                                                     %               %                               (in millions)
<S>                                                                 <C>            <C>                <C>                     <C>
        APCo                                   FMB                  8.50           100                2022                    $70
        APCo                                   FMB                  7.15           100                2023                     20
        APCo                                   FMB                  7.80           103.90             2023                     30
        CSPCo                                  FMB                  6.55           100                2004                     27
        CSPCo                                  FMB                  6.75           100                2004                     26
        CSPCo                                  FMB                  7.75           104.27             2023                     33
        CSPCo                                  FMB                  7.90           103.95             2023                     40
        I&M                                    FMB                  8.50           100                2022                     75
        I&M                                    FMB                  7.35           100                2023                     15
        I&M                                    JSD                  8.00           100                2026                     40
        I&M                                    JSD                  7.60           100                2038                    125
        KPCo                                   JSD                  8.72           100                2025                     40
</TABLE>
In May 2003, a third party exercised its option to call $250 million of 5.50%
putable callable notes, issued by AEP in May 2001, for purchase and remarketing.
Management is evaluating alternatives and plans to exchange the notes.

During May 2003, APCo issued $200 million of unsecured senior notes due 2008 at
a coupon of 3.60% and $200 million of unsecured senior notes due 2033 at a
coupon of 5.95%. The proceeds of these bond issuance will be used to redeem the
aforementioned early redemptions for APCo, a floating rate note due in August
2003 and for other corporate purposes.

Possible Divestitures

We have a strong commitment to continually evaluate the need to reallocate
resources to areas that effectively match investments with our strategy, provide
greater potential for financial returns, and to dispose of investments that no
longer meet these principles.

Assets we are seeking to divest consist of domestic and international
unregulated generation, gas pipelines, a coal business and a communications
business.

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. If we choose to
dispose of these assets, we may realize non-recurring losses in the aggregate
that could have a material impact on our results of operations.

Corporate Separation
As discussed in the 2002 Annual Report, we have filed with the FERC and SEC
seeking approval to separate our regulated and unregulated operations. With the
changes in AEP's business strategy in response to current energy market and
business conditions, management continues to evaluate corporate separation
plans, including determining whether legal corporate separation is appropriate.

RTO Formation
As discussed in the 2002 Annual Report, 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 the
subsidiaries' transmission systems to RTOs.

In 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. AEP
subsidiaries, which 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 based on
statutory or regulatory requirements in those states. Those proceedings remain
pending.

In February 2003, the Virginia Legislature enacted legislation, which the
Governor of Virginia signed, that prohibited the transfer of transmission assets
in its jurisdiction to an RTO, until at least July 2004. In April 2003, FERC
approved AEP's transfer of functional control of the AEP East companies'
transmission system to PJM. FERC also accepted AEP's proposed rates for joining
PJM, but set a number of rate issues for resolution through settlement
proceedings or FERC hearings.

AEP West companies are members of ERCOT or the SPP. In 2002, FERC conditionally
accepted filings related to a proposed consolidation of MISO and the SPP. AEP's
SPP companies are also regulated by state public utility commissions, and 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. Regulatory activities concerning various
RTO issues are ongoing in Arkansas and Louisiana.

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

ACCOUNTING POLICIES


Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - The consolidated financial statements of AEP and the
financial statements of electric operating subsidiary companies with cost-based
rate-regulated operations (I&M, KPCo, PSO, and a portion of APCo, CSPCo, OPCo,
SWEPCo, TCC and TNC) reflect the actions of regulators that can result in the
recognition of revenues and expenses in different time periods than enterprises
that are not rate regulated. In accordance with SFAS 71, regulatory assets
(deferred expenses to be recovered in the future) and regulatory liabilities
(deferred future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period and by matching income with its
passage to customers through regulated revenues in the same accounting period.
Regulatory liabilities are also recorded to provide for refunds to customers
that have not yet been made.

When regulatory assets are probable of recovery through regulated rates, 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 we determine 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.

Electric Generation - We record operating revenues from electric generation
activities using accrual, hedge and mark-to-market methods of accounting.

We use accrual accounting for electricity sales to residential, industrial and
institutional customers who have not signed a contract or have entered into
long-term power sales contracts that are not subject to mark-to-market
accounting. Under accrual accounting we record revenues when energy has been
delivered. All of the registrant subsidiaries except AEGCo are allocated a
portion of the revenues and costs associated with AEP's electric generation
activities that have been recognized on an accrual basis.

Some contracts for the sale of electricity at fixed prices for future delivery
are used to mitigate the risk associated with anticipated sales of electricity
from our generation assets and have been designated and accounted for as cash
flow hedges under SFAS 133. Prior to settlement, we record changes in the fair
value of contracts designated as cash flow hedges in the Consolidated Statements
of Common Shareholders' Equity as Accumulated Other Comprehensive Income (AOCI).
When the anticipated sale of electricity occurs, the settlement amount of the
cash flow hedge is recorded in revenues. See Derivatives below.

Revenues recognized under the mark-to-market method of accounting include
realized revenue on electricity contracts, net of related costs of sales, and
unrealized gains and losses on electricity contracts accounted for as
derivatives under SFAS 133. We also recognize revenues under the mark-to-market
method of accounting for non-derivative energy trading contracts as required by
EITF Issue No. 98-10. Beginning October 25, 2002 for new contracts and January
1, 2003 for pre-existing contracts, in accordance with a new accounting
pronouncement that is discussed further in Note 2, we discontinued the
mark-to-market method of accounting for all unsettled electricity contracts that
are not considered derivatives under SFAS 133. See Derivatives below. All of the
registrant subsidiaries except AEGCo are allocated a portion of the revenues and
costs associated with AEP's electric generation activities; however, PSO,
SWEPCo, TCC and TNC are only allocated a portion of the forward transactions
that are accounted for using the mark-to-market method of accounting. We defer,
as regulatory liabilities (unrealized gains) or regulatory assets (unrealized
losses), changes in the fair value of derivative contracts for the forward sale
and purchase of electricity in AEP's traditional marketing area to the extent
that a jurisdiction is regulated. AEP's traditional marketing area is up to two
transmission systems from the AEP service territory. For contracts which are
outside of AEP's traditional marketing area, the change in fair value is
included in nonoperating income on a net basis.

Electric Transmission and Distribution - Revenues from electricity transmission
and distribution services include realized revenue for electricity and delivery
services provided to residential, industrial and institutional customers. These
revenues are recognized when delivery services are provided.

Gas Sales, Pipeline and Storage Activities - Revenue from gas sales activities
includes realized revenue on contracts for the sale of gas, and unrealized gains
and losses on gas contracts accounted for as derivatives under SFAS 133. See
Derivatives below. Revenues from gas pipeline and storage services are
recognized when gas is delivered to contractual meter points or when services
are provided. Transportation and storage revenues also include the accrual of
earned, but unbilled and/or not yet metered gas.

Substantially all of the forward gas purchase and sale contracts (excluding
wellhead purchases of natural gas), swaps and options for the pipeline
operations, qualify as derivative financial instruments as defined by SFAS 133.
Accordingly, net gains and losses resulting from revaluation of these contracts
to fair value during the period are recognized currently in results of
operations and are appropriately discounted, net of applicable credit and
liquidity adjustments.

Derivatives - We use derivative instruments such as futures, swaps, forwards and
options to manage the commodity, currency exchange and financial market risks of
our business operations. We also manage a portfolio of commodity contracts held
for trading purposes as part of our strategy to market excess generation
capacity. All derivative instruments not qualifying for the normal purchase
normal sale exemption under SFAS 133 are recorded in the Consolidated Balance
Sheets as Risk Management Assets and Liabilities. On the date a derivative
instrument is entered into, we designate the derivative as either a normal
purchase or sale contract; as held for trading purposes (trading contract);
and/or a hedge of a forecasted transaction or future cash flows (cash flow
hedge).

Derivative instruments that provide for the purchase or sale of energy
commodities that will settle physically in the normal course of business qualify
for the normal purchase and sale exemption under SFAS 133. If the exemption has
been elected, no amount associated with these contracts is included in the
Consolidated Financial Statements until the commodity is actually delivered.

Derivative instruments used to mitigate the risks of variability in expected
cash flows attributable to a forecasted transaction are designated and accounted
for as cash flow hedges under SFAS 133. Cash flow hedges are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
unrealized gains and losses recorded on the Consolidated Statements of Common
Shareholders' Equity as AOCI until the hedged item affects earnings. We formally
document the hedging relationship at the inception of the cash flow hedge and
assess whether the hedging relationship is highly effective in achieving
offsetting cash flows on an ongoing basis. We discontinue hedge accounting
prospectively when the cash flow hedge is determined to be ineffective in
achieving offsetting cash flows of the hedged item or it is not probable that
the hedged transaction will occur. Settled amounts and ineffective portions of
cash flow hedges are removed from AOCI and recorded in the Consolidated
Statements of Operations in the same accounts as the hedged item. When hedge
accounting is discontinued because the derivative no longer qualifies as an
effective hedge, the derivative instrument will continue to be recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
subsequent changes in fair value recognized in the Consolidated Statements of
Operations.

Derivative instruments entered into for trading purposes are recorded at fair
value on the Consolidated Balance Sheets as either an asset or liability with
all realized and unrealized gains and losses presented on a net basis in the
Consolidated Statements of Operations.

Energy options, futures and swaps represent financial transactions with
unrealized gains and losses from changes in fair values reported net in
revenues. APCo, CSPCo, I&M, KPCo and OPCo also have financial transactions, but
record the unrealized gains and losses, as well as the net proceeds upon
settlement, in Nonoperating Income.

The fair values of derivative contracts are based on exchange prices and broker
quotes. We mark-to-market long-term derivative contracts based primarily on
valuation models that estimate future energy prices based on existing market and
broker quotes and supply and demand market data and assumptions. The fair values
determined are reduced by the appropriate valuation adjustments for items such
as discounting, liquidity and credit quality. Credit risk is the risk that the
counterparty to the contract will fail to perform or fail to pay amounts due.
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 contracts. We have
independent controls to evaluate the reasonableness of our valuation models.
However, energy markets, especially electricity markets, are imperfect and
volatile. Volatility in energy commodities markets affects the fair values of
all of our open trading and derivative contracts exposing us to market risk and
causing our results of operations to be subject to volatility. Unforeseen events
can and will cause reasonable price curves to differ from actual prices
throughout a contract's term and at the time contracts settle. Therefore, there
could be significant adverse or favorable effects on future results of
operations and cash flows if our current estimates of future market prices are
not representative of actual future market prices. Differences between actual
market prices in the future and our estimated future prices are more likely to
occur for long-term contracts.

See the "Quantitative and Qualitative Disclosures About Risk Management
Activities" section of this report for a discussion of the policies and
procedures used to manage our exposure to market and other risks from trading
activities.


New Accounting Pronouncements

See Note 2 for a discussion of significant accounting policies and new
accounting pronouncements.

OTHER MATTERS

Industry Restructuring
As discussed in the 2002 Annual Report, restructuring and customer choice were
effective in four of the eleven state retail jurisdictions in which the AEP
electric utility companies operate. Restructuring legislation provides for a
transition from cost-based rate regulation of bundled electric service to
customer choice and market pricing for the supply of electricity. The status of
our transition plans, regulatory issues and proceedings and accounting issues in
the state regulatory jurisdictions impacted by restructuring and customer choice
is presented in Note 6.

Nuclear Plant Outages - Affecting AEP, I&M and TCC

In April 2003, engineers at STP found a small quantity of powdery residue during
inspections conducted regularly as part of refueling outages. STP officials are
working closely with the NRC to safely return the unit to service. The NRC will
review any corrective action prior to its implementation and restart of the
unit.

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.

Management is unable to predict the length of time that the STP and Cook Plant
units may be unavailable or the costs of corrective actions at this time. Cook
Unit 2 was already planned for a refueling outage starting May 5. We have
commitments to provide power to customers during the outages. Therefore, we will
be subject to fluctuations in the market prices of electricity and purchased
replacement energy could be a significant cost.

Litigation
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo

As discussed in the 2002 Annual Report, AEPSC, APCo, CSPCo, I&M, and OPCo have
been involved in litigation since 1999 regarding generating plant emissions
under the Clean Air Act. Federal EPA and a number of states alleged APCo, CSPCo,
I&M, OPCo and eleven unaffiliated utilities made modifications to generating
units at coal-fired generating plants in violation of the Clean Air Act. Federal
EPA filed complaints against AEP subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred over a 20 year period.

Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
is unable to predict the timing of resolution of these matters due to the number
of alleged violations and the significant number of issues yet to be determined
by the Court. In the event the AEP System companies do not prevail, any capital
and operating costs of additional pollution control equipment that may be
required as well as any penalties imposed would adversely affect future results
of operations, cash flows and possibly financial condition unless such costs can
be recovered through regulated rates and market prices for electricity. See Note
7 for further discussion.

NOx Reductions - Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, SWEPCo and
TCC

Federal EPA issued a NOx Rule and adopted a revised rule (the Section 126 Rule)
under the Clean Air Act requiring substantial reductions in NOx emissions in a
number of eastern states, including certain states in which the AEP System's
generating plants are located. The compliance date for the rules is May 31,
2004.

The Texas Commission on Environmental Quality adopted rules requiring
significant reductions in NOx emissions from utility sources, including SWEPCo
and TCC. The compliance date is May 2003 for TCC and May 2005 for SWEPCo.

AEP is installing selective catalytic reduction (SCR) technology and non-SCR
technology to reduce NOx emissions on certain units to comply with these rules.

Our estimates indicate that compliance with the rules could result in required
capital expenditures in a range of approximately $1.3 billion to $1.7 billion
for the AEP System. The actual cost to comply could be significantly different
than the estimates depending upon the compliance alternatives selected to
achieve reductions in NOx emissions. Unless any capital or operating costs for
additional pollution control equipment are recovered from customers, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition. See Note 7 for further discussion.

Enron Bankruptcy -  Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

In 2002, certain subsidiaries of AEP filed claims in the bankruptcy proceeding
of the Enron Corporation and its subsidiaries which is pending in the U.S.
Bankruptcy Court for the Southern District of New York. At the date of Enron's
bankruptcy, AEP and its subsidiaries had open trading contracts and trading
accounts receivables and payables with Enron and various HPL related
contingencies and indemnities including issues related to the underground Bammel
gas storage facility and the cushion gas (or pad gas) required for its normal
operation.

Management believes that AEP entities have the right to utilize offsetting
receivables and payables and related collateral across various Enron entities by
offsetting trading payables owed to various Enron entities against trading
receivables due to us. Management believes we have legal defenses to any
challenge that may be made to the utilization of such offsets. An additional
expense of up to $110 million may be incurred without such offsets. At this time
management is unable to predict the ultimate resolution of these issues or their
impact on results of operations and cash flows. See Note 7 for further
discussion.

Bank of Montreal Claim - Affecting AEP

In March 2003, Bank of Montreal (BOM) terminated all natural gas trading
deals and has claimed approximately $25 million is owed to BOM by AEP which
BOM subsequently has changed to approximately $34 million.In April 2003, AEP
filed a lawsuit against BOM claiming BOM had acted contrary to industry
practice in calculating termination and liquidation amounts and that
BOM had acknowledged in March 2003 that it owed AEP approximately $68 million.
Alternatively, AEP is claiming that BOM owes approximately $45 million to AEP.
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 - Affecting AEP

In 2002, AEP filed its demand for arbitration with the American Arbitration
Association to initiate formal arbitration proceedings in a dispute with the
Williams Companies (Williams). The proceeding results from Williams' repudiation
of its obligations to provide physical power deliveries to AEP and Williams'
failure to provide the monetary security required for natural gas deliveries.
Although management is unable to predict the outcome of this matter, it is not
expected to have a material impact on results of operations, cash flows or
financial condition. See Note 7 for further discussion.

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

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.
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 conditions.

Energy Market Investigations  - Affecting AEP

As discussed in the 2002 Annual Report, the FERC, the California attorney
general, the PUCT, the SEC, the Department of Justice and the U.S. Commodity
Futures Trading Commission (CFTC) initiated investigations into whether any
entity, including Enron Corporation, manipulated short-term prices in electric
energy or natural gas markets, exercised undue influence over wholesale prices
or participated in fraudulent trading practices.

In March 2003, the SEC subpoenaed information from its August 2002 request for
us to voluntarily provide certain trading information. AEP and its subsidiaries
have and will continue to provide information to the FERC, the SEC, state
officials and the CFTC as required. See Note 7 for further discussion.

Shareholders' Litigation - Affecting AEP

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

California Lawsuit - Affecting AEP

In 2002, the Lieutenant Governor of California filed a lawsuit in California
Superior Court against forty energy companies, including AEP, and two publishing
companies alleging violations of California law through alleged fraudulent
reporting of false natural gas price and volume information with an intent to
affect the market price of natural gas and electricity. AEP intends to
vigorously defend against this action. See Note 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. Management is
reviewing this opinion and will evaluate AEP's options.

Other Litigation

AEP and its subsidiaries continue to be involved in certain other legal matters
discussed in the 2002 Annual Report.

Snohomish Settlement - Affecting AEP

In February 2003, AEP and the Public Utility District No. 1 of Snohomish County,
Washington (Snohomish) agreed to terminate their long-term contract signed in
January 2001. Snohomish also agreed to withdraw its complaint before the FERC
regarding this contract 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.

Other Management Matters - Affecting AEP

On April 9, 2003, Dr. E. Linn Draper Jr., AEP's chairman,
president and chief executive officer,  announced that he plans to retire in
2004.  AEP's board of directors will soon begin the process of identifying
Dr.  Draper's  successor.




<PAGE>




    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
  Affecting AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

Market Risks

As a major power producer and marketer of wholesale electricity and natural gas,
AEP has 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 AEP due to changes
in the underlying market prices or rates.

Policies and procedures have been established to identify, assess, and manage
market risk exposures in AEP's day to day operations. AEP's risk policies have
been reviewed with the Board of Directors, approved by a Risk Executive
Committee and administered by a Chief Risk Officer. The Risk Executive Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.

AEP has actively participated in the Committee of Chief Risk Officers (CCRO) to
develop standard disclosures for risk management activities around energy
trading contracts. The CCRO is composed of the chief risk officers of major
electricity and gas companies in the United States. Recently the CCRO adopted
disclosure standards for energy contracts to improve clarity, understanding and
consistency of information reported. Implementation of the new disclosures is
voluntary. AEP supports the work of the CCRO and has embraced the new
disclosures. The following tables provide information on AEP's risk management
activities.
<TABLE>
<CAPTION>

        Roll-Forward of MTM Risk Management Contract Net Assets

        This table provides detail on changes in AEP's MTM net asset or
        liability balance sheet position from one period to the next.



                                                                                      TABLE 1 Part I
                                                                       Roll-Forward of MTM Risk Management Contract Net
                                                                                         Assets
                                                                            Three Months Ended March 31, 2003


                                                                Domestic      Domestic                              AEP
        AEP Consolidated                                         Power          Gas           International     Consolidated
                                                                                          (in millions)
<S>                                                              <C>           <C>                   <C>             <C>
        Beginning Balance December 31, 2002                      $360          (155)                 45              250
        (Gain) Loss from Contracts  Realized/Settled
        During  the Period (a)                                    (89)          (23)                (22)            (134)
        Fair Value of New Contracts When  Entered
         Into During the Period (day one  gains) (b)
                                                                   -              -                   -                -
        Net Option Premiums Paid/(Received) (c)                    (2)           24                  (2)              20
        Change in Fair Value Due to Valuation  Methodology
        Changes                                                    -              1                   -                1
        Effect of 98-10 Rescission                                (19)            1                 (14)             (32)
        Changes in Fair Value of Risk Management
         Contracts (e)                                             27            24                 (28)      23
        Changes in Fair Value of Risk Management  Contracts
        Allocated to Regulated  Jurisdictions (d)
                                                                   17             -                   -                17

        Ending Balance March 31, 2003                             $294        $(128)               $(21)            $145


        Domestic Power                                          APCo           CSPCo             I&M               KPCO
                                                                                           (in thousands)
        Beginning Balance December 31, 2002                       $96,852       $65,117         $70,861           $24,998
        (Gain) Loss from Contracts  Realized/Settled During
        the Period (a)                                           (25,745)       (17,307)        (16,202)           (5,691)
        Fair Value of New Contracts When Entered  Into
         During the Period (day one
         gains) (b)                                                 -              -               -                 -
        Net Option Premiums Paid/(Received) (c)                     (466)          (274)           (293)             (106)
        Change in Fair Value Due to Valuation Methodology
         Changes                                                    -              -               -                 -
        Effect of 98-10 Rescission                                (4,664)        (3,135)         (4,861)           (1,744)
        Changes in Fair Value of Risk Management
         Contracts (e)                                            14,451          6,623            (296)             (163)
        Changes in Fair Value Risk Management  Contracts
        Allocated to Regulated  Jurisdictions (d)
                                                                   6,377           -               6,249             2,459

        Ending Balance March 31, 2003                            $ 86,805       $51,024          $55,458           $19,753


        Domestic Power                                           OPCo           PSO            SWEPCo              TCC
                                                                                           (in thousands)
        Beginning Balance December 31, 2002                     $ 94,106       $ 3,545           $ 4,050           $ 5,414
        (Gain) Loss from Contracts  Realized/Settled
         During  the Period (a)                                  (24,661)          220               (18)             (670)
        Fair Value of New Contracts When Entered  Into
        During the Period (day one                                  -             -                 -                 -
         gains) (b)
        Net Option Premiums Paid/(Received) (c)                     (363)         -                 -                 -
        Change in Fair Value Due to Valuation Methodology
         Changes                                                    -             -                 -                 -
        Effect of 98-10 Rescission                                (4,159)         -                  151               187
        Changes in Fair Value of Risk Management
         Contracts (e)                                            10,868          -                  595            (4,527)
        Changes in Fair Value of Risk Management  Contracts
        Allocated to Regulated  Jurisdictions (d)
                                                                   -              1,192              885               -

        Ending Balance March 31, 2003                            $ 75,791      $ 4,957           $ 5,663           $   404


        Domestic Power                                             TNC
                                                             (in thousands)
        Beginning Balance December 31, 2002                    $  2,043
        (Gain) Loss from Contracts Realized/Settled During
        the Period (a)                                              (41)
        Fair Value of New Contracts When Entered  Into
        During the Period (day one                                  -
         gains) (b)
        Net Option Premiums Paid/(Received) (c)                     -
        Change in Fair Value Due to Valuation Methodology
         Changes                                                    -
        Effect of 98-10 Rescission                                   20
        Changes in Fair Value of Risk Management
         Contracts (e)                                             (269)
        Changes in Fair Value of Risk Management  Contracts
        Allocated to Regulated  Jurisdictions (d)                  (298)

        Ending Balance March 31, 2003                           $ 1,455

        (a) "(Gain) Loss from Contracts Realized/Settled During the Period"
        include 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)"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.
        (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.
</TABLE>
<TABLE>
<CAPTION>



                                 TABLE 1 Part II
                     Detail on MTM Risk Management Contract
                                   Net Assets
                              As of March 31, 2003

                                                               Domestic      Domestic                            AEP
                                                                 Power         Gas        International      Consolidated
                                                                                         (in millions)
<S>                                                                <C>          <C>               <C>              <C>
        Current Assets                                             $ 473        $ 465             $ 157            $ 1,095
        Non Current Assets                                           426          285                57                768
        Total MTM Energy Assets                                    $ 899        $ 750             $ 214            $ 1,863

        Current Liabilities                                        $(367)       $(688)            $(183)           $(1,238)
        Non Current Liabilities                                     (238)        (190)              (52)              (480)
        Total MTM Risk Management Contract  Liabilities            $(605)       $(878)            $(235)           $(1,718)

        Total MTM Risk Management Contract Net  Assets             $ 294        $(128)            $ (21)               145
        Assets Held for Sale (Nordic)                                                                                   17
        Less Non-Trading Related Derivative  Liabilities
                                                                                                                       (56)
        Net Fair Value of Risk Management and  Derivative
        Contracts                                                                                                  $   106

</TABLE>
<TABLE>
<CAPTION>

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 AEP's total MTM asset
    or liability (external sources or  modeled internally)
o  The maturity, by year, of AEP's net assets/liabilities, giving an
    indication of when these MTM amounts will settle and generate cash

                                TABLE 2 Part I
                    Maturity and Source of Fair Value of MTM
                       Risk Management Contract Net Assets
                  Fair Value of Contracts as of March 31, 2003

                                             Remainder                                                                After
US POWER:                                        2003          2004         2005        2006         2007         2007     Total
                                                                                           (in millions)
<S>                                                 <C>        <C>         <C>         <C>          <C>          <C>       <C>
Prices Actively  Quoted - Exchange   Traded
Contracts                                           $ (5)      $(6)        $ (2)       $(2)         $ -          $ -       $(15)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                               52        58           21         14            7            -        152
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                                33        19           11         20           17           57        157

    Total                                           $ 80       $71         $ 30        $32          $24          $57       $294

U.S. GAS:
Prices    Actively    Quoted   -   Exchange
 Traded Contracts (a)                              $ (39)     $101         $ (6)       $(1)         $ -          $ -       $ 55
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                               41        -            -           -            -            -         41
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                              (193)      (41)          (4)         9            8           (3)      (224)

    Total                                          $(191)     $ 60         $(10)       $ 8          $ 8          $(3)     $(128)

International:
Prices Actively  Quoted - Exchange   Traded
Contracts (a)                                      $ (14)     $ (1)        $ -         $ -          $ -          $ -       $(15)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                              (12)        6           -          (1)           -            -         (7)
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                                (1)       -            -           -            1            1          1

    Total                                          $ (27)     $  5         $ -         $(1)         $ 1          $ 1       $(21)

AEP Consolidated:
Prices Actively  Quoted - Exchange   Traded
Contracts                                          $ (58)     $ 94         $ (8)       $(3)         $ -          $ -       $ 25
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                               81        64           21         13            7            -        186
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                              (161)      (22)           7         29           26           55        (66)

    Total                                          $(138)     $136         $ 20        $39          $33          $55       $145

APCo                                         Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                             $16,282   $16,967      $5,722      $4,278       $1,949       $  -      $45,198
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                               10,597     2,984       2,203       4,988        4,581        16,254    41,607
    Total
                                                    $26,879   $19,951      $7,925      $9,266       $6,530       $16,254   $86,805



CSPCo                                        Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $ 9,569    $ 9,974      $3,364      $2,514       $1,145       $ -       $26,566
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                               6,229      1,754       1,295       2,932        2,693        9,555     24,458

    Total                                          $15,798    $11,728      $4,659      $5,446       $3,838       $9,555    $51,024

I&M                                          Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $11,490    $10,513      $3,599      $2,690       $1,226       $  -      $29,518
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                               6,438      1,872       1,386       3,138        2,882        10,224    25,940

    Total                                          $17,928    $12,385      $4,985      $5,828       $4,108       $10,224   $55,458

KPCo                                         Remainder                                                        After
                                                 2003          2004         2005        2006         2007        2007      Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $3,705     $3,860       $1,302      $  974       $  443       $  -      $10,284
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                              2,411        679          502       1,135        1,043        3,699      9,469

    Total                                          $6,116     $4,539       $1,804      $2,109       $1,486       $3,699    $19,753

OPCo                                         Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $19,450    $15,232      $4,462      $3,336       $1,520       $  -      $44,000
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                               7,652      2,281       1,718       3,890        3,573        12,677    31,791

    Total                                          $27,102    $17,513      $6,180      $7,226       $5,093       $12,677   $75,791

PSO                                          Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                 (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $  943     $  928       $330        $247         $112         $ -       $2,560
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                                611        172        127         286          264          937       2,397

    Total                                          $1,554     $1,100       $457        $533         $376         $937      $4,957


SWEPCo                                       Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $1,077     $1,060       $377        $282         $128         $  -      $ 2,924
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                                698        196        145         328          302          1,070      2,739

    Total                                          $1,775     $1,256       $522        $610         $430         $1,070    $ 5,663

TCC                                          Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                          (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $ 77       $76          $27         $20          $ 9          $ -         $209
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                               50        14           10          23           22           76          195

    Total                                          $127       $90          $37         $43          $31          $76         $404

TNC                                          Remainder                                                            After
                                                 2003          2004         2005        2006         2007         2007     Total
                                                                                 (in thousands)
Prices  Provided by Other External  Sources
- OTC Broker Quotes (a)                            $277       $272         $ 97        $ 72         $ 33         $ -       $  751
Prices    Based   on   Models   and   Other
 Valuation Methods (b)                              179         51           37          85            77         275         704

    Total                                          $456       $323         $134        $157         $ 110        $275      $1,455


(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.
</TABLE>
<TABLE>
<CAPTION>

The determination of the point at which a market is no longer liquid for placing
it in the Modeled category in Table 2 Part I varies by market. Table 2 Part II
reports an estimate of the maximum tenors of the liquid portion of each energy
market used to complete Table 2 Part I.

                                 Table 2 Part II
                               Maximum Domestic Tenor of the Liquid Portion of Risk Management Contracts
                              As of March 31, 2003
                                                                                                              TENOR
        <C>                                                                                                     <S>
                                                                                                           (in months)
        Natural Gas         Forward Purchase and Sales
                                                                 NYMEX Henry Hub Gas                              72
                                                                 Gas East - Northeast, Mid-continent
                                                                 Gulf Coast, Texas                                12

                                                                 Gas West - Permian Basin, San Juan,
                                                                 Rocky Mtns, Kern, Cdn Border(Sumas),
                                                                 Malin, PGE Citygate, AECO                        12

        Power (Peak)        Over the Counter Options
                                                                 Power East - Cinergy                             33
                                                                 Power East - PJM                                 33
                                                                 Power East - First Energy                        21
                                                                 Power East - NEPOOL                              21
                                                                 Power East - ERCOT                               21
                                                                 Power East - TVA                                  9
                                                                 Power East - Com Ed                               9
                                                                 Power East - Entergy                             33
                                                                 Power West - PV, NP15,SP15,MidC,Mead             57
                            Peak Power Volatility     (Options)  ECAR, MidCon, NYPP, PJM, West Ercot
                                                                 NEPOOL                                           21
                            OffPeak Power Volatility             All Regions                                       0

        Natural Gas
         Liquids                                                                                                  14

        Emissions                                                                                                 33

        Coal                                                                                                      33

</TABLE>

Cash Flow Hedges Included in Accumulated Other Comprehensive
  Income on the Balance Sheet

AEP employs 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. AEP does not hedge all interest rate risk.

AEP employs 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. AEP does not hedge all
foreign currency exposure.

Table 3 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 AEP has in place. (However, given that under SFAS 133 not all hedges are
recorded in AOCI, the table does not provide an all-encompassing picture of
AEP's hedges). The table further indicates what portions of these hedges are
expected to roll off into the income statement 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).
<TABLE>
<CAPTION>

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 3
                   Cash Flow Hedges included in Accumulated Other Comprehensive Income
                           On the Balance Sheet as of March 31, 2003

                                                                                             Portion Expected to
                                                                   Accumulated Other         Be Reclassified to
                                                                 Comprehensive Income        Earnings During the
                                                                (Loss) After Tax
(a) Next 12 Months (b)
        AEP Consolidated                                                               (in millions)
<S>                                                                         <C>                      <C>
        Domestic Power                                                      $(43)                    $(31)
        Domestic Gas                                                           8                       (3)
        Foreign Currency                                                       2                        2
        Interest Rate                                                         (5)                       1

        Total AEP                                                           $(38)                    $(31)

</TABLE>
<TABLE>
<CAPTION>



                                       Total Other Comprehensive Income Activity
                                               Three Months Ended March 31, 2003

                                                      Domestic       Domestic        Foreign                             AEP
                                                        Power          Gas          Currency        Interest Rate    Consolidated
                                                                                             (in millions)
<S>                                                        <C>         <C>             <C>               <C>              <C>
        Accumulated OCI, December 31, 2002                  $ (1)       $ -             $(3)              $(12)            $(16)
        Changes in Fair Value (c)                            (65)         8               5                  6              (46)
        Reclassifications from OCI to Net
         Income (d)                                           23          -              -                   1               24
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003                                      $(43)       $ 8             $ 2               $ (5)            $(38)
</TABLE>
<TABLE>
<CAPTION>

        APCo                                          Domestic            Foreign                                   AEP
                                                        Power             Currency          Interest Rate       Consolidated
                                                                                           (in thousands)
<S>                                                    <C>                 <C>                   <C>                  <C>
        Accumulated OCI, December 31, 2002              $   (394)           $(190)                $(1,336)             $(1,920)
        Changes in Fair Value (c)                        (19,201)             -                      (104)          (19,305)
        Reclassifications from OCI to Net
         Income (d)                                        6,649                2                     136                6,787
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003                                  $(12,946)           $(188)                $(1,304)            $(14,438)

        CSPCo                                         Domestic
                                                        Power
                                                       (in thousands)
        Accumulated OCI, December 31, 2002               $  (267)
        Changes in Fair Value (c)                        (11,251)
        Reclassifications from OCI to Net
         Income (d)                                        3,908
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003                                   $(7,610)

        I&M                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002               $  (286)
        Changes in Fair Value (c)                        (12,039)
        Reclassifications from OCI to Net
         Income (d)                                        4,182
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003                                   $(8,143)



        KPCo                                          Domestic                                KPCo
                                                        Power          Interest Rate       Consolidated
                                                                            (in thousands)
        Accumulated OCI, December 31, 2002               $  (103)               $425              $   322
        Changes in Fair Value (c)                         (4,357)                (43)              (4,400)
        Reclassifications from OCI to Net
         Income (d)                                        1,513                  22                1,535
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003                                   $(2,947)               $404              $(2,543)


        OPCo                                          Domestic          Foreign              OPCo
                                                        Power           Currency         Consolidated
                                                                        (in thousands)
        Accumulated OCI, December 31, 2002              $   (354)          $(384)              $   (738)
        Changes in Fair Value (c)                        (14,928)             -                 (14,928)
        Reclassifications from OCI to Net
         Income (d)                                        5,185               3                  5,188
        Accumulated OCI Derivative Gain  (Loss)
        March 31, 2003                                  $(10,097)          $(381)              $(10,478)

        PSO                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (42)
        Changes in Fair Value (c)                         (1,833)
        Reclassifications from OCI to Net
         Income (d)                                          636
        Accumulated OCI Derivative Gain (Loss) March
        31, 2003                                          $(1,239)


        SWEPCo                                        Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (48)
        Changes in Fair Value (c)                         (2,094)
        Reclassifications from OCI to Net
         Income (d)                                          727
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003                                   $(1,415)

        TCC                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (36)
        Changes in Fair Value (c)                         (1,559)
        Reclassifications from OCI to Net
         Income (d)                                          541
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003                                   $(1,054)



        TNC                                           Domestic
                                                        Power
                                                        (in thousands)
        Accumulated OCI, December 31, 2002                $  (15)
        Changes in Fair Value (c)                           (645)
        Reclassifications from OCI to Net
         Income (d)                                          224
        Accumulated OCI Derivative Gain (Loss)
        March 31, 2003                                   $  (436)


(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 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.
(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.
</TABLE>

Credit Risk

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

AEP has risk management contracts with numerous counterparties. Since AEP's open
risk management contracts are valued based on changes in market prices of the
related commodities, AEP's exposures change daily. AEP believes that credit and
market exposures with any one counterparty is not material to AEP's financial
condition at March 31, 2003. At March 31, 2003 approximately 6% of AEP's
exposure was below investment grade as expressed in terms of net MTM assets. Net
MTM assets represents the aggregate difference between the forward market price
for the remaining term of the contract and the contractual price per
counterparty. As of March 31, 2003 the following table approximates counterparty
credit quality and exposure for AEP based on netting across AEP entities,
commodities and instruments:

                                     TABLE 4
                         Futures,
                         Forward and
     Counterparty        Swap
     Credit Quality:     Contracts    Options                    Total

                                      (in millions)
     AAA/Exchanges        $      12             $33      $     45
     AA                         302              19           321
     A                          338              17           355
     BBB                        515             161           676
     Below
       Investment
       Grade                     77              11            88

       Total                $ 1,244            $241        $1,485


The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

Merchant Plant Owned Assets Production and Hedging Information

Table 5 provides information on the proportion of output of AEP's generation
facilities (based on economic availability projections) economically hedged.
This information is forward-looking and provided on a prospective basis through
December 31, 2005. Please note that this table is point-in time estimates,
subject to changes in market conditions and AEP decisions on how to manage
operations and risk.

                                     TABLE 5

                 Merchant Plant-Owned Assets Hedging Information
                           Estimated Next Three Years
                              As of March 31, 2003

                                              2003       2004        2005
        Estimated Plant Output Hedged (a)       93%         88%          83%

(a)       Estimated Plant Output Hedged - Represents the portion of
          megawatt-hours of future generation production for which AEP has sales
          commitments to customers.

VaR Associated with Energy Trading Contracts

AEP uses a risk measurement model which calculates Value at Risk (VaR) to
measure AEP's commodity price risk in the Energy Trading portfolio. The VaR is
based on the variance - covariance method using historical prices to estimate
volatilities and correlations and assumes 95% confidence level, a one-day
holding period and a one-tailed distribution. Based on this VaR analysis, at
March 31, 2003 a near term typical change in commodity prices is not expected to
have a material effect on AEP's results of operations, cash flows or financial
condition. The following table shows the end, high, average, and low market risk
as measured by VaR for quarter ended and year-to-date:

                         AEP VaR Model

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

AEP       $7  $19    $ 7   $5       $5   $24    $12   $4

APCo       1    3      2    1        1     4      1    -
CSPCo      1    2      1    1        1     3      1    -
I&M        1    2      1    1        1     3      1    -
KPCo       -    1      -    -        -     1      -    -
OPCo       1    2      1    1        1     4      1    -
PSO        -    -      -    -        -     -      -    -
SWEPCo     -    -      -    -        -     -      -    -
TCC        -    -      -    -        -     -      -    -
TNC        -    -      -    -        -     -      -    -

The High VaR for the first quarter 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 quarter.

The AEP VaR model results are adjusted using standard statistical treatments to
calculate the Committee of Chief Risk Officers (CCRO) VaR reporting metrics
listed below. The adjustments are made to take the AEP model results from a
one-day holding period to the ten-day holding period, from a one-tailed result
to a two-tailed result and from the 95% confidence level to the 99% confidence
level. The AEP VaR model's performance has not been evaluated for its accuracy
at calculating VaR using the CCRO VaR Metrics assumptions.
<TABLE>
<CAPTION>

               Committee of Chief Risk Officers (CCRO) VaR Metrics
                                                                     Average
                                                 End of Q1 2003     for Q1 2003       High for Q1 2003         Low for Q1 2003
                                                                                      (in millions)
 <S>                                                      <C>                <C>                  <C>                    <C>
        95% Confidence Level, Ten-Day
          Holding Period, Two-Tailed                     $26                $28                  $71                    $17

        99% Confidence Level, One-Day
          Holding Period, Two-Tailed                     $11                $12                  $30                    $ 7
</TABLE>


AEP utilizes 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, a one year holding period and a one-tailed distribution. The
volatilities and correlations were based on three years of daily prices. The
risk of potential loss in fair value attributable to AEP's exposure to interest
rates, primarily related to long-term debt with fixed interest rates, was $1,047
million at March 31, 2003 and $527 million at December 31, 2002. AEP would not
expect to liquidate its entire debt portfolio in a one year holding period,
therefore a near term change in interest rates should not materially affect
results of operations or consolidated financial position.

AEGCo is not exposed to risk from changes in interest rates on short-term and
long-term borrowings used to finance operations since financing costs are
recovered through the unit power agreements.

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

AEP employs 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. AEP engages in risk management of
electricity, gas and to a lesser degree other commodities and as a result AEP is
subject to price risk. The amount of risk taken by the staff is controlled by
risk management operations and AEP's Chief Risk Officer and his staff. When the
risk from energy trading activities exceeds certain pre-determined limits, the
positions are modified or hedged to reduce the risk to be within the limits
unless specifically approved by the Risk Executive Committee.






<PAGE>




                             CONTROLS AND PROCEDURES

(a)              Evaluation of disclosure controls and procedures. Our chief
                 executive officer and our chief financial officer, after
                 evaluating the effectiveness of "disclosure controls and
                 procedures" (as defined in the Securities Exchange Act of 1934
                 Rules 13a-14(c) and 15d-14(c)) as of a date (the "Evaluation
                 Date") within 90 days before the filing date of this quarterly
                 report, have concluded that as of the Evaluation Date, our
                 disclosure controls and procedures were adequate and designed
                 to ensure that material information relating to us and our
                 consolidated subsidiaries would be made known to them by others
                 within those entities.

(b)              Changes in internal controls. There were no significant changes
                 in our internal controls or to our knowledge, in other factors
                 that could significantly affect our disclosure controls and
                 procedures subsequent to the Evaluation Date.








<PAGE>





PART II.  OTHER INFORMATION

Item 5.  Other Information.

                NONE

Item 6.  Exhibits and Reports on Form 8-K.

    (a) Exhibits:

        AEP, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

               Exhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.

        AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC

               Exhibit 99.1 - Certification of Chief Executive Officer Pursuant
               to Section 1350 of Chapter 63 of Title 18 of the United States
               Code.

               Exhibit 99.2 - Certification of Chief Financial Officer Pursuant
               to Section 1350 of Chapter 63 of Title 18 of the United States
               Code.

    (b) Reports on Form 8-K:

        AEGCo, APCo, I&M, KPCo, PSO, SWEPCo, TCC and TNC

        The following reports on Form 8-K were filed during the quarter ended
March 31, 2003.

        Company Reporting   Date of Report       Item Reported
               AEP             February 25, 2003    Item 5. Other Events and
                                               Regulation FD Disclosure
                                             Item 7. Financial Statements
                                              and Exhibits
               AEP             February 26, 2003    Item 7. Financial Statements
                                              And Exhibits
                                             Item 9. Regulation FD
                                              Disclosure
               AEP             February 27, 2003    Item 5. Other Events and
                                              Regulation FD Disclosure
                                             Item 7. Financial Statements
                                              And Exhibits
               AEP             March 14, 2003       Item 5. Other Events and
                                               Regulation FD Disclosures
                                             Item 7. Financial Statements
                                               And Exhibits
               CSPCo and OPCo  February 4, 2003     Item 5. Other Events and
                                               Regulation FD Disclosure



<PAGE>




                                   Signatures




        Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.

                                        AMERICAN ELECTRIC POWER COMPANY, INC.



        By: /s/Geoffrey S. Chatas           By:  /s/Joseph M. Buonaiuto
                Geoffrey S. Chatas              Joseph M. Buonaiuto
                Treasurer               Controller and Chief Accounting Officer



                             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




        By: /s/Geoffrey S. Chatas           By:  /s/Joseph M. Buonaiuto
                Geoffrey S. Chatas              Joseph M. Buonaiuto
                Treasurer               Controller and Chief Accounting Officer



Date: May 14, 2003


<PAGE>




                                 CERTIFICATIONS

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

1. I have reviewed this quarterly report on Form 10-Q of:

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

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

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

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

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

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

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

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

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

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

6.

<PAGE>


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


Dated: May 14, 2003                  By:    /s/  E. Linn Draper, Jr.
                                                 E. Linn Draper, Jr.
                                                 Chief Executive Officer


<PAGE>


I, Susan Tomasky, certify that:

1. I have reviewed this quarterly report on Form 10-Q of:

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

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

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

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

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

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

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

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

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

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

6.

<PAGE>


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


Dated: May 14, 2003                  By:    /s/  Susan Tomasky
                                                 Susan Tomasky
                                                 Chief Financial Officer